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ARC-FLASH

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ARC-FLASH HANDBOOK

SERIES III

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ARC-FLASH HANDBOOK

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ARC-FLASH HANDBOOK TABLE OF CONTENTS Verify Performance and Safety of Arc-Flash Detection Systems................................. 5 William Knapek and Mark Zeller

Electrical Safety – A Program Development Guide............................................... 10 Terry Becker

Low-Voltage Metal Enclosed Bus Duct Wetting Events............................................ 18 Dan Hook

Arc-Flash Hazard Mitigation by Transformer Differential Relay Protection................ 24 Randall Sagan and Mose Ramieh III

Safety Aspects of Breaker Protection and Coordination......................................... 29 Bruce M. Rockwell

Arc-Flash Mitigation Using Differential Protection................................................. 32 Brian Cronin

Metal Enclosed Medium-Voltage Air Switches: .................................................... 36 Condition Analysis and Hazard Awareness Scott Blizard and Paul Chamberlain

Electrical Hazard Facts.................................................................................... 38 James R. White

Make Your Electrical Safety Program Your Own, Part One: Why Won’t a Generic Program Work?................................................ 43 Don Brown

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InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

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Make Your Electrical Safety Program Your Own, Part Two: What Should be in an Electrical Safety Program?.................................. 45

Don Brown

Make Your Electrical Safety Program Your Own, Part Three: Implementation of an Electrical Safety Program................................... 48 Don Brown

Arc-Flash Analysis is Going Global.................................................................... 50 Lynn Hamrick

Arc-Rated Clothing and Electrical Hazard Footwear............................................. 53 Paul Chamberlain

Methods to Limit Arc-Flash Exposure on Low-Voltage Systems................................. 55 Scott Blizard

Why Do a Risk Assessment?............................................................................. 57 James R.White

Do I Need to Wear Arc-Rated PPE When Working Around Energized Equipment?.......................................................................... 60 Ron Widup and James R.White

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InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

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Published by InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Arc-Flash

VERIFY PERFORMANCE AND SAFETY OF ARC-FLASH DETECTION SYSTEMS PowerTest 2014 William Knapek, OMICRON Electronics Corp. Mark Zeller, Schweitzer Engineering Laboratories, Inc.

ARC-FLASH HISTORY Protecting workers from electrical hazards is not a novel idea. Since the first power generating station was built in 1877, the benefits and hazards of electricity have been recognized. The top engineers in the power industry have continuously worked to make electric power more economical and reliable, as well as safer. There have been many papers highlighting the hazards and possible prevention of electrical arc flash; a new focus was initiated in 1985, when Ralph Lee published the paper “The Other Electrical Hazard: Electric Arc-Blast Burns.” The National Fire Protection Association (NFPA) published NFPA 70E®: Standard for Electrical Safety in the Workplace® to document electrical safety requirements.1 It defines specific rules for determining the category of electrical hazards and the personal protective equipment (PPE) required for personnel in the defined and marked hazard zones. The United States Occupational Safety and Health Administration enforces the NFPA arc-flash requirements under its general rule that a safe workplace must be maintained. These regulations are forcing employers to review and modify their electrical systems and work procedures to reduce arc-flash hazards. IEEE 1584-2002 provides information on how to calculate arc energy and establish boundary distances for personnel when working around energized electrical equipment. IEEE 1584 provides an incident energy2 calculation method using the following formula: where:

E = 4.184 (Cf ) (En)

(1)

E is the incident energy in joules/cm2. Cf is a calculation factor (1.0 for voltages above 1 kV, and 1.5 for voltages below 1 kV). En is the normalized incident energy. t is the arc duration in seconds. D is the distance from the arc in millimeters. x is the distance exponent. As shown by (1), the energy produced by an arc-flash event is proportional to the voltage, current, and duration of the event (V • I • t). IEEE 1584-2002 concluded that arc time has a direct effect on incident energy. Therefore, reducing fault-clearing times proportionately reduces arc-flash hazards.

There are several key elements in clearing an electrical arc. The first step is detecting the flash, second is accurately determining if the flash is part of an electrical fault, third is signaling the circuit interrupting breaker, and the last is interrupting the current flow to the fault. Each step in the process contributes time to the overall time needed to clear the fault; therefore, a significant amount of research has been invested in each part. Many of the safe work practices, personal protective equipment, approach boundaries, and warning labels are dependent on the protection system that is in place to perform at the speed and sensitivity specified by the equipment manufacturer. A performance (by any of the components) that is slower than specified can dramatically increase the available incident energy. Personnel protection and procedures are based on properly working and performing equipment. Until recently, no proper test system was in place to evaluate the arc-flash detection equipment performance. Users are now able to verify not just the performance of the arc-detection equipment but also the system as a whole by including the breaker in the commissioning circuit. Although this paper only evaluates arc-flash detection systems, it is a straightforward extrapolation to include feeder and main breakers as well as communications links in the system while commissioning the arc-detection system.

TYPES OF ARC-FLASH DETECTION SYSTEMS Arc-hazard detection systems have been evaluated that are triggered from sound, pressure, current, and light, as well as predictive systems based on ion detection or thermal imaging. This paper focuses on arc-flash detection methods and leaves the predictive methodologies to present their own merits. Although an arc blast contains considerable sound and pressure waves, in the race to fastest detection, these waves are much slower than light. The fastest detection systems on the market today all use light as the primary arc-detection medium. They include the following: ●● Light detection ●● Current detection ●● Combined light and current detection Light detection systems have been commercially available for many years and have proven to be reliable and effective. Arc-flash

6

Arc-Flash

safety considerations over the last few years have elevated an interest in detecting and interrupting arc-flash incidents faster and with high security. Table I provides a general range of response times published by arc-flash detection system manufacturers. Table 1: Detection Technology in Arc-Detection Systems Detection Technology

Published Response Time

Light only

1 to 7 ms

Current only, instantaneous

24 ms

Light with current supervision

1 to 7 ms

Light and overcurrent

1 to 3 ms

Light-Only Detection Systems Light detection systems are based on the principle that during an arc-flash event, enough light will be detected by the receptor to indicate a flash. This is generally accepted as a sound principle because the amount of light given off during an arc flash is significant and contains nearly the entire light spectrum. Light is fast and relatively easy to detect.3 Generally, there are two types of light detectors. The first is a remote-mounted receiver that converts the light given off by the flash to some other form of signal that is transmitted to the tripping device. This type of sensor often uses a copper conductor for the transmission signal carrier, as shown in Fig. 1. Copper wire is common, reliable, and flexible but also has the capability to carry current in the event of contact with the bus bars or other current-carrying conductors. The second type of detector acts as a lens to collect the light produced from the flash and channel it back to a receptor in the tripping device. This channeling of the light is accomplished through fiber-optic cables (see Fig.  2). Fiber-optic cables have the advantage of not conducting electricity, thereby avoiding the installation of a conductor in the electrical gear. Fiber optic also has the advantages of electrical isolation between the receptor and the tripping device, easy installation, online complete functional testing, and choice of sensors. The disadvantages of fiber-optic cables include that they are easy to damage during installation, with either a too-tight bending radius or scarring of the fiber wall, and the possible need for special splicing tools.

Fig. 2: Fiber-optic cable and arc-flash point sensor The main disadvantage of a light-only detection system is the risk of tripping from a light source not related to an arc flash. These sources include arc-welding reflections, camera flashes, spotlights, and even light fixture failures. Any source of light exceeding the detection level in the relay will initiate a trip. Because of the very highspeed trip times of light-only systems, security is a serious concern.

Over-Current Only Detection Systems Over-current only detection schemes, although not intended specifically for this purpose, were the first arc-flash detection systems invented. Generally, they were built to protect the equipment, not the people in the area. Because they were initially installed for equipment protection, settings were normally chosen based on equipment damage, not personnel safety. As personnel safety has become a higher priority, the trip settings have been modified to provide separate levels of protection for equipment and personnel. A common practice today is to implement a maintenance switch (Fig.  3) that changes the protection settings in a relay from time-coordinated protection (equipment-level protection) to instantaneous (personnel-level protection) settings while people are working in or around the energized equipment. Although instantaneous settings can reduce the arc-flash hazard under some conditions, they can also create hazards if misapplied.

Fig. 3: Breaker control with maintenance switch

Fig. 1: Arc-flash sensor with copper wires

IEEE defines an instantaneous setting as having no intentional delay in the output.4 Notice, however, that this does not specify how fast a trip element needs to respond in order to qualify as instantaneous. This allows for significant variation in the response times of instantaneous elements between manufacturers and even from model to model of protective relays. All instantaneous trip elements are not created equal. Instantaneous trip response times are dependent on the magnitude and duration of the overcurrent. Internal

7

Arc-Flash signal filtering and the speed of the processing logic within the relay result in variations in instantaneous responses. Historic testing has found that traditional instantaneous elements have a pickup time of two cycles. When protection engineers build protective relays, they must balance the often competing characteristics of sensitivity and security. For a protective relay, security is defined as the ability to trip when needed and not trip when not needed. Although this is a simplistic definition of security, differentiating between an overcurrent signal and noise on the input channel must be carefully considered. Protective relay manufacturers have a detailed understanding of current transformer signal variation and the effects of saturation on the current signal; this may not be true of all manufacturers of arc-flash detecting devices. Therefore, when selecting a relay to be used for arc-flash hazard mitigation, carefully evaluate each manufacturer for experience, speed, sensitivity, and security. One challenge of a current-only detection system is selecting the proper trip settings. The settings must be high enough to ignore normal variation in current, yet low enough to quickly detect an event. Instantaneous settings that are too high endanger personnel and provide a false sense of safety. For example, by changing the settings on a feeder relay from the time-coordinated delay of 0.5 seconds to an instantaneous setting of 0.12 seconds, you could assume the arc-hazard energy dropped from 29 cal/cm2 to 4.5 cal/cm2 .5 This assumes that the current remains at the calculated available fault current. If the fault current is reduced (because of higher-than-expected impedance) to below the instantaneous setting, the relay would not trip on the instantaneous element. In that case, even with a lower fault current, the available arc-flash energy would be higher than the previously calculated level and personnel working in PPE rated for the lower hazard would be in jeopardy. A second issue with this method is determining the trip time to use in the incident energy calculations. Since the trip time varies with the magnitude of the fault, the protection engineer is left without fixed time duration to use for incident energy, approach boundary conditions, safety procedures and personal protective equipment.

Light With Current Supervision Systems Any arc-detection scheme that only evaluates a single quantity has serious security concerns. One security improvement is to supervise the light detection with a current element. This system measures the current and only enables the light detection trip element if the current is above some predetermined level. This application does not monitor for a fault current; it only disables the light trip element when the current is below a preset point. Supervision systems typically recommend current enable levels just below the expected normal operating load. Setting the supervision level too high disables the light portion of the arc detection. Setting it too low removes the security benefit of current monitoring. Current supervision systems only provide a modest improvement in security during low-current conditions.

Light and Overcurrent Detection Systems Modern protection systems make full use of both overcurrent and light detection to create a scheme that is both fast and secure. Combining fault current detection AND logic manner with the light detection element, tripping only when both are present, create a very secure scheme. One of the challenges of combining the two elements is to make sure the fault detection element for the current is as fast as the light detection element. This is accomplished by using special high-speed sampling and logic to match the response times of both elements with no delay. Although there is some reduced security with the faster current detection element, the combination of overcurrent and light detection more than compensates for any sacrifice in the current security.

Consequences of Misoperation The consequences of misoperation of the arc-flash detection scheme depend on the process and arc-suppression system. When isolating the fault with a standard circuit breaker, the result of a false trip (tripping when no fault is present) can be evaluated based on the consequences of the load lost. Failure of the system to trip when a fault is present will result in normal circuit protection with the associated incident energy. If personnel working in an area with PPE expect high-speed arc detection and the system responds with slower overcurrent protection, serious injury may result. Therefore, it is imperative that the system is reliable and tested often. Self-checking systems can increase confidence and provide warning in the event of a failure before personnel enter the risk zone. Modern arc-flash systems continuously test not just the relay, but the continuity and function of the sensors as well. Some systems, rather than just isolating the faulted circuit, also provide an alternate path to ground for the fault circuit. These systems use a crowbar circuit or an arc-containment system to redirect the current. In addition to the concerns previously stated, a false trip (tripping when no fault exists) creates a strain on all the equipment in the system. Fault current, although not from a fault, is created by the system itself as it attempts to divert the system current to ground while isolating the presumed circuit.

TESTING PROCEDURES Arc-flash detection systems were tested in the configurations designated in the respective manufacturer instruction manuals. The testing was executed with the same test system and used a single arc-flash test device to generate the flash. The block diagram of the testing setup is shown in Fig. 4. The purpose of the tests was to demonstrate the performance of each type of arc-flash detection system. Testing included subjecting the systems to a light flash, an overcurrent surge, and a combination of both light and overcurrent.

8

Arc-Flash

IRIG Clock for Synchronization

Multifunction Relay Test Device

Current to Relay Trip Outputs From Relay

Arc-Flash Relay

Synchronized IRIG Flash

Flash Test Device

Arc Flash

ArcDetection Unit

Fig. 4: Test system block diagram In setting up the tests a multifunction test set was used that provided current output, IRIG-B synchronization, high speed binary/analog inputs to measure the contact response time, and binary outputs to control the IRIG-B signal to the flash. The test set also provided a DC power supply to the relays that needed power. A single-phase test set, current output, was connected to the current input of the relay. The high-speed output contact of the relay was connected to the test set. The high-speed outputs required a wetting voltage and a load so a DC relay was used as the load and 110vdc was applied. This required that the test set inputs be configured to trigger on a wetted contact.

Fig. 5: Typical test screen showing fault initiation and time to trip One of the variables in setting up the testing procedure was the use of analog adjustment knobs (shown in Fig. 6) on some of the arc-flash detection systems. Modern relays avoid this subjectivity by using digital settings to exactly program the sensitivity. The adjustment knobs on some of the systems made the sensitivity setting inexact and nonrepeatable.

The tests were set up using a state sequencer program; prefault, fault, and post-fault states were used. The flash was synchronized so that it was applied with the current at the start of the fault state. A current value above the pickup level was used in the tests that evaluated current supervision. After the first tests, it was found that the flash generator would flash with each IRIG pulse. This led to misoperations, so a binary output contact from the test set was inserted in the IRIG signal to the flash generator. This caused a delay in the activation of the flash generator, so a two-pulse delay state was inserted before the fault state. The first test performed was an overcurrent surge test or normal overcurrent event. This test included a prefault state, a IRIG-B starting state, a fault state that included the fault current and a post fault state for timing purposes. This test did not produce a flash when the current was applied. The second test was a flash without current. In this test sequence, the same set up was used but no current was applied to the relay. The third test performed was a flash and overcurrent fault applied to the relay using the same test sequences. Finally, a test was performed with nominal load current, one amp secondary, and a flash to confirm the security of the relay with current supervision. This setup was used for all the relays in the study. The timing was evaluated using the time signal view of the test set software. The beginning of the IRIG pulse to the initiation of the output contact was measured, and the results are shown in Fig. 5 and in Table 2 (later in this paper).

Fig. 6: Arc protection analog setting knob

TESTING RESULTS The response times from the tests are shown in Table 2. Overall, the systems tested matched the actual performance with published specifications from the manufacturers. Each system was tested for possible false trips by subjecting the systems to flashes of light without the corresponding current, as well as current without light. Detection Technology

Device

Published Response Time

Actual Response Time

A

Light only

<2.5 ms

0.6 ms

A

Current only, instantaneous

No overcurrent element

NA

9

Arc-Flash A

Light with current supervision

<2.5 ms

0.7 ms

A

Load current and flash

No trip

No trip

B

Light only

<1 ms

1.3 ms

B

Current only, instantaneous

<1 ms

Did not trip

B

Light and overcurrent

<1 ms

1.2 ms

B

Load current and flash

No Trip

Tripped

C

Light only

2 to 5 ms

3.3 ms

C

Current only, instantaneous

24 ms

22 ms

C

Light and overcurrent

2 to 5 ms

3.0 ms

C

Load current and flash

No trip

No trip

D

Light only

<1 ms

0.9 ms

D

Current only, instantaneous

<1 ms

6.5 ms

D

Light with current supervision

<1 ms

1.5 to 2 ms

D

Load current and flash

No trip

No trip

Table 2: Arc-Flash Relay Testing Results Relay A has no separate overcurrent output, so the overcurrent element could not be evaluated. Relay B would trip with light only. Relay B has an overcurrent unit that provides a blocking signal when an overcurrent event occurs; this function did not work on the relay used in this study.

CONCLUSION Personnel safety while working around energized electrical equipment depends on the proper performance of several key devices. Personal protective equipment is specified based on published performance specifications from the equipment manufacturers. While this paper was only able to evaluate four arc-flash detection systems, it does reflect well that the equipment performs as expected. The authors of this paper are continuing to test available arc-flash detection systems and will update this paper with the results. All the arc-detection relays were able to detect and signal a trip at the published interval. Evaluation of the arc-detection system should be based on the quality, reliability, sensitivity, security, and usability of the system. Fast trip times do not necessarily make the best overall protection system. Security against false trips from electrical or light noise can be as important as the speed of the system. When selecting arc-hazard mitigation schemes, engineers need to understand the pros and cons of each technology. The fastest detection and trip times are accomplished with arc-flash light detection systems. These systems can use light only or can be made more secure with the addition of current supervision or best with overcurrent detection. Systems using either light or current alone are not as secure as the combination of both technologies. Systems

using current alone, such as instantaneous trip maintenance systems, have the difficult task of balancing security and sensitivity, along with the variation in trip times encountered from different fault levels and manufacturer variations.

REFERENCES 1

 FPA 70E®: Standard for Electrical Safety in the Workplace®, N 2012 edition.

2

I EEE Standard 1584-2002, IEEE Guide for Performing ArcFlash Hazard Calculations.

3

 . Hughes, V. Skendzic, D. Das, and J. Carver, “High-Current B Qualification Testing of an Arc-Flash Detection System,” proceedings of the 9th Annual Power Systems Conference, Clemson, SC, March 2010.

4

I EEE Standard 100-1996, The IEEE Standard Dictionary of Electrical and Electronics Terms, 6th ed.

5

 . Zeller and G. Scheer, “Add Trip Security to Arc-Flash M Detection for Safety and Reliability,” proceedings of the 35th Annual Western Protective Relay Conference, Spokane, WA, October 2008.

William Knapek is the Technical Support and Training Manager for OMICRON Electronics Corp. USA. He holds a BS from East Carolina University and an AS from Western Kentucky University, both in Industrial Technology. He retired from the U.S. Army as a Chief Warrant Officer after 20 years of service, of which 15 were in the power field. Will has been active in the testing field since 1995, and he owned and operated a testing company for 10 years. He is certified as a Senior NICET Technician, Certified Plant Engineer, and a former NETA Level IV technician. Will is also a member of IEEE. Mark Zeller received his BS from the University of Idaho in 1985. He has broad experience in industrial power system maintenance, operations, and protection. He worked over 15 years in the paper industry, working in engineering and maintenance with responsibility for power system protection and engineering. Prior to joining Schweitzer Engineering Laboratories, Inc. (SEL) in 2003, he was employed by Fluor to provide engineering and consulting services. He has held positions in research and development, marketing, and business development. Mark has authored several technical papers and has patents pending through SEL. He has been a member of IEEE since 1985.

10

Arc-Flash

ELECTRICAL SAFETY – A PROGRAM DEVELOPMENT GUIDE PowerTest 2016 Terry Becker, P.ENG., CESCP, IEEE Senior Member The Upstream Oil and Gas Industry (UOGI) in Canada is significant in size and employs thousands of workers who are exposed daily to workplace hazards, which include arc flash and shock. Occupational health and safety management systems are common and mature within the companies that are producers and within the services industries that support the producers, but there is a lack of content included related to arc flash and shock or the development and implementation of stand-alone Electrical Safety Programs that effectively address proactive management of arc-flash and shock hazards. The “Safety Association” for Canada’s Upstream Oil and Gas Industry was solicited by its six member associations to address the implementation of a “Guide” to assist the member associations in reviewing a “systems approach” to effective management of electrical hazards and the development and implementation of an Electrical Safety Program. Consistency in policies, practices, and procedures related to arc flash and shock was a desired state for the Upstream Oil and Gas Industry. It was assessed that providing guidance on how to build, implement, and maintain a discipline-specific Occupational Health & Safety Management System (OHSMS) for arc flash and shock, an Electrical Safety Program would provide direction to the Upstream Oil and Gas Industry with the goal of consistency and sustainability. The “Safety Association” initiated a project and a steering committee with representatives from the six Upstream Oil and Gas member associations was constituted to draft a guideline. Once developed, the “Safety Association” would provide the Guideline for reference to member companies and individuals. This third-party “Safety Association” provides training and documentation tools for the Upstream Oil and Gas Industry in Canada.

THE SAFETY ASSOCIATION Representing hundreds of individual companies, the “Safety Association” was constituted with the following mandate: ●● Help companies improve their safety performance with proven practices and certification tools. ●● Provide training, guidance, and other support to help companies adopt and apply practices to improve safety performance. ●● Gather, analyze, report, and use industry-safety performance data.

●● Foster and promote a strong industry safety culture with timely and targeted communications and advocacy. The Vision and Mission of the “Safety Association” are as follows: ●● Vision: No work-related incidents or injuries in the Canadian Upstream Oil and Gas Industry. ●● Mission: An advocate and leading resource for the continuous improvement of safety performance. Our mission is to help companies achieve their safety goals by providing practices, assessment, training, support, metrics, and communication.

SCOPE OF GUIDELINE DEVELOPMENT – GUIDELINE CONTENT As quoted in the developed Guideline, the intent and purpose was to develop a Guideline written specifically for the oil and gas industry and provide a framework to develop and address electrical safety within a company’s Occupational Health and Safety Management System (OHSMS). The Guideline discusses Electrical Safety Programs (ESP) as they apply to large and small employers and would actually apply to any employer in the industrial, commercial or institutional sectors. The Guideline for Electrical Safety Programs Development deals with safe work practices and not safe installations. For guidance on safe installations practices, the user of the Guideline should reference the Canadian Electrical Code Part 1, C22.1 or the National Electrical Code NFPA 70 and jurisdictional specific requirements. For member companies of the “Safety Association” the Guideline can be used by producers, drilling companies, service companies, transportation companies, seismic companies, exploration companies, and other companies that provide specific support to the UOGI in Canada (electrical and instrumentation services providers, construction services providers, cathodic protection service providers, hydrocarbon transmission companies, and other companies). The Guideline was developed with reference to industry related publications, however it is not exhaustive. The user of the Guideline is advised to defer to published standards and applicable legislation for specific guidance. The document was intended as a guideline and not as a compliance standard. The Guideline was not intended to be a protocol for the audit of an ESP.

Arc-Flash

11

GUIDELINE INTRODUCTION

DEVELOPING AN ELECTRICAL SAFETY PROGRAM

The “Introduction” of the Guideline provides background and identifies the need for the development and implementation of an ESP. Businesses are impacted by the requirements imposed related to Occupational Health & Safety Regulations.

The Guideline advises that an Electrical Safety Program (ESP) documents policies and practices that are directly related to the work tasks completed where electrical energy is present. When considering the development of an ESP an employer should consider the overall OHSMS first. The ESP that is developed can be a detailed and comprehensive document, a more simplified document or, where the organization is small and undertakes work of a low risk, may only need to add a small amount of content directly into the overall OHSMS. The Guideline provides a simple “Electrical Safety Program Development Checklist” that can be referenced and used at the beginning of the project to review what a company should do.

OHSMS standards require that all hazards related to a worker completing a work task be documented. Recognition is given to the fact that the Upstream Oil and Gas Industry employs thousands of workers on a daily basis and that incidents can and have occurred related to the electrical hazards of arc flash and shock. The Guideline recognizes that the application of industry practices such as those outlined in consensus based standards like the CSA Z462 Workplace Electrical Safety Standard, can provide useful information. There is immediate recognition in the Guideline that a disciplinespecific OHSMS for electrical hazards, an “Electrical Safety Program,” can be created as a stand-alone document or integrated within an overall OHSMS. Either way, a safety management system provides for good due diligence in documenting policies and practices and ensuring sustainable and measurable performance. The Guideline specifically outlines that an employer is obligated under the requirements of Occupational Health and Safety Law (OHSL) law to identify workplace hazards, and apply controls to reduce risk. The Guideline stresses that an ESP can provide for effective due diligence. The best due diligence is comprised of establishing an OHSMS, ensuring the system is adequate and that it shall be monitored to confirm its effectiveness. The Guideline further emphasizes the need for a methodical process and increased due diligence to be followed by clarifying that the electrical hazards of arc flash and shock can lead to serious harm or death. It recommends the following process be followed: ●● Identify electrical hazards related to work tasks. ●● Assess the electrical hazards and associated risk related to the work task. ●● Document the application of preventive and protective control measures to reduce risk to as low as reasonably practicable (ALARP). ●● Train workers to identify electrical hazards and to apply appropriate preventive and protective control measures to reduce risk. ●● Monitor the effectiveness of the control measures in reducing risk by performing audits. In order for UOGI employers to understand why an ESP is needed, the Guideline poses several questions to have the employer better understand their business risk. Examples of specific UOGI work task scenarios are provided to place specific emphasis on worker roles and work tasks in the UOGI where electrical hazards are present. The Guideline recognizes that all workers on a worksite can be exposed to electrical hazards.

In developing an ESP an employer should ensure that they review and understand the existing OHSMS practices and requirements. The Guideline outlines that the overall OHSMS’s framework may be modeled after the elements outlined in the CSA Z1000 Occupational Health and Safety Management Standard (or ANSI Z10 for the United States). Developing and implementing an ESP should consider the culture of the organization and the specific behaviors of workers. The ESP can include concepts that influence worker behavior such as TEST-BEFORE-TOUCH. When considering developing an ESP, a key to its success will be ensuring senior management commitment and leadership. Ensure that management is involved and understands the benefits that the ESP will provide. When involving management ensure that the cost benefit of electrical safety is clearly identified. Involving stakeholders in the development and implementation of an ESP is key to its short and long term success. Constituting an Electrical Safety Steering Committee (ESSC) of representative stakeholders (management, safety, supervisors, engineering, qualified electrical workers, operations, non-electrical task qualified workers, planners/schedulers), who are consulted and directly involved, provides a mechanism for consensus-based decisions and buy-in at all levels of the organization that would be impacted. At the beginning of the development project, the Guideline advises that a thorough review of Occupational Health & Safety Regulations (OHSR) is required to understand legal obligations. In Canada, provincial and federal OHSRs differ and an organization needs to understand what regulations apply, to their business. It is noted that whether provincial or federal regulations apply, they will both include requirements for an employer to identify workplace hazards, and that steps would be required to protect workers from those hazards (“General Duty Clause”). In Canada, depending on the province, there may be specific detailed requirements for electrical safety. The Guideline provides a list of standards that an organization may want to reference when developing an ESP. Due diligence to regulations can be fulfilled by applying applicable industry standards.

12

Arc-Flash

Project ManagerElectrical Safety Program Manager Senior Management Sponsor

Safety

Engineering Projects

EngineeringMaintenance

Planners/ Schedulers

Operations

Before undertaking the development of an ESP there should be a clear understanding of the status quo and how the existing OHSMS addresses workplace hazards and key areas that need to be considered with respect to electrical hazards. It is recommended that part of the plan in how to and what to develop starts with completing a “Safety Audit or Gap Analysis” of the company’s existing OHSMS. This process would also assist the ESSC in gaining an understanding and becoming educated on what the ESP can accomplish. Some key questions that the “Safety Audit or Gap Analysis” can address are: ●● What are the electrical hazards?

E&I Maintenance Manager

E&I Supervisor(s)

●● What controls are currently in place (e.g. any existing procedures developed and used)? ●● Are the controls adequate to ensure safety? ●● Have any engineering incident energy analysis studies been completed? Where do they need to be completed, under what priority? ●● What is needed in terms of training? ●● What is needed in terms of Electrical Specific PPE, Tools and Equipment? The Guideline provides a “Site Assessment Checklist” that can be used in completing the electrical hazard specific “Safety Audit or Gap Analysis.”

●● What energized electrical work tasks are performed and by what worker role? ●● What needs to be done to mitigate or control electrical hazards?

It is recommended that the development of the ESP be completed as a defined “project.” The project could be divided into four (4) distinct phases:

Phase 1 Project Manager/Electrical Safety Program Manager assigned. Get organized. Management commitment and sponsor. Safety engaged. Electrical Safety Steering Committee (ESSC) constituted. Schedule. Gap Analaysis. Deliverables.

Phase 2 ESSC reviews requirements and develops Electrical Safety Program. Project based approach. Educated ESSC. Gap Analyis. Consensus.

ESP Phase 3 Electrical Safety Program is finalized. Management approval received.

Qualified Electrical Worker(s)

Phase 4 is rolled out to QEWs and other workers. ESSC meets annually. Internal Electrical Safety Audits. Every 3 years major review and MOC to update.

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Arc-Flash ELEMENTS OF AN ELECTRICAL SAFETY PROGRAM With a detailed review completed, a clear understanding that there are gaps in what may have been undertaken to date, a constituted ESSC in place and engaged to be used for the development of a Electrical Safety Program (ESP), an organization, can then move to defining the “elements” or “framework” of the ESP that would be suited to their company and their existing OHSMS. When considering the ESP for an organization, the Guideline provides a list of “elements” that should be considered. The resulting developed ESP then needs to be approved by management and implemented to achieve the desired outcome of sustainable and measurable electrical safety, and in the UOGI in Canada, consistently. With respect to the “elements” to consider, the Guideline makes reference to processes and content in relevant standards and governmentsponsored programs in Canada such as:

Act • Management review • Contrual Improvement

Check • Monitoring and measurement • Incident Investigation and analysis • Internal Audits • Preventative and corrective action

●● CSA Z1000 Occupational health and safety management Standard (the equivalent in the United States is ANSI Z10 Occupational Health and Safety Management) ●● Provincial Certificate of Recognition (COR) framework for an Occupational Health and Safety Management System (e.g. OSHA Voluntary Protection Program in the United States). A key philosophy promoted in OHSMS standards is a continuous improvement process for safety and electrical safety. This is also promoted in the Guideline: a PLAN, DO, CHECK, ACT (PDCA) philosophy, as depicted in the diagram below. The following is a list of “elements” that can be considered when building an ESP. The Guideline provides comments on what may be considered with each element of the Electrical Safety Program.

Plan • Planning Review • Legal and other requirements • Hazard identification and risk assessment • OHS objectives and targets

Do • Infrastructure and resources • Preventive and protective measures • Emergency prevention, preparedness, and response • Competence and training • Communication and awareness • Procurement and contracting • Management of change • Documentation

Fig.1: Model of an occupational health and safety management system

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Arc-Flash

References

Safe Installations

Hazard Identification

Risk Assessment

Program Management

Policies & Practices PPE, Tools & Equipment

Roles & Responsibilities

Training Incident Reporting & Emergency Response

Principles

Scope

Audit Management of Change

Purpose

Policy, Purpose and Scope The ESP should include a clear statement of the intentions of the program, the “Principles” the program will apply, what it will be used to accomplish, what work is authorized, what facilities it applies to, what workers it applies to, etc. These are summary statements, with the detailed content to be provided in the body of the program.

Roles and Responsibilities Important to not only the development and implementation of the ESP, but key to the day-to-day application of the program is a clear understanding of the specific roles and responsibilities of everyone involved. Two of the primary roles of workers in the field that are directly impacted are the Qualified Electrical Worker and NonElectrical Worker.

Hazard Identification and Risk Assessment The ESP should provide for a documented process that is utilized by the affected worker to identify and quantify electrical hazards. Industry accepted processes, such as Job Hazard Analysis (JHA) Job Safety Analysis (JSA), or Field Level Hazard Analysis (FLHA), may be available for the worker to use. The ESP would outline a process where the employer works with employees and provides them tools to apply. The ESP would provide specific information on the process to determine voltage of equipment, on establishing approach boundaries for shock and on determining the level of arc-rated clothing at an assumed working distance and what the arc-flash boundary is.

The ESP would provide a risk assessment process and expect a hierarchy of controls to be applied to reduce risk. The hierarchy of controls outlined are: ●● Elimination of the hazard; ●● Substitution; ●● Implementation of engineering controls; ●● The use warning signs and barricading; ●● Implementation of administrative controls, through safe work procedures and training; ●● Personal protective equipment. The Guidelines provides specific information related to the hierarchy of controls that can be considered.

Electrical System Data The ESP will rely on electrical system data to be made available to affected workers and this information will play a critical role in safe work planning and executing procedures. The ESP should outline requirements and identify specific electrical system data such as: single line diagrams and other drawings, equipment labeling requirements for arc flash and shock and electrical rooms, and buildings and substation signage to warn workers and identify restrictions.

Electrically Safe Work Condition The most important element of an ESP should be a clear statement and details related to de-energizing electrical equipment before working on it. In the applicable industry standards, this process is

15

Arc-Flash referred to as an “Electrically Safe Work Condition.” Critical to this process is determining the absence of voltage and applying a TEST-BEFORE-TOUCH process.

●● Qualifications and training requirements for workers who operate electrical equipment.

A priority of the ESP should be to minimize the amount of energized electrical work performed and ensure that the risk associated to that work is understood and reduced to as low as reasonably practicable (ALARP).

●● Ensuring the equipment is in a normal operating condition (all doors closed and latched).

Power Line Safety

●● I dentifying abnormal conditions while operating the equipment, and if an abnormal condition is identified, ensuring it is reported to a Qualified Electrical Worker for further investigation.

The Guideline identifies that in the Upstream Oil and Gas Industry, high voltage power lines both overhead and buried pose a significant risk related to transportation and movement of high loads, excavation activities, hoisting and reaching, and drilling and boring. Any work task or activity in proximity to high voltage “Utility” transmission, distribution and substation facilities will require employees to identify, assess and control exposure to electrical hazards. Safe “Limits of Approach” shall be established for work by contacting the “Utility” owner if work will be completed within 7 metres (approx. 23 feet) of the high voltage transmission, distribution lines or substation. Workers must be trained in emergency response procedures should they find themselves near a downed power line or if an underground power line is contacted or if they are involved in a collision with an overhead power line.

Job Planning Meetings An ESP should specify requirements that assigned work tasks, where there may be exposure to electrical hazards, require pre-job planning that would include:

●● Proper body positioning when operating electrical equipment.

●● Identifying if any PPE is required depending on the specific work task and equipment conditions.

●● Proper investigation of tripped protective devices by a Qualified Electrical Worker.

Portable Electric Equipment and Extension Cords Portable electric equipment and the use of extension cords can pose a significant shock risk to all workers in the workplace. The Guideline advises that an effective ESP will identify the risk of exposure and specific requirements. Often in the workplace this equipment is overlooked or poorly managed. This equipment is approved for use and must be maintained or an increased risk of shock and electrocution can result. Safe installation Codes identify the need for equipment bonding and grounding; the degradation or damage to these controls can increase risk of exposure. All workers should follow specific procedures when using this equipment. A key control related to reducing risk is the use of Ground Fault Circuit Interrupters (GFCIs) when the portable equipment and extension cords are used in indoor or outdoor locations where water may be present. A Class A GFCI must be used when this condition exists.

●● Completion of a risk assessment related to the work task.

Extension cords are used in all workplaces and by all workers. If improperly assembled and not maintained, they pose a shock and electrocution risk to the worker. Qualified Electrical Workers are the only authorized workers to assemble and maintain extension cords.

●● A plan for executing the work task, including the development of procedures that would be utilized.

In the United States an Assured Equipment Grounding Conductor Program can be implemented.

●● Identifying required Electrical Specific PPE, Tools & Equipment for the work task.

Temporary Power Distribution Systems

●● Identification and evaluation of the hazards associated with the work task and, specifically, electrical hazards.

The ESP would also outline that a pre-job briefing be completed for all workers involved. The Guideline identifies that examples of a pre-job briefing and planning checklist are provided in the CSA Z462 Workplace Electrical Safety Standard (or NFPA 70E Standard for Electrical Safety in the Workplace).

Operating Fixed Electrical Equipment Within the ESP Roles & Responsibilities section, workers will be identified that will be authorized to operate circuit breakers, disconnect switches, push buttons, relays, etc. The ESP should include information on:

The Guideline outlines that in the Upstream Oil and Gas Industry, during construction and maintenance turnarounds, extensive use of temporary power distribution systems are used to provide power to portable electric equipment and other loads such as lighting. The temporary power systems need to be installed to the requirements of the applicable safe installations Code and procedures put in place to ensure identification of potential electrical hazards. The temporary power distribution systems must be inspected for damage and proper electrical protective devices installed and functioning (GFCIs).

16 Electrical Specific Personal Protective Equipment (PPE) The Guideline identifies that the ESP should provide information on the employers specific requirements to protect Qualified Electrical Workers from arc flash and shock. Specific requirements should be documented related to: ●● Specification of Electrical Specific PPE, Tools & Equipment. ●● When Electrical Specific PPE should be worn. ●● How to select appropriate PPE, tools and equipment. ●● Minimum requirements. ●● Requirements for proper care and maintenance. ●● Requirements for testing rubber insulating gloves every 6 months. ●● Requirements for testing “live-line” tools every 24 months. ●● Requirements for testing Temporary Protective Grounds every 36 months.

Equipment and Tools for Electrical Work Where work tasks are justified and authorized to be completed related to energized electrical equipment, the ESP should provide policies and requirements for the specification and use of the following: test equipment such as digital multi-meters used to test circuits for the absence of voltage, test equipment for use on high voltage equipment (i.e. >1000V), insulated hand tools, and insulating “live-line” tools. The ESP will outline that test equipment must be appropriately rated for the intended use and be in good working condition. The test equipment and insulated or insulating hand tools shall be preuse inspected and checked by the Qualified Electrical Worker before it is used.

Training The ESP should outline the specific electrical safety training requirements for each worker role. The training should consider the work tasks performed by the worker role and what level of training is required. A training matrix is identified and should be developed for all workers that operate and maintain energized electrical work. The ESP should identify the training frequency for different worker roles and the Guideline recognizes that CSA Z462 Workplace Electrical Safety Standard (or NFPA 70E Standard for Electrical Safety in the Workplace) recommends that the training interval should not exceed three (3) years. The ESP should outline how the training is delivered and that training documentation is required to be retained. The Guideline also outlines that beyond “qualification” training a specific documented competency validation process should be used. This may be of critical importance for Qualified Electrical Workers that perform critical high-risk work tasks. The process of

Arc-Flash validation can be completed by the worker’s supervisor or another delegated Qualified Electrical Worker that has demonstrated and has been deemed competent. The Guideline provides a sample list of what may be required for electrical safety competencies.

Maintenance and Housekeeping The Guideline outlines that the ESP should address the requirement for electrical equipment maintenance to be performed on a regular basis and that general housekeeping around electrical equipment is required. Specific mention is made with respect to the importance of arc-flash incident energy for circuit breakers to be exercised and tested at a regular frequency. The maintenance performed will ensure that the circuit breaker will operate in the specific amount of time required in order to limit incident energy in the event that an arcing fault occurs on energized electrical equipment. Depending on the electrical equipment, simple maintenance, such as cleaning dust and other contaminants, can reduce the probability of arcing faults occurring. Visual inspections should be completed on a regular basis to identify excessive corrosion, overheating or damage to electrical systems such as grounding. Examples of nonintrusive electrical inspections are infrared and ultrasonic.

Safety by Design As identified in the Guideline and as a priority control in the hierarchy of controls to reduce risk, engineering “Safety by Design” related to new electrical equipment and upgrades should be documented in the ESP. This should be considered by the employer (the owner of the electrical equipment) and the design engineer. The Guideline outlines that in all instances, electrical hazard risk exposure should be reduced to as low as reasonably practicable at the design phase of an electrical power distribution system. Safety related design requirements may consider the following: ●● Reducing the risk by eliminating or limiting the need for interaction. ●● Reducing incident energy where technically possible and considering reliability. ●● Reducing risk of exposure to shock by segregation, additional guarding, insulated bus and terminations, and finger safe components. ●● Increasing the working distance. ●● Installing infrared and ultrasonic inspection ports. ●● Installing permanent voltage and current meters. ●● Installing neutral grounding resistors to limit a single phase fault from escalating to a three phase fault. It is recognized that there are a variety of “Safety by Design” options that can be applied and that implementation may be limited by technical feasibility and cost. A cost benefit analysis is required during design.

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Arc-Flash Emergency Response to Electrical Incidents and Fires The Guideline outlines that if electrical incidents occur, they must be properly reported to the jurisdiction having authority and managed. The employers’ overall Emergency Response Plan must consider emergency response requirements to electrical incidents that would be outlined in the ESP. The ESP should provide specific policies and procedures related to who can implement emergency response and what must be considered. Specific mention of requirements related to emergency release of a shock victim should be documented in the ESP. Training requirements related to first-aid and CPR for emergency response shall be provided in the ESP. Where emergency responders of the Upstream Oil and Gas Industry are available to respond to fires, they should receive appropriate training related to the risk of exposure to electric shock and what they must do.

External Electrical Safety Audit (system audit), and Peer to Peer review (practices and behaviors). Regularly review applicable Occupational Health and Safety legislation and standards and update the Electrical Safety Program as required. When audits are completed, a report is generated to document findings and corrective actions to improve the Electrical Safety Program and the implementation of the hierarchy of controls.

SUPPORTING CONTENT OF THE GUIDE Additional resources are provided in the Guideline, in support of the information presented, that can be used to assist in applying the content in the Guideline and in the ultimate development of a comprehensive ESP suitable to an organization and integrated with the requirements of the overall Occupational Health and Safety Management System.

REFERENCES Csa Z462 Workplace Electrical Safety Standard.

IMPLEMENTATION

NFPA 70E Standard for Electrical Safety in the Workplace.

Finally after the development of an ESP, as identified in the Guideline, is completed, it will be required to be implemented and maintained on a go-forward basis.

CSA Z1000 Occupational Health And Safety Management.

The Guideline identifies 6 key components to successfully implementing the ESP: ●● People – involve people with the required knowledge and skills. ●● Resources – allow sufficient time and resources. ●● Budget – ensure budgets have been identified for implementation and maintenance of the program.

ANSI Z10 Occupational Health and Safety Management. United States Department of Labour, Occupational Safety & Health Administration, Voluntary Protection Program, An OSHA Cooperative Program, https://www.osha.gov/dcsp/vpp/.  overnment of Alberta, Canada, Jobs, Skills, Training and G Labour, Occupational Health & Safety, Certificate of Recognition, https://work.alberta.ca/occupational-health-safety/334.html. Enform, www.enform.ca/default.aspx.

●● Structure – ensure the role of an ESP Manager has been assigned and that regular Electrical Safety Steering Committee meetings are held.

Enform, Electrical Safety – A Program Development Guide, http://www.enform.ca/safety_resources/publications/ PublicationDetails.aspx?a=72&type=guidelines.

●● Systems – Use the safety management system to track progress and establish performance milestones. Ensure that the required Internal Electrical Safety Audit and/or Gas Analysis is completed every 12 months and corrective actions implemented.

sa Z1002 Occupational Health And Safety – Hazard C Identification and Elimination Risk and Asessment Control.

●● C  ulture – Create an environment that connects employees to the ESP and develop creative consequences for achieving or not achieving targets. Use the Plan, Do, Check, Act continuous improvement philosophy to drive the success of the ESP. Get affected workers engaged and encourage feedback and suggestions on how the ESP can be improved. Ensure that the ESP is working, responsive, and current by implementing audits and/or gap analysis. The ESP should outline requirements and frequency for detailed review and implementation of appropriate corrective actions to identified deficiencies. Methods that can be used are: Supervisory Level Audit, Internal Electrical Safety Audit (system audit),

CSA Group, Canadian Electrical Code Part 1, C22.1. NFPA, NFPA 70 National Electrical Code. Terry Becker, P.Eng., is the owner of ESPS Electrical Safety Program Solutions Inc. in Calgary, Alberta, Canada. Terry has over 24 years experience as an Electrical Engineer, working in both engineering consulting and for large industrial oil and gas corporations. He is a Professional Engineer in the Provinces of Alberta, British Columbia, Saskatchewan, and Ontario. Terry is the past Vice Chair of the CSA Z462 Workplace Electrical Safety Standard Technical Committee, and currently an Executive Committee member, voting member, and leader of Working Group 8 Annexes, as well as a member of the IEEE 1584 Committee, the CSA Z463 Guideline for Electrical Equipment Maintenance Standard Committee, and a member of the NFPA 70E Annexes Working Group.

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LOW-VOLTAGE METAL ENCLOSED BUS DUCT WETTING EVENTS PowerTest 2014 Dan Hook,PE, Western Electrical Services

INTRODUCTION Over the last ten years I have been involved with approximately a dozen wetting events involving low voltage metal enclosed non-segregated bus duct. The source of the water in each event varied; Rain, HVAC systems, a swimming pool, and permanent and temporary plumbing systems in the buildings were all culprits. In response to the first of the events, I simply applied the industry recognized testing standards to determine suitability for continued service, and in one instance dried out a single piece of bus duct until it met the applied specification. As the events continued in our service area, I recognized some commonalities in the events. These commonalities were useful combatting the technical aspects of the projects themselves as well as managing the expectations of the owner, contractor, and consultants commonly involved. The events grew increasingly more complex, with more at stake financially for the owner. This combination justified the resources to explore the published guidance and regulations, and improve my knowledge pertaining to these situations. The series of events culminated in one project where significant research and empirical testing and data gathering were authorized, yielding significant results I would like to share. Additionally, in the midst of one of the projects, I was given a report for a similar instance where the project team was being asked and asking the same types of questions I had in my mind. I will present four events I was directly involved with as well as a summary of this similar project based on the information contained in the final report.

EVENT #1 In 2005, during the construction of a low voltage doubleended substation, a custom piece of NEMA 1 bus duct, designed to connect one transformer to one end of the switchgear, was left outside inadvertently. Over the course of at least 24 hours, the elbow was exposed to a significant amount of rainfall. The exposure was not noted or reported by the installing contractor. During acceptance testing of the substation, the insulation resistance test results for the run of bus duct with the custom elbow installed did not meet the applied specification. Insulation resistance readings were 0.82 Mega-Ohms with the minimum required per the specification of 100 Mega-Ohms.

Troubleshooting ensued and the wetted piece was identified and removed from the installation. The project team explored the option of having the wetted piece replaced with a new custom built piece, however the cost and delivery time ruled this option out as viable. Another option presented was to dry the piece in an industrial oven of appropriate size by maintaining a temperature less than the rated temperature of the equipment, but high enough to evaporate any moisture present. The temperature rating of the equipment published by the manufacturer was 130C. The drying took place over the course of several days at approximately 80C with special attention paid to temperature correction of the values to a 20C standard temperature. Final insulation resistance readings were 10,000 Mega-Ohms. With insulation resistance once again meeting the applied specification, an over potential test was performed in accordance with the current ANSI/NETA ATS Specification with passing results. A final report of the activities was submitted to the owner and accepted. The installation has been in service since the second half of 2005 with no reported issues.

EVENT #2 In 2009, a customer experiencing an outage on a motor control center contacted me. The motor control center was fed by NEMA 3R metal enclosed bus originating from an electrical room, routed along the ceiling of a multistory parking garage directly under the motor control center, and then angling up 90 degrees and entering the motor control center in a bottom feed type configuration. A fused switch in the originating electrical room protected the feeder type bus duct, and all three fuses were blown. Preliminary visual inspections by the customer revealed some carbon deposits surrounding a small area with arcing damage and water leaking on top of the bus duct. The water source was traced back to an overflowing swimming pool located on top of the parking garage. Temporary power was routed to the motor control center to allow the building to return to normal operation, while the project team planned the repairs and recovery. In this case, with stable building power and a clearly faulted section of bus duct requiring extensive repairs, the project team elected to order a new section of bus duct from the factory and wait the required 3-4 week lead time.

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Arc-Flash The faulted section of bus duct was removed and the remaining upstream and downstream assemblies were tested using ANSI/NETA MTS specifications to ensure no other sections were subjected to water damage. Upon replacement of damaged section with the new section, the entire bus duct run was again subjected to testing in accordance with ANSI/ NETA MTS specifications with passing results. This same run of bus duct has been wetted at least one other time since the repairs in 2009, however with no failure of the bus duct. When the building operators recognized the wetting occurring again from the overflowing swimming pool, the system was de-energized and tested using ANSI/NETA MTS specifications and was determined to be suitable for continued service. This installation with repeated water exposure of NEMA 3R bus duct, forced me to recognize the fact that “exposed to water” and “water damaged insulation,” as it applies to metal enclosed bus duct, is not the same thing. Proper testing procedures and data must be utilized to ensure defective equipment is repaired or replaced, while also ensuring equipment that has not been damaged is not unnecessarily discarded.

EVENT #3 During the course of my study and research on the lengthy event #4 to be covered later in the article, I was sent a final report for an event covered by others that did not happen in my service area. The report suggested that my thoughts and approach to these events, happening many times a year, was shared by at least one other person and encouraged me to proceed. The event description is based solely on my review of that final report. In 2004 a medical facility under construction experienced a wetting event on the 8th floor. The report is unclear as to what the exact source of the leak was, however two new NEMA 1 bus duct assemblies were wetted. Due to the fact this equipment was new and still under manufacturers warranty, consideration was given to whether the manufacturer would still honor the warranty. The report covered insulation resistance testing and over potential testing of the intact bus duct assemblies. Due to the high capacitance values of the relatively long assembly of bus duct sections, supplemental inductors were required to allow the Doble M4100, used as the voltage source, to build the voltage to the required voltage levels. The insulation resistance results were considered acceptable at approximately 100 Mega-Ohms. The over-potential test was assigned a PASS result due to no indications of break down and no tripping off of the voltage source due to over current conditions. The leakage current recorded was consistent in the phase-to-phase and phase-to-ground tests conducted. The approach described in this report was enlightening to me in the choice of the test voltage source. AC over-potential testing of a large assembly of many bus duct sections can often be problematic due to the large amount of losses not allowing the required voltage level to be attained.

EVENT COMMONALITIES The previous three events followed a common approach to determine if, in fact, the insulation system was compromised during a wetting event. The decision of replacement versus repair or reconditioning, so to speak, was left up to the customer and the rest of the project team. The approach is grounded in the testing procedures and specifications contained in ANSI/NETA specifications as well as manufacturers guidance. Insulation resistance testing and overpotential testing were sufficient to satisfy the project team of the suitability of the equipment for continued service. The next two events required me to research further into the codes and regulations that were specific to my service area, including the Washington Administrative Code and the Seattle Electrical Code.

EVENT #4 A bus duct assembly was wetted from the 7th floor electrical room of a 13-story structure. A building water system leaked on service-aged NEMA 1 plug in type bus duct, and then travelled down the riser to the basement where the bus duct transitioned to a horizontal configuration to the electrical room entering the top of the switchgear. The bus duct was de-energized when building personnel discovered the event. No catastrophic event occurred. I was contacted as a consultant to advise the customer on the need to replace any or all of the bus duct sections. In a quick conversation over the phone, prior to mobilization, the customer stated that another testing company had been onsite and test results showed the insulation quality was compromised and the test data did not meet ANSI/NETA specifications. The electrical contractor onsite also stated that the position of the electrical inspector was that any piece of bus duct that was exposed to water required replacement per the Seattle Electric Code Article 110.11, Fine Point Note #4 (This Fine Point Note directly references the state administrative code, Washington Administrative Code, 296-46B-110-001.2.a-b, reproduced below.

296-46B-110,
General Requirements for Electrical Installations ●● 011 Deteriorating Agents ●● Electrical equipment and wiring that has been submerged or exposed to water must comply with the following: ○○  All breakers, fuses, controllers, receptacles, lighting switches/dimmers, electric heaters, and any sealed device/ equipment (e.g., relays, contactors, etc.) must be replaced. ○○ All other electrical equipment (wiring, breaker panelboards, disconnect switches, switchgear, motor control centers, boiler controls, HVAC/R equipment, electric motors, transformers, appliances, water heaters, and similar appliances) must be replaced or reconditioned by the original manufacturer or by its approved representative.

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Arc-Flash

The customer was having a difficult time accepting the wholesale replacement of 13 floors of bus duct, when clearly the floors from the 7th floor up were not exposed to water, and after examination in the basement, after about 3 feet of horizontal displacement from the riser area, no evidence of wetting was present. The language “submerged or exposed to water,” offers an extremely large range of conditions, which the AHJ was interpreting in a way the customer was not appreciating. In an attempt to understand the interpretation myself, I discovered a NEMA document titled “Evaluating WaterDamaged Electrical Equipment,” ©2011. This document used the phrase “subjected to water damage,” which offers a bit more insight in that the language expresses that the equipment must be damaged for the guidance to apply. The specific language must be dealt with rigorously as interpretations by Authorities Having Jurisdiction have real operational and financial impacts on facilities unfortunate enough to experience wetting events.

In an attempt to discover which sections of bus duct could truly be considered to have suffered water damage, a new test routine was proposed. The plan called for the removal of splice joint packs from the bus risers in two places, such that the vertical sections from the 7th to 13th floors could be tested separately from the 7th floor down to the basement, including the vertical sections and the vertical to horizontal transition elbow section, and finally the remainder of the horizontal section to the switchgear room. Insulation resistance was the only test performed. The results showed clearly which portions had compromised insulation and which did not. Given the inclination to remove more bus splices and continue testing, I was confident the number of sections actually showing failed test results would have shrunk, however other factors dictated we conclude our testing and submit our report after one day of testing.

Fig. 1: Insulation Resistance Floor 7 and Up

Fig. 2: Insulation Resistance Floor 7 to B level

Fig: 3. Insulation Resistance B Level to Switchgear

Arc-Flash EVENT #5 The last event I will discuss was the largest in terms of implications for the owner, and therefore, the willingness to gather data, study equipment specimens, and perform additional testing was the greatest. All of my previous experiences resulted in a better understanding of strategies to deal with wetting events, as well as the guidance provided by manufacturers, and finally the stance of many representatives of the authority having jurisdiction in my service area. The additional efforts and expenses to allow me to paint a more complete picture of wetting events and the associated test results, proved to be very beneficial. Seven bus duct assemblies in a 30+-story building were wetted when HVAC piping failed on the 14th floor. The water from the HVAC system travelled down the riser space to the basement where the bus ducts transitioned to a horizontal configuration in the same way as in the previous event. In a relatively short period of time, one of the seven bus-duct assemblies suffered a catastrophic failure in the basement, specifically on the elbow that transitioned the bus duct from a vertical to a horizontal orientation. Preliminary test results on-site, prior to my involvement in the project, were performed by removing an “elbow” from one of the other assemblies and applying a insulation resistance tester to the vertical sections extending upward. The test results indicated results that met the ANSI/NETA specifications deeming the bus duct suitable for continued service. Based on input from the authority having jurisdiction that the entirety of all seven bus-duct assemblies needed to be replaced, as in event #4, the customer proceeded with demolition of all sections on every floor. Upon my arrival at the site, I inquired as to testing sections of the bus duct in place to determine if, in fact, any water had damaged the insulation. I was denied the opportunity to test any bus duct in place, but was given approval for extensive testing after removal. Individual sections of bus duct were subject to insulation resistance tests and over-potential tests utilizing a power factor test set at the voltage source; and all power factor/dissipation factor data was also recorded in accordance with the test set manufacturers instructions. At the conclusion of the project, 135 sections of metal enclosed bus duct had been subjected to these tests. Performing the industryrecognized testing routine on the specimens per ANSI/NETA MTS specifications easily identified the bus duct sections that experienced water contamination of the insulation system when a power factor test set was used as the voltage source, such that valuable power factor data could be gathered. The final test results identified seven pieces of bus duct that did not meet the applied specification as determined by field test results. Predictably the failed pieces were located lower in the riser, and in every case but one, was in the basement with horizontal orientation on at least some of the section, allowing for collection of water and pooling. As I stated earlier, the implications of the project approach and test results were uncharacteristically high for this project, so the testing and data gathering continued.

21 Following the field tests, four bus duct sections were packed and sent to a testing laboratory in the southeastern US. The test specimens were selected to represent two different sizes of bus duct removed from lower floors and one section that yielded questionable and unacceptable test data during the measurements made in the field. The purpose of this exercise was to re-measure each section with laboratory standard dissipation factor and insulation resistance equipment. In addition, testing was scheduled to address the effects of moderate and severe applications of water to bus duct sections. When NEMA 1 bus ducts are introduced to moisture from rain, broken water pipes or leaking drainpipes, there is always a question of how much water has gained entrance and, in turn, contaminated the bus bar insulation system. For this reason the employment of dissipation factor measurements are extremely useful and allow for accurate assessment of the presence of moisture in the bus duct. Although the dissipation factor may be a little more difficult to measure, the improvement of portable equipment has allowed for accurate field measurements and the correct assessment of damaged insulation systems. To demonstrate how effective dissipation factor measurements can be when moisture ingress is suspected, testing was completed in the laboratory with two levels of water contamination. The first application of water was sprayed on the sample until the entire exterior surface of the bus duct was wet. The sample was remeasured and the data showed no significant change in dissipation factor or insulation resistance. The sample of bus section was then subjected to a severe soaking of water that was forced into the end of the bus duct. Following this, the dissipation factor could not be measured between parallel bus bars, while the insulation resistance measurements between phases were measured at 100 Giga-Ohms and showed a value of 11 and 20 Mega-Ohms between the outer buses and the case. Dissipation factor for the bus bars to the case was high at 25.1% and 8.8%. The bus duct section was then load cycled with current circulated in each bus until the dissipation factor improved to a satisfactory level between the bus bars. This data is shown as #438-5 in Figure 4. The insulation resistance data would meet manufacturers specifications and more stringent ANSI/NETA specifications for all buses indicated. However, the dissipation factor data between buss bars and the case was higher than the original measurement and suspect. The bus duct was then dismantled and the terminals were cleaned. An outer shield consisting of copper braid was wrapped around the encapsulated bus bars and the dissipation factor measurements still showed moisture present in the outer bus bar insulation. However, examination of the insulation resistance data showed values greater than 100 G-ohms.

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CONCLUSIONS ●● Metal enclosed bus ducts can sustain rather liberal amounts of water and experience no significant loss of insulating properties. ●● ANSI/NETA ATS and MTS specifications are the industryrecognized standard for determining if new bus duct is suitable for initial energization and if service aged bus duct is suitable for continued service. However, consideration should be given to power-factor testing if moisture contamination is suspected.

●● Manufacturers have an inherent conflict of interest in evaluating electrical equipment for continued service and their literature contains conflicts in direction as it pertains to wetted bus duct: ○○ N  EMA BU 1.1-2010 General Instructions For Handling, Installation, Operation, and Maintenance of Busway Rated 600 Volts or Less, Section 9 Care and Maintenance; ○○ NEMA: “Evaluating Water-Damaged Electrical Equipment.”

Fig. 4: Laboratory Test Results

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Arc-Flash ●● The Professional Electrical Apparatus Recyclers League (PEARL) publishes a reconditioning standard for metal enclosed bus duct. PEARL is accredited by ANSI as a standards developer. ●● Common terms used when discussing wetting events “exposed” and “subjected to water damage” and “submerged,” mean different things. As the test results and data clearly show, a piece of bus duct with Mylar insulation can be exposed to water without the insulation being subjected to water damage. Further, the drying of moisturecontaminated insulation in bus duct sections is possible. In the cases where chemicals, dirt or other contaminants are present, they can be removed as well, consistent with NEMA BU 1.1 2010 and PEARL reconditioning standards. ●● Metal enclosed bus duct oriented horizontally is much more susceptible than vertical bus duct to a wetting event. This is due to the fluid actually seeping into the insulation of a bus duct assembly, compromising the ability of the insulation to perform as required vice running down the protective metal enclosure with no affect on the insulation. ●● Power Factor/Dissipation factor test results can determine definitively whether a wetting event has compromised the insulation system of metal enclosed bus duct or is a superficial wetting of the metal enclosure. In some cases, a simple insulation resistance test may meet the applied specification, however moisture contamination is present. ●● State and local authorities having jurisdiction may diverge from industry-recognized standards, such as NEMA and ANSI/NETA guidelines. Understanding these regulations can be of high importance when part of a project team is attempting to deal with an emergent type of situation. ○○ Example: WAC article, which directs replacement of all circuit breakers subjected to wetting events, is in direct contradiction to NEMA guidelines, differentiating between molded case circuit breakers and low voltage power circuit breakers or medium voltage circuit breakers.

REFERENCES AND INFORMATIONAL SOURCES ANSI/NETA ATS and MTS Section 1.1.1-1.1.2 ANSI/NETA ATS and MTS Section 7.4 ANSI/NETA ATS and MTS Table 100.1 and 100.14.1 or 100.14.2 ANSI/NETA ATS and MTS Table 100.17 NEMA BU 1.1-2010 “General Instructions for Handling, Installation, Operation, and Maintenance of Busway Rated 600 Volts or Less” NEMA “Evaluating Water-Damaged Electrical Equipment” ©2011 PEARL Reconditioning Standards, Low Voltage Bus Duct Plugin Type Section 2010 Revision #5 11-2008 PEARL Reconditioning Standards, Low Voltage Bus Duct Feeder Type Section 2010 Revision #5 11-2008 Washington Administrative Code 296-46B-110-001.2.a-b Seattle Electrical Code 110.11 FPN#4 Dan Hook is the Executive Vice President in charge of Business Development at Western Electrical Services, Inc. where has previously held Field Service Engineer, Sales Engineer, and Chief Operating Officer positions. He has been in the industrial electrical industry for over 20 years with US Navy and civilian experience. Dan holds a master’s degree in Electric Power Engineering from Rensselaer Polytechnic Institute in Troy, New York, and he maintains his professional engineer’s license in Washington, Utah, Arizona, and Oregon. He earned an MBA in 2012 from Pacific Lutheran University with a concentration in Entrepreneurship and Closely Held Businesses. Dan is a certified NETA Certified Senior Technician Level IV as well as a NICET Level IV.

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ARC-FLASH HAZARD MITIGATION BY TRANSFORMER DIFFERENTIAL RELAY PROTECTION PowerTest 2016 Randall Sagan, Mercedes-Benz U.S. International, Inc. Mose Ramieh III, Power & Generation Testing, Inc.

INTRODUCTION Unit substation transformers in industrial facilities are commonly protected by fuses installed at the primary disconnect switch. This arrangement is relatively inexpensive, provides good protection of the primary windings, and coordinates well with the protective relay on the upstream feeder breaker. However, fuse clearing time for a secondary winding fault is much slower and results in dangerously high values of arc-flash incident energy (AFIE) at the secondary circuit of the transformer. This paper describes the use of a transformer differential relay scheme as one method to reduce the arc-flash hazard at the secondary circuit of the transformer. Other significant benefits in protection and control are also discussed. Testing and commissioning of the overall unit substation is reviewed with emphasis on the key points that require special attention.

TRANSFORMER PROTECTION When a downstream short circuit occurs (called a “fault”), the links inside the fuses melt to interrupt the fault current. “Downstream” could mean the primary windings of the transformer or could mean a feeder circuit fed from the unit substation. All downstream faults will be sensed by the fuses. If the current magnitude is high enough and is sustained long enough, then the fuse links will melt and open the circuit. If only one or two of the fuses open on a three-phase transformer, then additional equipment failure or damage could occur from the resultant voltage imbalance. This is called a “single-phase” condition. Although most medium voltage primary switches are rated to interrupt load current, the preferred practice is to only use the secondary main breaker for interrupting load current. A key interlock scheme between the primary switch and the secondary main breaker is often used to prevent opening or closing the switch when the breaker is closed. This means that whenever the transformer needs to be de-energized (for maintenance or any other reason) the secondary main breaker must be opened before the primary disconnect switch can be opened and locked out. Some arrangements even require racking out the main breaker before the interlock key can be released. In this case, maintenance

personnel must utilize appropriate personal protective equipment (PPE) while racking out the breaker. This includes arc-rated clothing and protective safety equipment rated for the arc-flash hazard levels present at the secondary main breaker. Due to the slow clearing time of the primary fuses, these hazard values can sometimes exceed the maximum safe ratings of such PPE.

TRANSFORMER DIFFERENTIAL RELAY A transformer differential relay scheme requires more components and is much more complicated than a fuse protection scheme (see Diagram 1). Current transformers (CT’s) are used on both the primary and secondary sides of the transformer. A primary circuit breaker and associated controls (including the differential relay) replace the fuses in the primary switch. For medium-voltage applications, this breaker is equipped with vacuum contactors to safely interrupt fault current. The CT circuits feed analog current signals to the transformer differential relay, which in turn provides trip functions to the circuit breakers. All of the circuit elements between the two sets of CT’s make up what is called the “zone of protection.” By locating the CT’s on the line-side of the primary circuit breaker, and on the load-side of the secondary breaker, both breakers can also be protected by being included in the differential relay’s zone of protection.

Diagram 1: Typical transformer differential relay scheme. All components between the primary and secondary sets of CT’s are contained within the differential relay’s zone of protection.

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Arc-Flash This scheme operates based on the concept that transformer power IN equals power OUT. The differential relay uses signals from the two sets of CT’s to monitor the current passing through the transformer. If a fault occurs within the zone of protection, then the relay senses a difference between IN and OUT and operates to trip the breakers connected to the transformer. If a fault occurs downstream of the zone of protection, then the fault currents passing through the transformer will sum to zero and the relay will not trip its breakers. Because a differential relay is much more sensitive to faults anywhere within its zone of protection (even on the secondary windings), it is able to operate much faster than a fuse protection scheme.

The transformer differential relay settings must account for the transformer turns ratio, phase shift due to delta-wye winding configurations, differences between primary and secondary CT ratios, and phase rotation. Using all of this data, the relay currents are normalized in per-unit values to accurately represent load current flowing through the transformer (see Diagram 3). Under normal load conditions, the sum of input and output vectors for each phase will be equal to zero. When there is a fault within the zone of protection, then the magnitude of the resultant vector sum will cause the relay to operate and issue a trip signal.

CT LOCATION AND ACCURACY To ensure that the transformer differential relay does not misoperate for a downstream fault outside of its zone of protection, the accuracy ratings of both sets of CT’s need to match. Higher accuracy class CT’s, however, will probably not fit in the lowvoltage main breaker cubicle. In this case, the CT’s may have to be installed on the low-voltage busbars inside the transformer enclosure (see Diagram 2). Unfortunately, this leaves the secondary main breaker outside of the differential relay’s zone of protection. By utilizing additional overcurrent elements the relay can still provide exceptional protection compared to traditional fuse protection. On the other hand, if the secondary CT’s are located inside the transformer, then the control power transformer (CPT) will also be excluded from the differential relay’s zone of protection. This allows more sensitive settings to be applied to the differential relay, and therefore, provide even better transformer protection. The tradeoff between transformer protection and arc-flash hazard must be weighed when considering the location of secondary CT’s in a differential relay scheme. Both options provide improvements over traditional fuse protection schemes.

Diagram 2: If secondary CT’s do not fit in main breaker cubicle, then they may be installed on low-voltage busbars in the transformer enclosure. In this case, the differential relay can be set very sensitive since the CPT is excluded from the zone of protection.

Diagram 3: Normalized per-unit current vectors are added together by the relay software. For normal load conditions, each phase should sum to zero.

ARC-FLASH HAZARD MITIGATION Fault current on the secondary windings of a transformer will be detected by the primary fuses, but at a magnitude reduced by the ratio and impedance of the transformer windings. This reduced-magnitude fault current means the fuses will take much longer to clear the fault than they would if the fault were on the primary windings. The longer fuse clearing time results in much higher values of AFIE at the secondary circuit of the transformer. For a typical industrial three-phase transformer (e.g., 2-MVA, 13,800/480-volts, delta-wye) using primary fuse protection, AFIE at a distance of 24-inches at the secondary circuit can be as high as 80-cal/cm². This is generally considered too high for safely working energized (Category Dangerous), even with appropriate arc-rated clothing and PPE. For AFIE values above 40-cal/cm² at the working distance, NFPA 70E recommends greater emphasis on de-energizing equipment if at all possible. The faster clearing time of a differential relay scheme however, can reduce the AFIE at the secondary circuit of the same transformer to less than 1.2-cal/cm². This is the main reason differential

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relay protection is becoming more prevalent in industrial power distribution systems. Even if the secondary main breaker is not included in the differential relay’s zone of protection, faster fault clearing using backup overcurrent elements can still reduce the AFIE to less than 20-cal/cm². This is well below the maximum acceptable level and provides a much safer system.

ADDITIONAL DIFFERENTIAL RELAY BENEFITS A differential relay scheme provides several other benefits in addition to reduced arc-flash hazard. One benefit is better overall transformer protection. By quickly de-energizing the transformer in the early stages of a fault, the extent of the damage can be greatly reduced. This could potentially save a transformer from catastrophic failure and possibly mean that it can be repaired instead of having to be totally replaced. This leads to reduced cost of repair and less downtime after a failure, especially if the faulted transformer can be repaired on site. Because a differential relay scheme requires a primary circuit breaker instead of individual fuses, the risk of voltage imbalance due to a “single-phase” condition is eliminated. This protects other downstream equipment from being damaged in the aftermath of a transformer fault. Again, restoration and recovery is much less expensive and faster if multiple other components do not also have to be repaired or replaced. If the secondary main breaker can be included in the differential relay’s zone of protection, then all of the components of this breaker benefit from the enhanced protection of this scheme. Additionally, secondary circuit overcurrent elements in the differential relay provide backup protection to the secondary main breaker’s tripping unit. If the differential relay has a breaker failure function, then the transformer primary breaker can trip quickly for a secondary breaker trip failure. All of this improves the reliability of protection for the unit substation.

ACCEPTANCE TESTING Unit Substations and their associated components require acceptance and maintenance testing as described in the ANSI/NETA Standards.3, 4. Typical components and associated tests include, but are not limited to: ●● Medium-Voltage Fused Switch: ○○ Visual and mechanical inspections and mechanical operations ○○ Insulation resistance ○○ Contact resistance of contacts, pivot points and primary fuses ●● Liquid or Dry Type Transformer:

○○ Winding resistance testing ○○ Power Factor testing of windings (optional, but recommended) ●● Low-Voltage Circuit Breakers and Switchgear: ○○ Visual and mechanical inspections of both the breakers and switchboard ○○ Insulation resistance of circuit breakers and switchgear bus ○○ Contact resistance of breaker current path (contacts) and switchgear bus ○○ Breaker Trip Unit Testing: – Primary injection of circuit breakers is recommend for acceptance testing – Secondaryinjection with maintenance testing

primary

verification

for

○○ AC over-potential testing of switchgear bus (optional, but recommended) Unit substations that include a transformer differential relay scheme require additional component testing, commissioning, and functional verification of the overall differential relay system. These components require a slightly higher degree of technical competence as well as the expertise of a protection and control (P&C) engineer or technician. Particular components and tests include, but are not limited to: ●● Medium-Voltage Vacuum Circuit Breaker (VCB): ○○ Visual and mechanical inspections and electrical functions ○○ Insulation resistance ○○ Contact resistance of current path and contacts ○○ Vacuum bottle integrity test Technician Pro-Tip on vacuum bottle testing: – In a typical unit substation arrangement, the VCB is fixed and cannot be drawn out for testing. This can present additional challenges during the high potential portions of vacuum bottle testing. – You should expect to have to disconnect associated medium-voltage cable and lightning arresters. Additionally, covers and barriers will need to be removed to gain access to the bus. – Consult the manufacture’s literature for test voltage and duration recommendations. ●● Current Transformers (CT) on the Primary and Secondary of the Transformer:

○○ Visual and mechanical inspections

○○ Visual and mechanical inspections to include polarity dot orientation where accessible

○○ Insulation resistance and polarization index tests of windings

○○ Excitation test (knee point)

○○ Turns ratio testing

○○ Turns ratio testing to include polarity orientation ○○ Injection of primary current to verify:

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Arc-Flash – Completeness of current path to the protective relay – Test switches properly interrupt the secondary circuit without creating an open CT circuit – Relay software settings for CT ratios (e.g., 50 amps of primary current should be indicated as “50 amps” on the relay display) Technician Pro-Tip on CT testing: – Polarity orientation (determined with electrical testing and/ or visual inspection) shall be compared to the substation drawings. As a general rule, these “dots” should be pointed away from the protected transformer (See Diagram 3). – Bring discrepancies to the attention of the appropriate project lead or engineer to avoid unnecessary delays during the commissioning and functional testing portion of the project. – Include as much of the secondary wiring as possible (ideally to the test switch) in the ratio/polarity testing. This will help to identify and eliminate wiring errors between CT and relay. ●● Differential Relay Testing: ○○ Obtain and review the relay settings in the appropriate software version for the selected relay ○○ Program relay and begin with current metering checks of the primary and secondary CT circuits ○○ Conduct pick-up and timing tests of applicable protective elements: ○○ Restrained and unrestrained differential elements as well as through fault testing – Over-current elements (High and Low side elements) ○○ Verify that relay inputs work and are activated by the designated device(s) ○○ Verify that relay outputs work and operate the designated devices. This includes actually tripping lockout devices (86) and circuit breakers Technician Pro-Tip on Input/Output Testing: – Avoid using a jumper to simulate inputs and outputs. Find a method that proves the circuit(s) in the most “real world” situation as practical There are several key points that need to be considered when performing acceptance tests on a transformer differential scheme. These include CT ratios, polarities, and locations. The CT ratios are critical for the relay to appropriately calculate the secondary current being provided by the primary and secondary CT’s and in turn, performing the per-unit current differential calculations. An incorrect value entered in the relay settings could result in a misoperation of the relay when the transformer is under normal load. CT nameplates should be compared against shop drawings and relay settings. It

is also important to verify the CT polarity by checking the polarity marks on the CT’s as well as the physical orientation of the CT’s. If the polarities of the CT’s are wrong, then the vector summation calculated by the relay will indicate that there is differential current where none truly exists. This could lead to false tripping of the relay when the transformer is under normal load. Major components of the overall unit substation are often not manufactured or assembled in the same location. The primary breaker, transformer, and low-voltage substation sections will never be coupled together as an entire unit until they are assembled in the field. This means large portions of the differential relay’s current circuit and control circuit wiring will have to be field-installed. The opportunity for an initial factory quality check is then eliminated. Relay test currents should be injected at the CT secondary test switches in order to prove that CT phasing and polarity are maintained throughout the current circuit. This should include pickup and trip tests as well as through-fault tests of the relay.

FUNCTIONAL AND SYSTEM COMMISSIONING: The final and most critical step of a differential relay installation is the functional and system commissioning checks. Even if you take every effort to verify CT ratio and orientation and test the relay by injecting test current at the appropriate shorting terminal blocks or test switches, inevitably problems could still exist. Take the following steps to eliminate any potentially remaining or hidden wiring issues: 1. Simultaneously inject primary test currents through the primary and secondary CTs at the correct magnitude and phase angle (typically 30o out of phase for a delta/wye transformer) ○○ Use the relay metering function to verify that the differential operating current is 0.0 amps and the appropriate restraint current (these values can be calculated but that is beyond the scope of this paper) 2. Energize the substation with the protective relay active and all low-voltage breakers open 3. Close the secondary main circuit breaker 4. Review the relay metering to verify that operating current is 0.0 Amps (at this point you should have no restraint current) 5. Disable the relay differential trip output (typically with a test switch) 6. Select and close a feeder breaker(s) that will place load current on the substation 7. Monitor the relay metering and verify that the operating current remains at 0.0 amps and that you begin to see some level of restraint current 8. If you get the results in step 7, then you have completed the commissioning of the system. Should you see operating current (even as little as 0.1 Amps) you have troubleshooting to perform. Continue to step 9.

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Arc-Flash 9. Use the relays metering functions to view the phase angles. Typical phase angles will be 150o out of phase for a delta/ wye transformer. If all phases are at the appropriate angle for your transformer configuration then go to step 10.

The transformer nameplate should be reviewed when confirming phase orientation and winding configurations. All transformers are not wound alike! Special attention should be paid to the polarity of the primary and secondary windings. Three-phase delta and wye configurations, with differing polarities, will result in a difference in the phase-shift from primary to secondary currents. Relay settings that account for this phase shift must be verified in order to continue this trouble shooting. 10. R  eview the magnitudes of the metered current and verify that they match the calculated values for primary and secondary transformer currents 11. M  ake the required wiring changes or relay software changes to correct any problems found

Technician Pro-Tip on Differential Operating Current: ●● N  ever, ever, assume that a “little bit” of operating current is not a problem. The only acceptable value of operating current is 0.0 amps! Microprocessor-based, solid-state transformer differential relays are capable of selectively operating for true fault conditions and restrain operating for magnetization inrush, harmonic distortion, or CT saturation. This can also make setting the relay more complicated. In these cases, it is important to note where the secondary CT’s are physically located. If they are located in the breaker cubicle of the secondary main breaker, then the unit substation CPT could also be included inside the relay’s zone of protection. This will normally only be connected to two phases, which means the relay settings will have to be carefully adjusted to account for load current to the CPT.

CONCLUSIONS With more and more emphasis on electrical safety in industrial environments, and especially as it relates to arc-flash hazards, transformer differential relay schemes are becoming more popular. Not only is this scheme an extremely effective method for mitigating transformer arc-flash hazards, it provides several other benefits in terms of protection and reliability of the entire unit substation. Electrical test technicians need to be familiar with the operation and control of the overall system in order to safely and effectively test and commission the equipment associated with such a protection scheme.

REFERENCES “ARTICAL 130: Work Involving Electrical Hazards, Table 130.7(C)(15)(A)(a), ‘Arc-Flash Hazard Identification for Alternating Current (ac) and Direct Current (dc) Systems’,”

in 2015 NFPA 70E: Standard for Electrical Safety in the Workplace: 70E-35. “ARTICLE 130: Work Involving Electrical Hazards, Paragraph 130.7 (A), ‘Personal and Other Protective Equipment’,” Informational Note No. 3, in 2015 NFPA 70E: Standard for Electrical Safety in the Workplace: 70E-30. “INSPECTION AND TEST PROCEDURES,” in 2013 ANSI/ NETA Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems: Section 7. “INSPECTION AND TEST PROCEDURES,” in 2011 ANSI/ NETA Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems: Section 7. Randall Sagan earned his Electrical Engineering degree from the University of Kentucky. Upon graduation, he worked as a relay engineer at Kentucky Utilities, then became a facility electrical engineer at Toyota Motor Manufacturing. In 1994, he joined the groundbreaking design team at Mercedes-Benz U.S. International (MBUSI) where he currently serves as Electrical Engineer in the Factory Planning Department. Randall recently designed and implemented the safest medium-voltage switchgear in any Mercedes-Benz facility worldwide. Randall is a Senior Member of the IEEE, a member of the Association of Energy Engineers, NFPA, and NETA. He has served as a Ballot Pool Member for the ANSI/NETA Standards for Acceptance Testing, Maintenance Testing, and Electrical Commissioning Specifications. In addition to teaching and speaking engagements, Randall has presented at numerous technical conferences. Randall retired from running after two marathons and multiple half-marathons. Kayaking and hiking have now become some of his favorite activities. He also finds cooking, theatre, and college sports great diversions to his busy schedule. Mose Ramieh III is a Texan, University of Texas graduate (BA) and former US Navy Lieutenant, Mose Ramieh knows a thing or two about getting things done. He is the Manager of Business Development for the Southeast for CE Power and has over 20 years in the electrical testing and maintenance business. Over the years, he has held numerous technical and management positions in the industry and in the US Navy. In 1997, Mose joined PGTI eight months after it was founded. The company served industrial and utility customers in Tennessee and the greater Southeast market. Last year, he was instrumental in the company’s transition to CE Power. He is a certified NICET Engineering Technician, NETA Level IV Technician, Level II Thermographer and a Steam Engineer with Turbine Endorsement (Los Angeles, CA). He has served on the NETA safety committee and is currently a SME for the NETA exam development and CTD Reviewer. Mose is a master at using simple processes to solve seemingly complicated problems, leading and teaching others to do the same.

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SAFETY ASPECTS OF BREAKER PROTECTION AND COORDINATION NETA World, Fall 2013 Issue Bruce M. Rockwell, P.E., American Electrical Testing Co.

OVERCURRENT COORDINATION Compliance with arc-flash hazard work rules, as defined by OSHA, NFPA 70E, Standard for Electrical Safety in the Workplace, and NFPA 70, National Electrical Code, requires evaluation of arc-flash hazards and subsequent posting of the hazard on electric equipment. The arc-flash hazard can be dramatically affected by the overcurrent protective device settings. Faster response and trip times can significantly reduce the hazard. Acceptance and periodic maintenance testing serve to confirm the arc-flash hazard analysis predictions based on NFPA 70E and IEEE 1584, Guide for Performing Arc Flash Hazard Calculations. This article reviews protection schemes and application methods that can be applied to enhance time-overcurrent (TOC) protection to improve safety, such as: directional overcurrent, bus differential, partial differential, zone interlocking, blocking, and other schemes. Historically, TOC settings that were once acceptable to protect equipment are no longer suitable as they may not provide adequate protection of personnel. More recent changes in worker safety standards challenge protection professionals to further optimize settings. Advances in protective device technology allow application of enhanced protection that can reduce fault clearing time without compromising selective coordination or sensitivity. Changes in industry practice are also driving change. The decision to remove instantaneous protection settings was widely adopted in the 1980s and 1990s by some utilities as a means to stop customer complaints for blinking digital clocks. Today, where continuity of service is critical to business operations, the application and use of the instantaneous function is a very important consideration. In 2011, the NEC added article 240.87 in an attempt to address increased hazards on power systems that operate without instantaneous protection. Basic TOC protection coordination operates based on a timecurrent curve (TCC). Multiple TOC protective devices, connected in series, are generally applied to protect the power system. TOC elements may have fixed response curves or may require selection of one or more current and time-delay pickup setting pairs: long time, short time, and ground fault that allow piecewise continuity of various time bands and selection of multiple response curves. The time delay associated with the TOC element can produce a slower-than-desired response since it is applied for protection over a wide range of fault current values.

Identifying faults sooner or sending a trip signal faster can reduce arc-flash hazard energy during faults. The goal is to reduce I2T by responding quicker to reduce the time and/or quick enough to reduce the fault current. An understanding of the available fault current(s) should be sought prior to engaging work, such that the desired range of settings or number and type of schemes to be applied can be fully considered. This can be accomplished by preparing or reviewing an existing short-circuit study. Industry standards recommend an updated study every five years. Bolted three-phase and line-ground faults, as well as reduced fault currents that may occur from arcing faults, should be considered. Being able to recognize the possible range of fault current values and how they affect trip-time response and production of arc-flash energy is necessary to work safely.

The following information should be obtained prior to working on a protection system: ●● Bus Configuration and Operational Sequence ●● Desired Protection Scheme ●● Minimum Three-Phase Fault Current ●● Maximum Three-Phase Fault Current ●● Minimum Line-to-Ground Fault Current ●● Maximum Line-to-Ground Fault Current ●● C  urrent Transformer Location, Ratio, Accuracy Class, Saturation Curve ●● Relay Type and TCC’s ●● Setting Calculations For some protection schemes, such as some of the differential schemes, unequal performance of CTs is important to define, as an offset will need to be applied to the settings. Modern relays tend to eliminate this concern; thus, it is important to understand that all differential schemes are not created equal.

PARTIAL DIFFERENTIAL SCHEME This scheme may also be referred to as a bus overload or selective backup scheme. It is considered a variation of the differential scheme, yet one or more circuits are not included in the phasor summation of current to the relay. This scheme is typically applied for differential backup, primary protection for stations with fused feeders, and local backup protection for feeder circuit breakers.

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One such scheme is shown in Fig. 1. In this scheme, only the sources are differentially connected using a high set TOC relay. The CTs protecting the feeders are not included. Sometimes this scheme is applied to save on the cost of CTs. This scheme provides TOC bus protection with feeder backup protection. The sensitivity and speed are not as good as a differential scheme. In modern multifunction numerical relays, this scheme can be applied using communications to apply protection to the source and feeder breakers. Feeders can be equipped with nontripping

low-set instantaneous time overcurrent (IOC) set just above the maximum load. The sources have IOC with a slight delay set above the maximum load of the bus and use status inputs from the feeder breakers. For a feeder fault, the low set IOC operates and sends a block to the source relay. The IOC of the source relay operates but does not trip due to blocking. The TOC element for the source breaker is not affected and the backup protection remains active.

Fig. 1: Partial Differential Scheme For a bus fault, the block signal is absent and the source breaker trips at high speed. Some schemes use distance relays to achieve faster and more sensitive operation than the TOC scheme.

DIFFERENTIAL SCHEMES There are many types of differential schemes. Here we will consider the following differential schemes: Bus differential with TOC relays, improved TOC, comparator, multirestraint, and high impedance.

Bus Differential with TOC Relays This scheme uses TOC relays. A typical scheme is shown in Fig. 2. CTs are connected in parallel with the relay. Aux CTs can be used to match ratios, but should be avoided in this scheme. A critical issue for setting the relay is that the maximum CT error for a fault (phase and ground) needs to be established. Also, the time delay selected needs to be set, such that it delays tripping if CTs are saturated by the dc component of the primary current. To achieve this, the CT primary rating is selected, such that the maximum external fault current magnitude, If , is less than 20 times the CT rating; and for this fault value, the CT burden can be no more than its relay accuracy class voltage divided by 100. The relay operating time cannot be less than three primary time constants and the current pickup setting should be greater than the

exciting current of the CT for If . Typical settings are a current pickup of 10 amperes or more and a time delay not less than 18 cycles. This scheme is not suitable for expensive systems or for enhanced safety. Faster tripping for this scheme is achieved by applying TOC relays with extremely inverse TCC response. This allows for relay trip times of eight cycles.

Improved Bus Differential Scheme with TOC Relays The scheme can be improved by applying a stabilizing resistor in series with each overcurrent relay. If an external feeder fault causes the feeder CT to saturate, the CT excitation reactance approaches zero and the CT error current that flows through the relay can be defined. Applying a resistor to the circuit allows reduction of the CT error and thus improves the scheme sensitivity. This allows for lowering of the current pickup and thus faster relay trip response.

Multi-Restraint Differential Scheme This scheme is very sensitive and secure for external faults, as it addresses the CT error and CT saturation issues. It is reasonably fast and responds well, even when applying auxiliary CTs. It tends to be inflexible in applications where the system may be expanded, as all the circuit wiring needs to be brought back from the switchyard to the relay house.

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This protection scheme uses a TOC relay that incorporates the phase relationship of voltage and current to identify the direction of a fault. Numerical relays use sequential components or quadrature voltage to sense fault direction. They also use memory to address close-into-fault protection where voltage is nearly zero. This protection system scheme, when applied with a numerical relay, can achieve four-to-six cycle trip response time. This relay is sometimes applied with blocking schemes to perform sequential tripping. Fig. 2: Bus Differential w/ TOC Relay

High Impedance Differential Scheme This scheme uses a high impedance voltage element instead of a low impedance current element and resistor. This scheme is effective in forcing the CT error current through the CTs in lieu of the relay operating coil. This scheme achieves high speed operation and can respond with a trip signal in 25 milliseconds (1.5 cycles). When using this scheme, an important safety issue is to make sure that all CTs are applied at their full tap position to avoid induced high voltage that can appear on any unused tap positions if a lower tap position is applied.

Differential Comparator Scheme This scheme achieves the fastest trip response speed. It can operate in 9 - 16 milliseconds (1/2 to 1 cycle). This scheme is very secure against misoperation for external faults. This scheme is indicative of the enhanced protection that can be achieved using modern numerical relays. The scheme is shown in Fig. 3.

DIRECTIONAL OVERCURRENT In some medium-voltage distribution systems and most high-voltage transmission systems, faults can occur in two directions. For these systems, the directional overcurrent scheme can be applied for protection. This relay is not useful in a system with only one source.

ZONE INTERLOCKING Zone interlocking schemes are readily available in lowvoltage and medium-voltage trip units and can be easily applied using modern relays. This protection scheme is based on using communication between protective devices to improve (speed up) protection. The scheme also improves selective coordination by applying a blocking signal to delay upstream tripping. Downstream devices communicate with upstream devices if the downstream relay detects fault current. The main (disconnect) service trip device is identified as Zone 1, with each level of downstream protection being assigned a new Zone level number. These schemes typically utilize a three- or five-wire system to communicate phase and ground fault conditions in the zones. If a fault is seen by the downstream device and if it exceeds the short time pickup, it signals the upstream device to block high-speed tripping that may occur from the instantaneous setting. If the downstream device fails to trip for a fault, the upstream device will override the blocking signal and trip instantaneously, applying a slight (three cycle) delay. Continuity of power system operations and worker safety are competing objectives when designing power system protection schemes and applying device settings. Modifying protection schemes and / or applying newer technology allow the designer to improve protection to enhance safety. This improved safety is achieved by the application of faster responding protection schemes and devices as well as taking advantage of the multiple protection elements and logic in numerical relays. Communication features are also available to enhance protection schemes by using logic that can apply blocking signals or release blocking signals to further enhance speed, selectivity, and reliability of protection system operation. Bruce Rockwell, P.E. has been Director of American Electrical Testing’s Engineering Division for the last nine years. He has over thirty years of business development, management, construction and engineering experience; specializing in the T&D utility sector. Bruce holds an MBA from Monmouth University and received his BSEE from New Jersey Institute of Technology. Bruce is a Certified Co-Generation Professional with the Association of Energy Engineers and a Continuing Education Instructor for the State of New Jersey.

Fig. 3: Differential Comparator

32

Arc-Flash

ARC-FLASH MITIGATION USING DIFFERENTIAL PROTECTION NETA World, Winter 2014 Issue Brian Cronin, CSA Engineering Services, LLC With the revision of the NFPA 70E, the Standard for Electrical Safety in the Workplace, one thing remains constant: the risk of an arc-flash hazard will need to be performed. Although the risk hazard tables are presented in a different manner with the latest revision of NFPA 70E, one of the goals to this analysis will continue to ensure the proper personal protective equipment (PPE) is used under specific conditions. When performing arc-flash hazard calculations, all factors must be included to accurately predict the incident energy. Some of these factors include short-circuit current, fault clearing time and worker distance to source. The procedures set forth in IEEE 1584, Guide to Performing Arc-Flash Calculations, are most commonly used in calculating incident energy and the arc-flash boundary. The basic formulas presented in IEEE 1584 are as follows: Where E: Incident Energy [J/cm2]

E=4.184CtEn

DB= 4.184Cf En

Ct: Calculation Factor En: Incident Energy Normalized

t: Arcing Time [sec]



D: Working Distance [mm]

DB: Arc-Flash Boundary [mm] EB: Incident Energy at Boundary [J/cm2] Upon inspection of these equations, it can be seen that the arcing time will directly affect the incident energy and, in almost all cases, have a direct effect on the arc-flash boundary. Since reducing the time to clear a fault directly affects the incident energy, the application of differential relaying should be considered because its operation is independent of any other protective devices, so clearing time is minimized. Although not shown in this equation, the level of fault current will also have a direct effect on the incident energy. The pickup level of a differential relay is typically well below fault current levels, so arcing currents do not tend to have an effect on the trip time of the relay. In an effort to reduce incident energy levels, various methods have been implemented to allow for increased worker safety. The method that should always be considered first is to perform work on de-energized equipment; however, this is not possible in all cases. A system available from several manufacturers applies a temporary low level instantaneous overcurrent device to reduce

the fault clearing times; however, these devices tend to reduce or eliminate coordination between adjacent protective devices. Differential relays are high-speed protection devices. Because current through the differential relay is nearly zero for all conditions, except for a fault in its zone of protection, it can be set to be much more sensitive than a fast instantaneous overcurrent device and not affect coordination and can also remain in service under all conditions. The effectiveness of differential relaying is often overlooked when evaluating arc-flash hazard. Other methods to improve worker safety include increasing worker distance to the arc source with the use of remote control and remote racking equipment. The application of differential protection provides improved coordination and arc-flash hazard mitigation. A typical system depicted in Fig.1 shows a 1500 kVA transformer supplying low-voltage switchgear. Fig. 2 graphically illustrates the coordination of typical protective devices found on a system of this type. Ideally, the feeder breaker, for example CB3, should operate to clear a fault before the main circuit, CB2. To allow for coordination, the main circuit breaker protection must be delayed to allow for the feeder breaker to clear a fault. This time must be increased as more protective devices are installed in series. Many applications apply an instantaneous element on the main circuit breaker, but the application of instantaneous protection on the main circuit breaker prevents coordination with downstream devices for fault levels above the pickup setting. To ensure coordination, the delay set on the main circuit breaker typically leads to a dangerous arc-flash condition. A bolted fault of 29.7 kA would be typical for the system shown in Fig. 1. Applying the incident energy calculation for a fault with bolted fault current of 29.7 kA, arcing fault current of 15.6 kA, and a clearing time of 1.9 seconds, values typical for the system shown in Fig. 1, results in an incident energy value of 273 J/cm2. PPE ratings are typically in units of cal/cm2 . Converting the metric 273 J/cm2 yields a value of 65 cal/cm2. This is considerably greater than the 40 cal/cm2 level, above which the NFPA 70E indicates that there is no safe level of PPE available. If a temporary instantaneous setting is applied during periods of maintenance, the arc-flash hazard can be reduced to a Category 2 because the operating time is reduced to about 80 msec. During this period of maintenance, the arc-flash hazard is reduced; however, there will be a loss of coordination with downstream protective devices. While procedures will be written to turn on and turn off this temporary setting, human error may prevent either its use or prevent coordi-

33

Arc-Flash nation during normal conditions, if the temporary setting remains after maintenance is completed. Also, the unanswered question that remains at many facilities is, “How is the equipment to be labeled?” The use of a differential relay in this application would reduce the incident energy to 5.2 cal/cm2 and would not be required

Fig. 1: Basic One Line ential relays could be used to protect the zones individually. When the transformer is included in the zone of protection, the effects of the phase shift and voltage difference must be incorporated into the application of the relay. When selecting current transformers (CTs), the classical approach would require the available fault current not to exceed 100 amperes (20x nominal) on the CT secondary and the connected burden be less than the rated burden. This approach does not take time to saturation into consideration. With the use of numerical relays, the burden on the CT in a differential relay is significantly less than an electromechanical relay, but CT secondary winding and cable impedances remain the same. Care must be given when selecting the CT to avoid saturation. If the transformer and bus are protected as a single zone, a set of CTs must be installed on the transformer pri-

to be switched in and out of service. Additionally, the traditional reason for using a differential relay applies, which limits the damage caused by the fault due to the reduced clearing time. Depending on the application, a single differential relay could be used to protect the transformer and the bus or two separate differ-

Fig. 2: Time-Current Curve mary and a set of CTs must be installed on each feeder, as shown in Fig. 3. In Fig. 3, an internal fault is marked by F1 and an external fault is marked by F2. If a fault occurs at F1, a differential relay will clear the fault without intentional time delay, much like a temporary maintenance setting. However, should a fault occur at F2, the differential relay will restrain and not operate, where the maintenance setting will not be able to distinguish between an internal and external fault, causing an unnecessary outage to the entire bus. Also, under normal conditions, the damage of fault F1 is minimized when differential protection is applied because it can clear a fault much quicker than the time delayed overcurrent protection on the secondary main. Differential protection can be summarized by understanding that the current into the zone of protection must equal the outgoing cur-

34

Arc-Flash

rent or else an internal fault exists. Again, referring to Fig. 3, for a fault at F2 current flows through the high side CTs (CT1) and also flows through the feeder CTs (CT4); CT4 provides the balance current that allows for the relay to restrain – essentially the input current matches the output for a result of zero. For a fault at F1, current flows in CT1; however, no current flows out of any other CT, so the relay has no restraint. Should a power source from any of the feeders be present, the direction of current from the feeder is reversed, so the relay will see additional current, not less current. The direction of the CT and its wiring are often the cause of differential relay misoperation, so it is important that the installation of the differential relay is correct and verified during acceptance testing. When numerical relays are used, internal settings can compensate for the different CT ratios and the phase shift in the transformer. When an electromechanical relay is used, taps are available to adjust for the difference in the CTs and the CT wiring must adjust for the phase shift. It should be noted that the above description is based on low impedance differential relays. High impedance relays are typically not suited to include a transformer in its zone of protection. Differential protection has not typically been applied to transformers less than 10 MVA, unless there was some critical im-

portance. This size limitation is mostly due to the cost-benefit relationship to the use of differential protection. Worker safety is an intangible aspect of the cost-benefit analysis. Due to the relatively low number of worker injuries that could have been prevented with the installation of differential protection, it is difficult to make an argument using a cost-benefit basis; however, the cost associated with electrical injuries is also difficult to quantify. The transformer identified in Fig. 1 is typically protected using three single phase fuses. Depending on the specifics of the application, the installation of a three phase fuse may cost $25k. This is far less than the cost to install a medium-voltage circuit breaker, CTs, a relay, and all other required control work. The circuit breaker, or similar device, may have the added advantage of protecting against single-phasing conditions. The differential relay may be able to clear certain faults that cannot be isolated by high-side fuses. Fuses do not have metering and monitoring capabilities like numerical relays, so certain operational improvements are available with the installation of relay based protective systems. Maintenance costs are also greater for relay based systems than fuse protection. Relays, CTs, circuit breakers and batteries require significantly more resources for maintenance than fuses. Also, the

Fig. 3: Relay One line

Arc-Flash cost to repair or replace a small transformer or switchgear may not be significantly different if the system is protected by fuses or relaying. Where coordination is paramount, the installation of differential protection has merit. If the only purpose of installing the differential relay is to reduce arc-flash levels on the secondary bus, there would be no need to install a high-side circuit breaker. Tripping the low-side main would perform the same function at a substantial cost reduction. In considering the coordination in Fig. 2, one can see the fuse is not fully selective with the low-voltage circuit breaker. This condition is often required because the upstream fuse must coordinate with the transformer fuse or else an even larger outage could occur unnecessarily. Since the operation of the transformer fuse and the main circuit breaker will result in the loss of the same load and coordination requires compromise, this area offers a good point of compromise. A drawback to this sort of compromise is seen when trying to determine the location of the fault. If the fuse operates, it is assumed the fault is between the fuse and the main circuit breaker; however, when coordination is not fully selective, the device upstream may operate faster than the downstream device, which can lead to confusion. R1 in Fig. 2 represents a relay curve, which can be set to better conform to the characteristics of the downstream device. If transformer and bus differential protection are provided, coordination with adjacent protective systems becomes less troublesome because the differential protection acts to clear the fault without any unnecessary time delay. Although coordination will still be required with backup protection, more compromise between protective devices can usually be found when using differential protection. Overcurrent protection using fuses is a far simpler and less expensive approach than the installation of a relay system; but the added benefit of a relay system should be understood. With respect to arcflash hazard, differential protection will reduce the incident energy relative to time-delayed overcurrent protection. When considering coordination, numerical relays offer a superior alternative to fuses because of the myriad of possibilities to shape the protective characteristic. The added metering, monitoring, and recording features of a numerical relay can provide tremendous operational information, which may be a feature to include in the cost-benefit analysis. Zone Interlocking offers a similar alternative to differential protection, but performing primary simulation can be cumbersome. Maybe not every 1500 kVA transformer should have differential protection, but given equipment available today and its capabilities, it may be prudent to consider the 10 MVA limit as too high.

35 Mr. Brian Cronin, PE is the President of CSA Engineering Services, LLC. and has extensive control and protection engineering experience, both as a Senior Protection Utility Engineer for a privately owned electric utility and as a field applications engineer/ business development manager for a major OEM. Mr. Cronin holds a BEE from Manhattan College, an MBA from New York Institute of Technology. Additionally, he is a registered professional engineer, a member of the NYC Electric Code Interpretation Committee, a member of IEEE, and a member NFPA.

36

Arc-Flash

METAL-ENCLOSED MEDIUM-VOLTAGE AIR SWITCHES: CONDITION ANALYSIS AND HAZARD AWARENESS NETA World, Spring 2016 Issue Scott Blizard and Paul Chamberlain, American Electrical Testing Co., Inc. When performing a condition analysis on medium-voltage air switches located in metal-enclosed switchgear, the person performing the task must be aware of all potential hazards. Furthermore, the individual must be qualified to perform the task and also have a solid understanding of each hazard and ways to mitigate those hazards. To better understand the hazards involved with the analysis, testing, and maintenance of metal-enclosed, medium-voltage air switches, take a look at what sources contribute to each hazard.

LOCK OUT/TAG OUT OF ELECTRICAL AND MECHANICAL ENERGY Prior to performing work on any electrical equipment, it must be de-energized and locked out to prevent inadvertent re-energization. Failure to properly perform lock out/tag out when performing maintenance on metal-enclosed, mediumvoltage air switches contributes to many injuries. Controlling the electrical energy of the air switch is the first and most obvious hazardous energy source that could cause injury. Prior to the start of a lock out/tag out procedure, review the electrical drawing and the arc-flash study to identify the personal protective equipment (PPE) required during isolation. Additionally, the task performer must identify the type of switch to be serviced and the electrical source(s) to be deenergized when isolating the switch. Be aware of the air-switch compartment layout. Mediumvoltage air switches come in several configurations, and the task performer must ensure that the line side of the switch is properly identified. Do not bypass interlocks or keyed systems. Secure the proper instruction manual for the make and model of the equipment prior to starting work. The air-switch operating compartment may be isolated, meaning that the operating devices may be located in one compartment while the air switch is located in a different compartment. During this step, electrical and mechanical energy are potential hazards, depending upon the type of air switch involved. Electrically de-energize the air switch from its primary energy source, and ensure that the air switch is disconnected from all sources of power, including control voltage sources, if applicable. Once de-energized, verify that the air switch is at a zero-energy state using the manufacturer’s approved method. Verify the accuracy of the detection or voltage measuring device

against a known source, then check for zero energy on the de-energized equipment, and test the detection equipment against a known source again. This will verify that the testing device was functional during the check for voltage. Testing for voltage requires its own level of PPE, depending on the voltage and equipment type per the tables in NFPA 70E 2015 or OSHA 1910.269, “Appendix E.” Determine which is applicable for the installation, whether commercial or utility, based on where the work is being performed. For example, in the NFPA 70E, use “Table 130.7(C)(15)(A)(b)–Arc-Flash PPE Categories for Alternating Current (ac) Systems.” This table will tell you whether arcflash protection is required based on the equipment condition and the task to be performed. If it is determined that arc-flash protection is required for the task, then reference “Table 130.7(C)(15)(A)(b)– Arc-Flash PPE Categories for Alternating Current (ac) Systems” or “130.7(C)(15)(B)–Arc-Flash Hazard for Direct Current(dc) Systems,” whichever is applicable. These tables will identify what level of arc-flash protection is required for the task as well as the arc-flash boundary. Performers can then reference “Table 130.7(C) (16)–Personal Protective Equipment (PPE)” to ensure that they are performing the task using all the appropriate PPE. Additionally, rubber gloves, sleeves, insulated tools, and other rubber goods may be required during the isolation procedure. These specialized pieces of PPE and other equipment must be rated for the voltages worked with and tested per the applicable ASTM Standard. However, electrical energy isn’t the only energy that requires lock out/tag out. The air switch may contain a large amount of mechanical energy. This energy must be dissipated prior to servicing or serious injury could occur. Once the air switch has been discharged, lock out/tag out the charging mechanism, if feasible. In the case of a motor-operated switch, ensure that remote operating handles are tagged in a local or manual mode. This will prevent someone from inadvertently operating the air switch. For motor-driven operating systems, make sure the motor has been locked out or disengaged prior to starting work.

37

Arc-Flash OTHER PHYSICAL HAZARDS Gravity is also an energy that needs to be controlled. The size and weight of a medium-voltage air-switch panel cover can be heavy and awkward to remove prior to performing maintenance; therefore, take proper precautions. These may include getting another person to aid in removal of the panel or removing by mechanical means.

INSTALLATION OF TEMPORARY PROTECTIVE GROUNDS Refer to OSHA (29 CFR 1910.269) and NFPA 70E for specific guidance on grounding locations and sizing of grounds required for the task. Grounds must always be applied upstream and downstream of the equipment and as close to the work as possible. Always ensure that work is done between the grounds and that you remove them once the work is complete.

PROPER PERSONAL PROTECTIVE EQUIPMENT Prior to beginning any work, verify that the metal-enclosed medium-voltage air switches are electrically de-energized; in some cases, this may be accomplished through remote operation. Ensure that proper PPE is used for the class of air switch serviced or any adjacent energized equipment. Adjacent equipment may require different levels of PPE if the work is performed within its limited approach boundary. Refer to the three applicable tables in the NFPA 70E 2015 or to OSHA 1910.169 Appendix E again. It will indicate the level of protection required and will aid in preventing electrical shock and protect personnel from arc flash. However, this table provides information based upon known values of the short-circuit current available, the clearing time in cycles, and minimum working distance. If those factors are unknown, more information must be gathered prior to performing the work to ensure personnel safety.

CHEMICAL HAZARDS Some lubricants and cleaners may pose a respiratory and skin irritant if used in enclosed areas or on bare skin. Knowledge of the material, reading its label, and checking the Safety Data Sheet (SDS) is advised to identify any potential health effects from its use. Once again, use of proper PPE is necessary for using some cleaners and lubricants. For example, nitrile gloves, safety glasses, face shield, and even respiratory protection may be needed.

HUMAN ERROR MITIGATION Simply put, human error is a person (or persons) making a mistake. To prevent an error, follow a procedure or checklist while performing the task. If one doesn’t exist, create one. Nomenclature should be verified, and re-verified upon approaching a piece of equipment. Perform a self-check and a peer-check to ensure that the task is being performed on the correct component.

When working around similar-looking pieces of equipment, use markings such as flagging to identify the components that should not be touched. Flagging can take several forms, depending upon the company or client’s policy and procedures. Do not forget to identify, mark, then lock out/tag out all associated equipment (e.g. associated cables and compartments). Flagging could be used to indicate a component that is not operating normally. Barricading off a safe work zone prevents other workers from inadvertently entering the work area. This will ensure that maintenance and testing is conducted in an area under your control. Use a test stand in this area, if applicable. Ensure that any control voltage required to operate the switch during testing is within the secured area.

CONCLUSION There are many potential hazards to watch out for when performing maintenance and testing on metal-enclosed mediumvoltage air switches: ●● Obtain all service bulletins, maintenance documents, arcflash studies, and manuals prior to beginning work for that specific device. ●● Review all prints and one-lines associated with the equipment. ●● Establish a safe work area, and barricade off the work area. ●● Perform a pre-job brief with all employees on site. ●● Wear proper PPE. ●● Disconnect any control circuits and test equipment before performing visual or mechanical inspections or during maintenance. ●● If applicable, verify zero energy (test, check, test) and discharge all stored energy. ●● If possible, lock out/tag out (mechanical and electrical energy sources). ●● Connect grounds where, and if, applicable; ●● Identify, visually mark, and/or flag the equipment worked on. Following these steps will lead to a safer work environment while performing maintenance and testing of metal-enclosed medium-voltage air switches. Scott Blizard has been the Vice President and Chief Operating Officer of American Electrical Testing Co., Inc. since 2000. During his tenure, Scott acted as the Corporate Safety Officer for nine years. He has over 25 years of experience in the field as a Master Electrician, Journeyman, Wireman, and NETA Level IV Senior Technician. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

38

Arc-Flash

ELECTRICAL HAZARD FACTS NETA World, Winter 2013 Issue James R. White, Shermco Industries, Inc.

INTRODUCTION The Bureau of Labor Statistics reports that before OSHA was created in 1970 there were some 14,000 job-related fatalities annually, with 2.5 million disabling injuries. In 2011, there were 4,693 fatalities in the workplace, while there were 908,300 losttime injuries. The workforce has more than doubled in size since 1970, which means the rates for fatalities and injuries has dramatically fallen since then. As an example, the 1980 fatality rate was 7.7 per 100,000 workers; in 2011 it was 3.5 per 100,000 workers. Even though that decrease is very significant, one might choose to look at these statistics in another way: 4,693 workers were given capital punishment for the crime of going to work. When it is put in those terms, this statistic doesn’t sound nearly as good, does it?

PRE-1996 ARC-FLASH PPE INADEQUATE The three primary hazards of electricity have been well known for decades. The hazard of electrical shock has been known since the first electrical devices were designed in the 1800’s. Arc flash and arc blast have also been recognized, but due to the inability to quantify these two hazards, there was nothing that could be done to effectively protect the worker from them. In the late 1980s, the first arc-flash suits began to appear. Most were made from NOMEX® and used polycarbonate windows. It was found later that the polycarbonate windows would actually fail at a very low value of incident energy, causing the window to melt. Figs. 1a and 1b show an example of the early, unrated arc-flash PPE and clothing. One tip-off is the clear window in the hood. The other is the lack of required markings, “ATPV, ASTM F1506”1 and “NFPA 70E”2 on the label.

This type of flash suit is still used by uninformed technicians and contractors and presents a very real threat to their well-being. All arc-flash protective clothing and PPE must have a label giving the arc rating and show that it complies with ASTM F1506 and NFPA 70E. If it does not, do not allow the person possessing it to work on or near any electrical power system or device that may be energized. There are arc-rated flash suits that have a similar appearance, but meet the requirements above. These would be sufficient to perform tasks on or near energized conductors and circuit parts. In 1996, the first arc testing of clothing and PPE took place and it was soon discovered that the existing PPE and clothing were inadequate, especially for higher values of incident energy. As the industry was then able to determine the hazard created by an electrical arc flash, protective equipment was designed to provide that protection, and NFPA 70E (in the 2000 edition) provided the first generally available guide to choosing PPE to protect workers from the arc-flash hazard. In this author’s opinion, “Table 130.7(C)(9)(a)” [now “130.7(C)(15) (a)”] did more to increase workers’ awareness of the arc-flash hazard and how to protect themselves than any other single factor. Advancements have been made, both in our understanding of the arc-flash hazard as well as how to design more effective PPE and clothing that provides a higher level of protection and is more comfortable to wear. This includes lighter weight arc-flash clothing and arc-rated windows and face shields and hood windows that have better light transmission through them. These two factors have increased the acceptance by workers of the provided arcrated PPE and clothing and have encouraged their usage.

THE HAZARDS OF ELECTRICITY The three recognized hazards of electricity are shock, arc flash and arc blast.



Fig. 1a

Fig. 1b

The Department of Labor estimates that there are 4,000 nondisabling and 3,600 disabling injuries in the workplace due to electrical shock each year. A nondisabling injury is one which is a lost-time injury, but the person can return to work doing his/ her normal job. A disabling injury means the person either could not return to work or could not return to work in the position held prior to the injury. Another 2,000 traumatic electrical burn injuries are estimated to occur each year. The term traumatic indicates that there is a second-degree burn on more than 50 percent of a person’s body. The DOL figures mean that there are approximately 10,000 serious injuries from electrical shock and arc-flash events each year. Arc-blast injuries and fatalities are not currently tracked by OSHA or the Bureau of Labor Statistics.

39

Arc-Flash THE ELECTRICAL SHOCK HAZARD When exposed, energized electrical conductors or circuit parts are contacted by an unprotected part of the body, electrical current flows through the person to either ground or some nearby grounded object such as a metal enclosure. Phase-to-phase contact is rare, but substantially increases the shock hazard and injury. The pathway the electrical current takes through the body plays an important part in determining the seriousness of the resulting injury. The most common pathway is from the hand to the foot followed by hand-to-hand contact. Head-to-hand or head-to-foot contact is much less likely, but since the electrical current passes through the stem of the brain, serious injury can occur at much lower voltages.

The Most Recent Available Data ESFI (Electrical Safety Foundation International) updated a CDC/ NIOSH study of electrical shock injuries and fatalities over a tenyear period. (See Fig. 2.) The event that causes the greatest number of electrocutions in the workplace is contact with an overhead power line (42%), followed by contact with transformers, wiring or other electrical devices (26%), and contact with machines, tools or appliances (16%). In the event category of contact with overhead power lines, approximately half of those fatalities were from cranes, bucket trucks, and other types of mechanical equipment making contact. The other 50 % is from people making contact by long dimensional objects such as conduit or making accidental contact during the performance of their job duties. It is clear that the three major causes of electrocution have remained virtually unchanged during this period of time. (See Fig. 3.) 3

Fig. 3 In a study conducted by CDC/NIOSH on just electrical workers, it was found that 24% of the lost-time injuries/fatalities were due to troubleshooting and voltage testing activities, while 19% of the recorded events occurred during normal operation of electrical machines, tools, or appliances. 18% of the recorded events occurred due to repair or repair-related activities.4 There are several factors contributing to the severity of electrical shock: ●● ●● ●● ●●

Voltage magnitude Current magnitude Pathway through the body Duration

●● Physical condition of person being shocked Electrical current is what actually causes damage to the body. The voltage is the force that pushes the current. As the voltage increases, more current, will flow through the body. This relationship to voltage, current and the body’s resistance is explained through Ohm’s Law, shown below: Current though the body =



Voltage Resistance of Body

The Differences That Electrical Shock Has on Men vs. Women Fig. 2

According to IEEE standard 80, Guide for Safety in AC Substation Grounding, the average resistance of a man’s body is approximately 1,000 ohms. This will vary some (but not much) depending on a person’s weight. For 1,000 ohms body resistance contacting a 120-volt conductor, the resulting current is 120 mA through the body. This current is usually lower, as the most common path is for electricity to flow from hand-to-foot. Shoes, socks, flooring (carpet, wood, tile, and dry concrete) all provide some additional resistance. Women have about 2/3 the body resistance, due to fac-

40

Arc-Flash

tors such as size, bone mass, and body composition. This means that for the same exposure, women face a greater risk of injury from the shock hazard. Instead of having approximately 120 mA current pass through them for a 120-volt shock, they would have approximately 160 mA passing through them. In 1961, Dr. Charles Dalziel presented a paper describing the results of experiments he had conducted on student volunteers at the University of California, Berkeley. The results are summarized in Table 1.5.

mA Current

Effect on Person

These Are All Possible Effects from Low-Voltage Contact 0.5 to 3

Slight Tingling

3+

May Be Painful

10+

Muscle Contractions and Pain

30+

Respiratory Paralysis

75+

Ventricular Fibrillation Threshold These Effects Only with High-Voltage Contact

4+ Amps

Heart Paralysis

5+ Amps

Tissue and Organ Burning

Table 1: Effects of Electrical Current (From Deleterious Effects of Electric Shock, Dr. Charles Dalziel,1961) The second part of the equation is that when shocked, women are more likely to suffer injury, and their injury is likely to be greater than what a man would be expected to receive. Table 2 is also from Dr. Dalziel’s experiments and shows the relationship between ac and dc, as well as men vs. women. Look at the last example effect shown on Table 2, “Shock, Painful and Severe, Muscular Contractions, Breathing Difficult.” A 60 Hz contact with 23 mA of current is required to cause this effect for a man, but only 15mA of current is required to produce the same effect for a woman. Female technicians need to be aware that they are more susceptible to injury than their male counterparts, if they make contact with exposed energized conductors or circuit parts.

Electrical shock kills and injures more than twice as many people each year as electrical arc flash. That being said, arc-flash injuries are often more serious and, on average, require much more hospitalization and recovery time.

ELECTRICAL ARC FLASH An electrical arc occurs when an energized conductor or circuit part makes contact with either a grounded object or, much more rarely, another conductor. Approximately 97% of all electrical arcs begin as phase-to-ground faults. Often the grounded object is a tool or materials being held by a person. Once initial contact is made, the intense heat of the electrical arc ionizes the surrounding air, creating a pathway from the grounded object to the energized conductor or circuit part. If the arc occurs inside a metal enclosure, the arc plasma will reflect off the back and sides of the enclosure, enveloping the other two phases, which may not have been originally involved. This will cause the arc to develop from a single-phase arc to a three-phase arc, substantially increasing the incident energy. If the voltage is less than 240 volts, the arc is usually self-extinguishing, although, if it is fed from a large source, the available short circuit current could establish the arc. At higher voltages, the arc is able to establish itself and will continue until the circuit is de-energized by an overcurrent protective device (OCPD). There are five primary factors that determine the severity of an injury from an electrical arc: ●● The distance from the arc ●● The absorption coefficient of the clothing worn ●● The arc temperature ●● The arc duration ●● The arc length

The Distance from the Arc The heat of an electrical arc is referred to as the incident energy. This is because the heat is made up of the radiated heat (infrared) and convection heat (heat flow through air). Incident energy decreases by the inverse square of the distance. In other words, as a person moves away from an arc, the heat will decrease rapidly. This aspect is critical to understanding how to protect oneself from an arc. Body position is a primary factor to consider when performing energized work. One should stand no closer to the device than necessary in order to perform the work effectively because the incident energy that person will receive, if there is an arc-flash event, increases as one moves closer to the device. The standard working distance for power systems of less than 600 volts is typically 18”, while that of 2.4 kV to 15 kV is a 36” working distance.

The Coefficient of Clothing Worn Table 2: Effect of Electrical Shock; Men vs.Women (From Deleterious Effects of Electric Shock, Dr. Charles Dalziel,1961)

The type and fabric weight of clothing being worn affects the heat that is transferred to the body. NFPA 70E recommends wearing either flammable, non-melting clothing as underlayers (cotton,

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Arc-Flash wool or silk) or arc-rated underlayers for additional protection. The general rule of thumb is that each layer of clothing under arcrated clothing reduces the heat to the body by approximately 50%. Flammable underlayers do not increase the arc rating of a clothing system, but will reduce the probability of a burn underneath arcrated clothing.

The Arc Temperature The temperature of an electrical is arc is significantly affected by the power available to create it (instantaneous power levels in the megawatt range are present within many types of electrical equipment arcs). Other factors include electrode material and shape, length of arc travel, constraints on arc volume, etc.

The Arc Duration The arc duration is the second most critical factor in an arcflash event. Incident energy is proportional to time. If a person is exposed to an arc flash for 0.08 seconds, he would receive twice the incident energy as an arc of the same magnitude that lasted 0.04 seconds. This is why the NFPA 70E technical committee inserted “Section 205.4,” which states, “Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards.” Poorly-maintained circuit breakers and other OCPD are unreliable. If an OCPD malfunctions, it will increase the time it takes to clear and extinguish the fault. Even though this may be only fractions of a second, it can effectively double or triple the incident energy received by a worker.

death by impacting a person’s body. At this time there are no equations to calculate the pressure wave that would be created by electrical arc blast as there are for the arcflash hazard. IEEE and NFPA are conducting a joint collaboration project to develop the needed equations, but those results have not been released as of this date.6 It has been shown that as the short circuit available current increases, the pressure wave also increases. The pressure wave has been measured at greater than 2,160 lb/ft2. At about the same instant in time as the pressure wave is created, an acoustic wave is also created. The acoustic wave is created by the near instantaneous heating of the air surrounding the electrical arc, similar to the way lightning is created. This sound intensity has been measured at greater than 160dB. This level of intensity will cause instantaneous hearing loss.

Current-Limiting Devices – Not a Cure-All Current-limiting fuses have been found to be an effective method of reducing both the incident energy and potential pressure wave by limiting available short circuit current from the system and by greatly reducing the duration of the arc (Fig.4). When properly applied, current-limiting fuses will have a clearing time of less than ½ cycle. Current-limiting fuses cannot be applied in all circumstances, and, if the short circuit current does not push the fuse into its current-limiting region, it will act as a dual-element time delay fuse. Some manufacturers produce current-limiting circuit breakers for low-voltage protection that have similar characteristics as current-limiting fuses.

The Arc Length The arc length becomes a factor at higher voltages (>600 V). It has been demonstrated that, with all other factors being the same, a longer arc creates more incident energy than a shorter arc. Lowvoltage power systems cannot sustain a longer electrical arc, as arc resistance causes a voltage drop of approximately 75 to 100 V/inch.

The Onset of a Second-Degree Burn Unprotected skin has a very low tolerance for heat. A temperature rise of 1760F for 1/10th second will produce the onset of a second degree burn. This is the point at which NFPA 70E requires arcflash protective clothing and PPE to be worn. This level of injury is considered to be non-life threatening as the skin is still mostly whole and not uniformly blistered; therefore, the risk of infection is less than a second-degree burn, which will have uniform blistering.

ELECTRICAL ARC BLAST Electrical arc blast refers to the pressure wave created by the rapidly expanding vaporized metal (arc plasma ball) when an arc occurs inside metal-enclosed equipment. This pressure wave can distort the enclosure, causing it to rupture, create shrapnel from parts and components that are broken loose, and cause injury or

Fig. 4

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SUMMARY In 1999, the 2000 edition of NFPA 70E was released, containing the first method of choosing arc-flash protective clothing and PPE. In 2002, IEEE 1584, Guide for Performing Arc-Flash Hazard Calculations was released. Together, these two standards provide guidelines for companies to protect their workers from the hazards associated with an arc-flash event. The equations developed in IEEE 1584 will be further refined, once the members of the IEEE/ NFPA joint collaboration finish their work. The effects of vertical vs. horizontal bus will further revise the equations used by IEEE 1584, and equations for calculating the effects of a dc arc flash will be available. A solid understanding of the hazards of electricity is important to working safely. OSHA’s electrical safety regulations were written before the hazards of arc flash and blast were as well known as they are today, but they were written in such a way that they are still relevant and enforceable today. Sometimes it seems as though the hazard of electrical shock has been forgotten, or overshadowed by the hazard of electrical arc flash. This is unfortunate, as electrical shock injures and kills twice as many workers as arc flash. This is not to downplay the arc-flash hazard, as the injuries received from an arc flash are often more serious and result in more medical intervention than shock. The important point is that one should neither forget nor minimize either of these life-threatening hazards. The arc-blast hazard is much less understood. The IEEE/NFPA joint collaboration is just now finishing some of the field tests it has been performing. One of i ts mandates was to provide a means of calculating the pressure wave that is likely to be created during an arc event. Until that information is compiled and released, the arc-blast hazard will remain an incompletely defined quantity.

REFERENCES ASTM F1506, Standard Performance Specification for Flame Resistant Textile Materials for Wearing Apparel for Use by Electrical Workers Exposed to Momentary Electric Arc and Related Thermal Hazards 1

“Standard for Electrical Safety in the Workplace,” NFPA 70E®, 2000 and 2012 editions.

2

James Cawley and Gerald Homce, “Trends in Electrical Injury,” IEEE PCIC, 2006; Electrical Safety Foundation International, Workplace Electrical Injury and Fatality Statistics – Additional Charts 2003 – 2010.

3

Kathleen Kowalski-Trakofler, Ph.D., “Non-Contact Electric Arc-Induced Injuries in the Mining Industry: a Multi-Disciplinary Approach,” IEEE/IAS Electrical Safety Workshop, 2004.

4

Dr. Charles F. Dalziel, “Deleterious Effects of Electric Shock,” Meeting of Experts on Electrical Accidents and Related Matters, Geneva, Switzerland, 1961

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6

IEEE/NFPA Joint Collaboration on the Arc-Flash Hazard Reports

James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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MAKE YOUR ELECTRICAL SAFETY PROGRAM YOUR OWN, PART 1: WHY WON’T A GENERIC PROGRAM WORK? NETA World, Fall 2014 Issue Don Brown, CESCP, Shermco Industries This is the first in a three-part series in the creation of an Electrical Safety Program (ESP). Part 1 will address the need for a companyspecific ESP and why a copy of a generic program will most likely get you into trouble. Part 2 will discuss the criteria for the contents of a company-specific ESP, and Part 3 will explain the implementation process of your newly created program.

The Williams-Steiger Occupational Safety and Health Act of 1970, Title 29 USC 654 Sec. 5. Duties: ●● Each employer ○○ Shall furnish to each of his employees employment and a place of employment that are free from recognized hazards that are causing or are likely to cause death or serious physical harm to his employees; ○○ Shall comply with occupational safety and health standards promulgated under this Act. ●● Each employee shall comply with occupational safety and health standards and all rules, regulations, and orders issued pursuant to this Act that are applicable to his own actions and conduct. We have all heard this time and time again. Many of us have heard it so many times that we can recite it verbatim to each other. It is known as the General Duty Clause, and it gives the Occupational Safety and Health Administration (OSHA) the authority to fine you on nearly any unsafe condition or circumstance you may have present on your job sites. If there are rules and regulations in the Code of Federal Regulations (CFR), then how can the General Duty Clause be used to issue a citation to a company? Simple: not every situation or potential event can be predicted on every job site. Conditions change, personnel change, and so does the work. It is for these reasons that the General Duty Clause exists. While it is very important to have a good safety program for your company, we will be focusing on the ESP, which should be separate from, but consistent with and a part of, the company’s overall safety program. There are many excellent resources available to use for creating an effective electrical safety program. The NFPA 70E – Standard for Electrical Safety in the Workplace (National Fire Protection Agency), Electrical Safety – A Practical Guide to OSHA and NFPA 70E (James R. White, American Technical Publishers), and The Electrical Safety Program Guide (Ray A. Jones, Jane G. Jones, Jones and Bartlett Learning) are among the best resources. However, using these as your ESP alone, or copying the example safety programs word for word, will

not only get you into trouble, it actually does a disservice to your company and could place your workers in hazardous situations. Your ESP must be company specific, hazard specific, and cover the work your employees do each and every day. These documents are a great starting point, but they don’t know what your employees do and what they face in their daily work. It is the responsibility of each employer to provide a safe working environment for its workers. In order to do this, the specific hazards one may face must be identified and a way to perform work safely must be determined. One of the key phrases in the General Duty Clause is “…free from recognized hazards….” Is electricity a recognized hazard? Of course it is. Knowing this is a key point to being able to create a company-specific electrical safety program. Looking at the key job duties of each employee and how they are exposed to those hazards will help in the creation of an excellent ESP. It is up to the employer to conduct a hazard assessment to determine what hazards are present at the place of employment and to create a program that ensures the employees work safely around those hazards. The Safety and Health Program Management Guidelines, dated January 26, 1989, was issued as a guideline for employers to use to prevent occupational injuries and illnesses. The guidelines represent a set of program elements used by employers that are successful in the protection of their employees. Along with the hazard assessment comes the risk assessment. Just what is a risk assessment? It can be defined and conducted in many ways, but it is simply this: a risk assessment is a careful examination of what could harm your workers, so that you can determine whether or not you have taken the proper precautions to prevent the harm or if you need to take additional precautions to help eliminate those hazards. Looking at the combination of the hazards to which your employees are exposed, in addition to the tasks being performed, is the best way to conduct a risk assessment. For example, you can have a high level of hazard around electrical equipment, but if there is no work being performed, there is little risk. On the other hand, there may be a low level of hazard, and a lot of work going on in the area of that hazard, and that increases the potential of an incident occurring. It just gives a level of protection to the workers when they are exposed to hazards in

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the workplace. Workers all have a right to be protected from harm, and you, as the employer, have the responsibility to provide that protection. See the Risk-ometer, below in Fig. 1, for a comparison of some common tasks.

Pulling fuses with bare hands on live circuit with no PPE Inserting MCC”bucket” into energized motor control center Troubleshooting 480v AC control circuit Opening hinged covers on live electrical panel Fused switch operation with doors closed

Fig. 1 Another key component is the inclusion of management’s commitment to the program. Without the commitment of management to the safety program, there will be no employee commitment, and with no employee commitment, there will be accidents and fatalities. A culture of safety can only come from the top down. So now you have management commitment, employee involvement, and a great program has been created. What do you do next? Whatever you do, don’t put it on the shelf and not tell anyone about it! Too many times that is exactly what happens. Another part of any good electrical safety program is getting the information out to the employees. Training is not only an essential part of the program, it is also a requirement per OSHA and NFPA. No matter what the employees’ job or task is, they have to be trained to be able to recognize and avoid the hazards they could be faced with while performing their daily duties. The training has to be either classroom, hands-on, or a combination of both, and it must address the hazards to which they are exposed. One of the last items this article will address is the need for sitespecific safe work practices. You can have the best written plan and the best training program and provide the employees all of the personal protective equipment and tools that they need to do their jobs, but if they don’t work safely, the chance of an incident increases dramatically. 29CFR1910.333 – Selection and use of work practices states:  (a) General. Safety-related work practices shall be employed “ … The specific safety-related work practices shall be consistent with the nature and extent of the associated electrical hazards.” and NFPA 70E 110.3(B) – Awareness and Self-Discipline states:

The electrical safety program…shall be developed to “ provide the required self-discipline for all employees who must perform work that may involve electrical hazards.” The old saying, “That’s the way we have always done it,” doesn’t work anymore. Work practices change, regulations and standards change, and the hazards in the workplace change. Your employees must change as well. With the updates to the NFPA 70E, and the upcoming changes to OSHA regulations, workers must be prepared to change with them. Working safely is not an option, it must be a condition of employment and must be upheld to the fullest. There is not a person out there that goes to work with the thought that, “Hey, I think I am going to hurt myself today.” Unfortunately, injuries are still happening. Many of the injuries that occur on the job today occur from two different work groups: the inexperienced workers and the more seasoned workers. The inexperienced workers are learning from the established workers, and sometimes pick up bad habits. With the right mentoring and the right training, those workers can have a lifetime of safe employment and will be able to go home at the end of the day. The seasoned workers, those that have been in a given industry for quite a long time, sometimes have the thought process that they have been doing something a particular way for their whole career and have not been hurt, so they must be doing something right. They need to be aware that things change in the workplace, equipment gets upgraded, equipment may not be maintained as well as it should have been, or tasks just get so routine that they are not paying attention to the hazards to which they are exposed. Invest the time and effort in your safety program to make it specific to your jobsite. It does not matter if it is a construction site, a manufacturing facility, or a customer site during a turn-around. Make sure that the specific hazards you will be facing are identified, the risks assessed, and the work is done safely. We all want to go home at the end of the day in the same condition that we came to work that day. In the next part of this series, we will be talking about some of the specific requirements of putting together a complete electrical safety program. Too many times things get overlooked and left out, only to come back at a later time and rear its head. Part three of this series puts the whole puzzle together and takes a look at the company-specific electrical safety program, looks at the specific requirements of an effective ESP, and shows how to implement a program that not only keeps workers safe, but helps reduce delays and equipment damage and decreases downtime by preventing incidents. Don Brown is the Senior Programs Developer for Shermco Industries in Irving, Texas. He has been in the electrical industry for over 40 years and has been implementing and training electrical safety for the last 15-plus years. Mr. Brown just completed his certification through NFPA as a Certified Electrical Safety Compliance Professional (CESCP). He has written electrical safety programs for large data centers, petrochemical facilities, and manufacturing facilities, and is in the process of updating many of these to include the upcoming changes in the NFPA 70E—2015 Edition.

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MAKE YOUR ELECTRICAL SAFETY PROGRAM YOUR OWN, PART 2: WHAT SHOULD BE IN AN ELECTRICAL SAFETY PROGRAM? NETA World, Winter 2014 Issue Don Brown, Shermco Industries

This is the second in a three-part series in the creation of an Electrical Safety Program (ESP). Part 2 will discuss what should be included in a company-specific ESP. Part 1 addressed the need for a company-specific ESP. Part 3 will explain the implementation process of your newly created program. A complete ESP consists of many parts. Some of the components of an effective ESP are safe work practices, including the need for an energized electrical work permit, personal protective equipment, training requirements, and insulated tools We will be discussing these in a broad overview of each category. Keep in mind that it is essential that the safety program be based on your site-specific needs as were outlined in Part 1 of this series.

INTRODUCTION This section includes the purpose for the ESP; the scope of the policy; the responsibilities of the employer, employees, and contractors; disciplinary procedures for noncompliance; auditing; and documentation. It should also include a list of all of the referenced documents that are a part of the ESP. These can be ASTD, IEEE, NFPA, and ANSI standards as well as references to applicable portions of the OSHA regulations. The referenced sections should be called out specifically, such as 29CFR1910.147—The Control of Hazardous Energy, and NFPA 70E-2012, The Standard for Electrical Safety in the Workplace.

TRAINING Training must be identified for each person that will be exposed to the hazards of electricity, whether that person is a qualified electrical worker or someone that is not generally going to be working on the electrical components, but may be exposed to the hazards in normal daily work. There are different classifications of electrical hazards, such as shock, arc flash and arc blast. These hazards must be addressed in the individual’s training requirements. Keep in mind that a person can be trained to a specific level of qualification on some equipment, but not be qualified to work on other equipment. Once the training is finished, it must be documented. Documentation is a key component of the EPS as far as being able to prove that someone has had the necessary training for a particular job. There are many ways to document the training that an individual has taken. It can be in the form of the class sign-

in sheet, a copy of the course-completion certificate, if awarded, or computer tracked identification badge log-in. The correct information must make it to the individual’s personnel or training file to show that the student attended the course. Just as important as documenting the training, is documenting the content of the class that was completed. NFPA 70E 110.2(E) Training Documentation states, “The documentation shall contain the content of the training, each employee’s name and the dates of the training.” The “content of the training” means not just a short description of the course, such as safety training, but what information was covered in that training session. The last part of the training documentation outlined in NFPA 70E 110.2(E) states, “This documentation shall be made when the employee demonstrates proficiency in the work practices involved and shall be maintained for the duration of the employee’s employment.” Broken down into two parts, the main topic here is the “demonstrates proficiency” section. To demonstrate, one has to “explain workings of something;  to explain or describe how something works or how to do something; show validity of something; to show or prove something clearly and convincingly.” And proficiency is defined as “mastery of a specific behavior or skill demonstrated by consistently superior performance, measured against established or popular standards.” Put very simply, that means that one has to prove that they have mastered a particular skill set by performing that skill. This also means that one cannot demonstrate proficiency by taking a written test or taking a class on line. Once the demonstration is done, the documentation is completed and the record placed in that person’s training or personnel record for the duration of their employment.

PERSONAL PROTECTIVE EQUIPMENT AND VOLTAGE-RATED TOOLS We are all aware that personal protective equipment is required, but how much is really needed, and do we have to wear it all? There is a simple answer to this question, and it goes like this: you need to wear all of the PPE that will protect you from all

46 of the hazards you will face in a given situation, every time. If there is no chance of electrical shock, but there is the possibility of an arc flash, you must wear arc-rated clothing to protect you to the level of that arc flash. If there is no possibility of an arc flash, but there is the potential for an exposure to shock, you have to be protected from the shock by wearing the proper protective insulating clothing, whether that is rubber insulating gloves with leather protectors, rubber insulating sleeves, or installing rubber insulating blankets over the exposed energized parts. And in many cases, you may be required to wear clothing and PPE that will protect you from all of these hazards. That means that you need to do a hazard assessment as well as a risk assessment for each potential hazard and provide the proper level of PPE for each worker to wear based on that hazard. Personal protective equipment can range from rubber insulating gloves to arc-rated clothing to arc-rated faceshields and hoods. Also required is that the workers be provided with electrically insulated tools and equipment for the work to be performed. Voltage-rated tools such as screwdrivers, wire strippers, wrenches, and socket sets are fairly common things to provide to each worker. Many of those tools can be used in daily activities. However, equipment such as hot sticks, shotgun sticks, and personal protective ground sets also fall into this category. These are the types of tools that are specialty tools and need to be identified for a specific job task, unlike insulated hand tools.

EEWP An Energized Electrical Work Permit (EEWP) is required any time that work is performed on electrical equipment that has not been placed in an electrically safe work condition and work is performed within the Limited Approach Boundary or the Arc-Flash Boundary. This does not include basic testing and troubleshooting. However it does include repair and installation of equipment while energized. There are a number of requirements for inclusion in an EEWP. Some of these are the description of the circuit or equipment to be worked on, the justification for working on energized equipment, a list of the specific safe-work practices to be employed while working, the results of the arc-flash and shock-hazard assessments, methods used to limit access to the area while work is begin performed, documentation of holding a job briefing, and last, but by no means least, the energized work approval which should be signed by the responsible manager, safety manager or facility owner. Each of these requirements must be documented on a single form (multipage, if necessary) and signed by that person responsible for the work. The document should be succinct enough to make it a user-friendly document, but detailed enough to include all of the listed information. General forms such as the one included in “Annex J” of the NFPA 70E are a good starting point, but the document needs to be site-specific enough to cover the requirements of the facility.

Arc-Flash SAFE WORK PRACTICES A strong case can be made that safe work practices include all that has been described previously─and with good reason. These are all part of the safe-work practices outlined in the NFPA 70E. What is being discussed in this part of the article is the actual work that is being performed, lockout/tagout, testing, troubleshooting, selection of PPE, and all potential emergency responses or emergency action plans that need to be addressed. The best and safest way to protect from the hazards of electricity is to engineer out the hazard during the design phase of a project. If you can totally eliminate the hazard, then everyone would be safe. Is that always possible? No. However, there are ways to minimize the hazards that are faced. One way is to control the hazardous energy using correct lockout/tagout procedures. There is not enough time or space in this article to address all of the requirements for an electrical lockout/tagout of a piece of equipment. We will leave that for another time. Just keep in mind that it is not always possible, for reasons that will vary from facility to facility and from company to company, that electrical equipment may not be able to be de-energized and locked out. This is when good, safe-work practices come into play. Looking at the equipment that needs to be worked on, one must look at not only the electrical hazards that he or she faces, but other potential hazards such as falls, other equipment operating in the area, other people working in the area, and many others. There will be times when a worker faces multiple hazards in a work environment. The authority having jurisdiction may grant special provisions to allow the worker to wear clothing that is not arc-rated, provided that it can be shown that the level of protection is adequate to address the arc-flash hazard (NFPA 70E-2012, “Article 130.7 (C) (12): Exception 2”). That does not give permission to ignore the shock- or arc-flash hazard. Those hazards must still be addressed. For example, this addresses the issue of work being performed in an area that may require such PPE as respirator protection. Not only is the person performing the work required to be protected, but the other workers in the work area must be protected as well. There are many ways to protect other workers. One of the best ways to protect others is by communication; keep everyone informed of the hazards of the work being done on equipment while energized. Another way is to set barricades to limit, or prevent, access by unauthorized and unqualified workers. If you can keep others from coming into the area where work is being done, that will help protect them from the hazards, as well as keeping the worker doing the work from being distracted while working. We could go on for a long time discussing safe work practices when it comes to working on or around electrical equipment. However, if you approach it from the perspective that you should look for a way that you could get injured while working, then take whatever precautions necessary to prevent that injury from happening, you will be well on your way to a safe work day.

Arc-Flash CONCLUSION These items are by no means the only components of an EPS. These are meant to be building blocks for your specific program. As we mentioned in the first part of this series, you need to have your EPS custom tailored to your company, then to your individual facility. Since some companies have multiple locations, there is no one way to address each and every situation throughout the company. There can be a corporate electrical safety policy, but each facility must have an individual program at that location. Some facilities may have mobile equipment, such as cranes and forklifts operating, while others may not. Some may have control of the substations that power their buildings, while others may not. And some companies may have instances when workers could be in remote locations with no one around. These issues are company and facility specific and must be addressed as such. At the end of the day, it come to this: Where are you working? Who are you working with (if anyone)? What are the hazards you are working around? How are you going to control those hazards? If you cannot address these simple items, you have some work to do. If you have addressed these, you are on your way to a safe work environment. One thing to remember: your EPS is a living, breathing document that needs to be used daily. Don’t create a program and put it on a shelf. It will do you no good there. Keep your workers safe. The next and final article in this series will discuss how to implement the safety program that you have just created. We will put all of the pieces together and show you how to make it work for you, as long as you keep it in front of your workers. Don Brown is the Senior Programs Developer for Shermco Industries in Irving, Texas. He has been in the electrical industry for over 40 years and has been implementing and training electrical safety for the last 15-plus years. Mr. Brown just completed his certification through NFPA as a Certified Electrical Safety Compliance Professional (CESCP). He has written electrical safety programs for large data centers, petrochemical facilities, and manufacturing facilities, and is in the process of updating many of these to include the upcoming changes in the NFPA 70E—2015 Edition.

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MAKE YOUR ELECTRICAL SAFETY PROGRAM YOUR OWN PART 3: IMPLEMENTATION OF AN ELECTRICAL SAFETY PROGRAM NETA World, Spring 2015 Issue Don Brown, Shermco Industries This is the third and final part of a series about creating and implementing an effective electrical safety program (ESP). Part 1 discussed the need for a company specific ESP. Part 2 discussed the requirements for that program. Here, in the final part of the series, we will discuss the implementation of the program that you just spent all that time and effort creating. Now that you have this wonderful, new creation in your possession, what do you do with it? The one thing you do not do is put it on a shelf and leave it there. There are too many companies with a very well written program that they don’t know how to implement, so they just do nothing! This does a disservice not only to your development team, but to your employees as well. Safety is about one thing and one thing only: sending your workers home at the end of the day in the same condition that they arrived at work in that morning, maybe a little tired or a little sore, but all in all, completely intact. No one wants to go home after a side trip to the hospital or with bandages. Most of all, everyone wants to go home. Being the person that has to make the call or visit to the family of someone who has been hurt or fatally injured at work is not a position that anyone wants. This is why proper implementation of your new ESP is important. Before implementation begins, safety must be a part of the company’s culture. It cannot be a priority. Yes, you read that right; safety cannot be a priority. It has to be a part of the company culture and the way that everyone lives his or her daily life. Everyone knows that priorities change, not only daily, but sometimes minute by minute. If safety becomes a priority, it can be changed to a lower priority and you will be putting your employees at risk. In order for safety to be a part of the company culture, it has to be brought into the values and the mission of the company, and this comes from upper management and flows downward, not the other way around. Everyone from the CEO to the company president to the directors to the managers to the supervisors to the front line workers needs to be a part of the process of implementing the safety program you just finished creating. Using the right team is crucial in the rollout of the program, but so is incrementally implementing the program. A phased rollout is one in which the program is introduced to the company’s employees one section at a time. This could be something as simple as introducing a new training matrix for qualified and unqualified workers. In most cases, everyone will start with the unqualified person training and move into more detailed training for the qualified person. Not every employee

will need to be designated as a Qualified Person for electrical work, but there are some that definitely need additional training, even if they have been doing a specific task for a number of years. The key part of the training is the documentation of that training as discussed in Part 2 of this series. Remember, if the training is not documented, the training never took place! Once the first part of the new program has been introduced to the masses, a second part, such as a section on personal protective equipment (PPE), can be introduced. It does not matter which section of the program gets introduced. The main issue is that you do not want to create the whole program, throw it out there, and tell everyone “Here it is! Now you have to do it.” Think of it like drinking from a fire hose or a glass. Which is easier to handle? By introducing and training your people on the program one section at a time, there is a much higher adoption rate and a higher success rate. These in turn will lower accident and incident rates, which will in turn help lower insurance premiums, etc. It is all connected. Putting together the proper implementation team is critical before taking it to the rest of the employees. There needs to be representation from each level of the organization from the top all the way down. However, you also need to include someone from each department. Now, before you turn away, hear this out. You need someone from operation, someone from maintenance, someone from human resources, someone from safety, and someone from each pertinent department in the company and the person from each department must be committed to the program, which also means they need to be a part of the creation process. You can have a safety professional create the baseline program, but there must be input from each department to help with the necessary customization. Each company will be a little different, but it all comes down to the team. Each member of the team with, support from the safety department will, be responsible for explaining to his or her own department how the new program will impact the coworkers in that department. ANSI/AIHA Z10 – Occupational Health and Safety Management Systems states that top management leadership and effective

Arc-Flash employee participation are crucial for the success of an occupational health and safety management system (OHSMS). From Section 3, as paraphrased below: ●● Top management shall direct the organization to establish, implement and maintain an OHSMS. ●● The organization’s top management shall establish a documented occupational health and safety policy. ●● Top management shall provide leadership and assume overall responsibility. ●● The organization shall establish and implement process to ensure effective participation in the OHSMS by its employees at all levels (AIHA). The content of this is fairly straightforward. It is up to top management to ensure that a complete and comprehensive safety program is established and implemented. By utilizing members from top management as well as those on the front lines, the organization will be able to get full participation in the newly-created ESP. When everyone is involved, and there are many owners of a program, a higher level of participation and acceptance occurs. Then the program permeates the organization and becomes a part of the culture of the company. Once we have the electrical safety program created, the implementation process has been finished, and everyone believes and participates in the program, the final part of the process comes into play. Reviews and updates are very important pieces of the puzzle. NFPA70E states that ESPs must be audited with a frequency not to exceed three years. ANSI/AIHA Z10 says that the organization shall establish and implement a process for top management to review the OHSMS at least annually. It would appear that this is a conflict in recommendations. However, there are other ways to look at it. NFPA 70E covers the electrical safety program, while the ANSI/AIHA Z10 covers the organization’s entire safety program. If the organization reviews the entire safety program every year, is not the 70E requirement being met? Of course it is. But does it require an extensive overhaul every year? Absolutely not. If the standards have not changed, the main review will consist of corporate changes to procedures and policies. If the standards have changed, then there may be a need to overhaul the particular sections of the corporate safety program, such as the ESP. The NFPA 70E standards change every three years with few exceptions. In most cases, there will be a few changes to your ESP every three years. Currently there are changes being brought about due to the sweeping changes to the OSHA electrical regulations in 1910 and 1926, and these will have an impact on your program. During the times that the electrical standards and regulations are not being changed, you can focus your efforts on the other portions of the corporate safety program. Your ESP is a living, breathing document that needs to be utilized, updated, and cared for every single day you are working.

49 Conditions change that may have an impact on your program; new workers may show up on the jobsite; new equipment and procedures that your employees are not familiar with may come up. That is just a fact of life. That is the reason for conducting your site safety assessments. That is why you conduct job briefings before work starts each and every day. If you have a good ESP, and you take care of it by following it and updating it as standards and regulations change, your program will take care of you. If you do not know what your ESP contains, it is time for you to look into it and begin asking questions. Now, go out there and plan your work and work your plan. Be safe and come back to work tomorrow so you can do it over and over again. Don Brown is the Senior Programs Developer for Shermco Industries in Irving, Texas. He has been in the electrical industry for over 40 years and has been implementing and training electrical safety for the last 15-plus years. Mr. Brown just completed his certification through NFPA as a Certified Electrical Safety Compliance Professional (CESCP). He has written electrical safety programs for large data centers, petrochemical facilities, and manufacturing facilities, and is in the process of updating many of these to include the upcoming changes in the NFPA 70E—2015 Edition.

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ARC-FLASH ANALYSIS IS GOING GLOBAL NETA World, Winter 2014 Issue Lynn Hamrick, Shermco Industries NFPA 70E is a well-recognized standard for specifying arcflash personal protective equipment (PPE) and provides a good overview of arc-flash hazard calculations. The Canadian ArcFlash Standard CSA Z462 has been developed in collaboration with the NFPA of the United States, so it is essentially an adaptation of the NFPA 70E standard. The result is that North America is very consistent in its approach and application of standards for protection against arc-flash hazards. These standards are living documents that are updated at regular intervals to accommodate technological developments and new information. Most of the global community has embraced these standards and is applying them as their own. However, in some of the global community, mostly within the European Union, alternate standards are being developed to address arc-flash hazards. This article will discuss some of the challenges one might face when performing arcflash analysis and implementing the use of arc-flash personal protective equipment (PPE) outside of North America.

ARC-FLASH ANALYSIS Generally, the calculations in NFPA 70E are based on a paper published by Ralph Lee in 1982.1 Lee used simple theoretical models and basic electrical understanding to calculate a distance at which a person could walk away from an arc flash with a second-degree, or curable, burn. These models were based on a spherical heat source with a heat absorber at a distance. He used skin burn models postulated by Stoll and Chianti to derive his equations.2 In 2000, Doughty, Neal and Floyd, added a piece to the puzzle by publishing a paper on their research that considered variations in incident energies in open air versus incident energies from an enclosure or box.3 A combination of these efforts resulted in the basis for the arc-flash analysis calculations in NFPA 70E. From there, IEEE performed more practical testing and empirically-derived calculations were presented in IEEE 1584.4 After IEEE 1584 was published, the next version of NFPA 70E added that it has an acceptable, alternative method for performing arc-flash hazard analysis. Currently, IEEE 1584 is the most widely used standard for arcflash incident energy calculations globally. With the exception of the calculations provided in NFPA 70E, IEEE 1584 is the only generally-accepted methodology for performing these calculations for three-phase, low-voltage systems. When using this standard, it should be noted that it is limited to arc-flash analyses for infrastructure below 15 kV. Fortunately, the empirically-derived calculations suggested within the standard have weathered the test

of time in that they appear to be fairly accurate in low-voltage applications (< 1000 V), which is the majority of the applications where arc-flash analysis is most beneficial. However, IEEE 1584 has received some criticism from the international community with regard to its methodology and test setup.5 Further research on arc-flash calculations is being carried out as a collaborative effort of NFPA and IEEE. This effort includes some international involvement, so it is hopeful that this criticism will be minimized with future revisions of the standard. The latest revision of the European electrical safety standard, EN 50110, requires that an arc-flash risk assessment (analysis) be performed.6 Unfortunately, there is no specific guidance or consensus methodology for performing an arc-flash analysis in Europe. Germany’s BGI 5188 was published in October 2012 and is similar to the NFPA 70E methodology in that it calculates a heat flux in various configurations (open air, in a box, against a wall, etc.) in combination with Stoll’s burn model to evaluate an arcflash hazard.7 However, it will probably be years before the European community agrees to endorse this or any other guide as a consensus standard. Until that happens, and specifically with North American-based companies, IEEE 1584 is being used extensively throughout Europe to meet the EN 50110 requirement. There are some things to consider when using IEEE 1584 outside of North America. When performing an arc-flash analysis in accordance with IEEE 1584, information associated with the electrical infrastructure is used as input (voltage levels, bolted fault currents, fault clearing times, etc.) to perform the calculations. Specifically, the source of the bolted fault information has resulted in some concern as to the effectiveness of the analysis. In North American, bolted fault calculations are typically performed using IEEE 141 as the methodology for evaluating bolted fault currents.8 This methodology uses a comprehensive network approach to determine bolted fault currents. For most applications, the European community prefers the use of the methodology in IEC 60909 for evaluating bolted fault currents.9 This methodology uses the fault current associated with the first ½ cycle of the fault to determine the bolted fault current. This article will not discuss the merits of either methodology for determining bolted fault currents. It should be noted that the results using either methodology will be similar; however, there may be some disagreement as to which methodology is appropriate for use in this application. Typically, the selection of the bolted fault current determination methodology for use in evaluating arc-flash

51

Arc-Flash hazards is not a problem. However, when performing arc-flash analysis anywhere other than North America, it is highly recommended that the methodology to be used is agreed upon prior to performing the analysis. It should be noted that most of the available comprehensive modeling tools for performing power system studies can perform short-circuit analysis using either the IEEE 141 or IEC 60909 methodology. However, the companion arc-flash evaluation program may not be fully integrated with the IEC 60909 modeling version of the tool. This means that you may have to manually enter the short-circuit information into the arc-flash evaluator to perform an arc-flash analysis.

ARC-RATED PPE SELECTION Another challenge that may be encountered when implementing protective measures associated with arc flash is the methodology used in determining the appropriate arc-flash PPE. In the US, arcrated PPE is selected based on the incident energy at a given working distance. This arc rating for the PPE is established by determining the arc-thermal performance value (ATPV) of the material in accordance with ASTM F1959, which is endorsed by NFPA 70E.10 Concurrent with the development of this US standard, the international community has been developing the IEC 61482 series of standards. IEC 61482-2 is also provided as the requirements portion of the standard series.11 IEC 61482-1-1 is equivalent to ASTM F1959 in that it evaluates the ATPV of the material.12 This standard is preferentially used in North America. IEC 61482-1-2 is based on a European standard (formerly ENV 50354) which uses a specific box test and heat flux measurement to classify the material for use in an application.13 Both of these standards are acceptable; however, they are not interchangeable. In Europe, arc-rated clothing receives a CE certification that is based on the specific type of risk analysis that is used to determine the extent of the arc-flash hazard. This means that clothing certified to IEC 61482-1-1, or by ATPV testing, should be used when IEEE 1584 is the method used for the arc-flash analysis. Further, clothing certified to IEC 61482-1-2, or by box testing classification, should be used when a guide like BGI 5188 is the method used for arc-flash analysis.

CONCLUSIONS NFPA 70E is a standard for specifying arc-flash PPE and provides a good overview of arc-flash hazard calculations. Additionally, IEEE 1584 is the most widely used standard for arc-flash incident energy calculations. Most of the global community has embraced these standards and is applying them as its own. However, in some of the global community, mostly within the European Union, alternate standards are being developed to address arc-flash hazards. So, there are some things to agree upon prior to performing an arc-flash analysis outside of North America:

●● The methodology for determining bolted fault currents (IEEE 141 or IEC 60909). ●● The selection of certified arc-rated PPE (ASTM F1959 and IEC 61482-1-1, or IEC 61482-1-2). If IEEE 1584 is to be used as the methodology for performing an arc-flash analysis, the appropriate bolted fault calculation method must be defined. If IEC 60909 is to be used with a comprehensive modeling tool, verify that the companion arc-flash evaluation program is fully integrated with the IEC 60909 modeling version of the tool. Further, the arc-rated PPE to be used must be certified in accordance with IEC 61482-1-1 or ASTM F1959.

REFERENCES: Lee, R. The Other Electrical Hazard: Electrical Arc Blast Burns, IEEE Transactions on Industry Applications, Vol. IA-18, no. 3, pp. 246--251, May/June 1982.

1 

Stoll, AM and Chianta, MA. Method and Rating System for Evaluation of Thermal Protection, Aerospace Medicine, Vol. 40, No. 11, pp. 1232-1238, Nov 1969.

2 

Doughty, RL., Neal, TE, and Floyd HL. Predicting Incident Energy to Better Manage the Electric Arc Hazard on 600-V Power Distribution Systems, IEEE Trans. Ind. Appl., Vol. 36, No. 1, pp. 257--269, Jan./Feb. 2000.

3 

IEEE Standard 1584---2002, IEEE Guide for Performing ArcFlash Hazard Calculations.

4 

Stokes, AD and Sweeting, DK. Electric Arcing Burn Hazards, IEEE Transactions on Industry Applications, Vol. 42, No. 1, pp. 134--140, January/February 2006.

5 

EN 50110-1: 2013, Operation of Electrical Installations. General Requirements.

6 

BGI/GUV-I 5188 E, Thermal Hazards from Electric Fault Arc- Guide to the Selection of Personal Protective Equipment for Electrical Work, October 2012.

7 

IEEE Standard 141---1993, IEEE Recommended Practice for Electrical Distribution for Industrial Plants.

8 

IEC 60909-0---2001, Short Circuit Currents in Three Phase A.C. Systems---Part 0: Calculation of Currents.

9 

ASTM Standard F1959/F1959M-14, Standard Test Method for Determining the Arc Thermal Performance Value of Materials for Clothing.

10 

IEC 61482-2---2009, Live Working---Protective Clothing Against the Thermal Hazards of an Electric Arc---Part 2: Requirements.

11 

IEC 61482-1-1---2009, Live Working---Protective Clothing Against the Thermal Hazards of an Electric Arc---Part 1-1: Test Methods – Method 1: Determination of the Arc Rating (ATPV or EBT50) of Flame Resistant Materials for Clothing.

12 

52 IEC 61482-1-2---2007, Live Working---Protective Clothing Against the Thermal Hazards of an Electric Arc---Part 1-2: Test Methods – Method 2: Determination of the Arc Protection Class of Material and Clothing by Using a Constrained and Directed Arc (Box Test).

13 

Lynn Hamrick brings over 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. Lynn is a Professional Engineer, Certified Energy Manager and has a BS in Nuclear Engineering from the University of Tennessee.

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ARC-RATED CLOTHING AND ELECTRICAL HAZARD FOOTWEAR NETA World, Summer 2016 Issue Paul Chamberlain, American Electrical Testing Co., Inc. Everyone wears clothes. However, not everyone needs to wear clothes designed to protect from the inherent hazards in their job. If employees work on electric power generation, transmission, and distribution equipment, then special clothing is necessary for certain tasks. Per OSHA Regulation 29 CFR 1910.269, employers need to assess a workplace and whether an employee will be exposed to the hazards of flames or electric arcs. Upon finding a potential for exposure, the employer must estimate the potential incident heat energy the employee could be exposed to and provide the employee with the appropriate personal protective equipment (PPE). In addition, if employees will be exposed to flames and arcs, the employer must ensure that the material worn by employees is not untreated meltable fabric (polyester, rayon, fleece, natural fiber blended with meltable fibers, etc.). Available materials are listed in “Flame Resistant and Arc Rated Textile Materials for Wearing Apparel for Use by Electrical Workers Exposed to Momentary Electric Arc and Related Thermal Hazards,” ASTM F1506. Further, in regulation 1910.269, OSHA states: “ The employer shall ensure that the outer layer of clothing worn by an employee, except for clothing not required to be arc rated, is flame resistant under any of the following conditions: ●● The employee is exposed to contact with energized circuit parts operating at more than 600 volts, ●● An electric arc could ignite flammable material in the work area that, in turn, could ignite the employee’s clothing, ●● Molten metal or electric arcs from faulted conductors in the work area could ignite the employee’s clothing, or ●● The incident heat energy exceeds 2.0 cal/cm2.” Per NFPA 70E 2015 Standard for Electrical Safety in the Workplace, the employer must provide arc-rated (AR) clothing for potential arc-flash hazards in an atmosphere not regulated by the OSHA 1910.269 standard. “Section 130.4 and 130.6” of NFPA 70E clearly states that it is the employer’s responsibility to identify the hazards and provide the necessary AR clothing to mitigate those hazards. It also instructs the employee in proper inspection of that PPE. Once it is determined that flame-resistant clothing is required, the employer must provide clothing that is appropriately rated for the potential hazard. In 1910.269, OSHA further states:

“The employer shall ensure that each employee exposed to hazards from electric arcs wears protective clothing and other protective equipment with an arc rating greater than or equal to the heat energy estimated whenever that estimate exceeds 2.0 cal/cm2. This protective equipment shall cover the employee’s entire body, except as follows: ●● Arc-rated protection is not necessary for the employee’s hands when the employee is wearing rubber insulating gloves with protectors, or, if the estimated incident energy is no more than 14 cal/cm2, heavy-duty leather work gloves with a weight of at least 407 gm/m2 (12 oz/yd2), ●● Arc-rated protection is not necessary for the employee’s feet when the employee is wearing heavy-duty work shoes or boots, ●● Arc-rated protection is not necessary for the employee’s head when the employee is wearing head protection meeting § 1910.135 if the estimated incident energy is less than 9 cal/ cm2 for exposures involving single-phase arcs in open air or 5 cal/cm2 for other exposures, ●● The protection for the employee’s head may consist of head protection meeting § 1910.135 and a face shield with a minimum arc rating of 8 cal/cm2 if the estimated incident-energy exposure is less than 13 cal/cm2 for exposures involving single-phase arcs in open air or 9 cal/cm2 for other exposures, and ●● For exposures involving single-phase arcs in open air, the arc rating for the employee’s head and face protection may be 4 cal/cm2 less than the estimated incident energy.” As the potential incident energy increases, so must the protection level provided to the employee. Again, it is the employer’s responsibility to assess the workplace, identify potential hazards, and provide adequate protection to the hazard. Training employees in the proper use and care of the PPE provided is very important. Employees’ ability to identify electrical hazards, their knowledge of electrical equipment and its nominal voltage, and understanding when proper PPE is required are vitally important and will go a long way in ensuring that they are protecting themselves from potential hazards.

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Arc-Flash electrical circuits, electrically energized conductors, parts, or apparatus. It must be capable of withstanding the application of 18,000 volts at 60 hertz for one minute with no current flow or leakage current in excess of one milliampere under dry conditions. Should the assessed potential exceed this, protection such as rubber dielectric over boots or shoes will be required.

The other aspect to employee training is care of their PPE. If it is worn, damaged, or deteriorated, then it cannot adequately protect them from potential hazards. Employees must learn to inspect all PPE prior to and after use. A guideline in the inspection and care of AR clothing is found in ASTM F1449 Standard Guide for Industrial Laundering of Flame, Thermal, and Arc Resistant Clothing and ASTM F2757 Standard Guide for Home Laundering Care and Maintenance of Flame, Thermal and Arc Resistant Clothing. These ASTM standards are a requirement for management of AR clothing, whether laundered at home or commercially. Many AR clothing manufacturers offer helpful online aids to provide guidance to employees on the proper use, care, and maintenance of AR clothing.

Proper care of footwear is also very important. Exposed toe caps indicate a breakthrough in the leather of the boot, providing less arc and flame protection. Simple things such as broken, missing, or overly long laces can pose a simple trip hazard, which can cause serious injury. Wear in the sole of the boot exposes the employee to step potential during a ground fault. Spilled flammable materials can soak into a leather boot, possibly causing a flame hazard. Therefore, cleaning and maintaining boots and shoes used for protection is highly important. Wearing the correct AR clothing and boots protects employees from many potential hazards. Ensuring that this equipment is clean and well maintained is an important step in providing adequate protection to the wearer. Knowledge of how to inspect, clean, and maintain these garments and footwear must be given to the employee by the employer to ensure a safe and productive workplace.

If they will be exposed to the hazard of flames or electrical arc, employees must also wear heavy-duty work boots or shoes. Per OSHA 29 CFR 1910.136(a): “Each affected employee shall wear protective footwear when working in areas where there is a danger of foot injuries due to falling or rolling objects, or objects piercing the sole, and where such employee’s feet are exposed to electrical hazards.” Likely, the boot or shoe will also need to be safety-toed and meet ASTM F2413 Standard Specification for Performance Requirements for Protective (Safety) Toe Cap Footwear. Additionally, the boots must be electrical hazard-rated footwear (EH). EH footwear is manufactured with non-conductive, electrical-shock-resistant soles and heels. The outsole provides a secondary source of electric shock-resistance protection to the wearer against the hazards from an incidental contact with live

Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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METHODS TO LIMIT ARC-FLASH EXPOSURE ON LOW-VOLTAGE SYSTEMS NETA World, Winter 2013 Issue Scott Blizard, American Electrical Testing Co., Inc. As the electrical industry addresses arc-flash safety concerns, the industry is realizing the high risks associated with what used to be normal maintenance tasks. In many cases, the excessively high arc-flash incident energies make it so all maintenance must be done with equipment de-energized, which is not always feasible. The methods discussed below will address several ways to significantly lower arc-flash incident energy exposure by new system design and products, retrofits, equipment modifications, and alternate protection settings, etc. In most cases, NFPA 70E2012 Hazard Risk Category 2 or lower can be obtained. One of the best and most efficient ways to lower the incident energy, which inherently lowers the Hazard Risk Category of electrical equipment, is to clear the fault quicker by making the protective device trip faster. Some of the methods to reduce the clearing time of an electrical fault, using various protective devices and schemes, are described below. Implementation of a bus-differential scheme increases the speed to trip the circuit, which will reduce the arc-flash hazards. The concept of a bus-differential protection (87B) scheme has been around for a very long time. Because of the space and cost constraints, it was typically only used for high-voltage or medium-voltage applications. The scheme measures 100% of the current into and out of a bus. It requires three additional current transformers on every breaker. Simply put: ●● If 100% 1IN = 100% 1OUT, then do not trip. ●● I f 100% 1IN ≠ 100% 1OUT, then trip all bus breakers instantaneously. Zone selective interlocking (ZSI) improves the level of protection in a power distribution system. ZSI is a control logic system communicating between feeder breakers and upstream feeder breakers or the main breaker. The main breaker is zone 1 and subsequent downstream breakers establish one or more additional zones. The control system is built into the electronic and digital trip units of low-voltage breakers. Its design functionality and use have grown over the last 20+ years. Assuming a high-level short circuit occurs on the load side of a feeder breaker, digital trip units on the main breaker and the feeder breaker sense the fault. The feeder breaker sends a blocking signal to the main breaker, letting it know that the fault is in the feeder breaker’s zone of protection or in a lower zone. The blocking signal tells the main breaker to delay tripping per the trip unit’s time-delayed settings (backup to the feeder breakers), while the feeder breaker trips with no intentional delay.

When a fault occurs in the switchgear on a primary side of a feeder breaker, no blocking signal is sent to the main breaker. Since the main breaker senses the fault, but does not receive a blocking signal, its control logic bypasses the short time or ground fault time delay setting characteristics and trips almost instantly as described for the feeder breaker in the paragraph above. It lowers its time-delay settings to approximately two cycles, just enough time-delay to assure nuisance tripping does not occur. When applying ZSI, as an arc-flash solution, one must be aware of the following: ●● It is automatic - no special precautions are required. ●● I t only affects the short time delay and ground fault time-delay setting characteristics. ●● T  he arcing fault current must be above the short-time pickup settings or ground fault pickup settings for ZSI to be initiated and to reduce the arc-flash incident energy. ●● I t adds two to three cycles maximum to the breaker clearing time of three cycles compared to an instantaneous trip resulting in five to six cycles total clearing time (83 ms – 100 ms). ●● It requires slightly different breaker testing procedures during maintenance testing and calibration to prove the integrity of the system. A very effective way to lower arc-flash incident energy is to apply a maintenance switch. This option can be retrofitted or purchased new in low-voltage and medium-voltage protective devices. An external override switch and circuitry are connected to a breaker’s trip unit and is adjustable between 2.5X - 10X the breaker rating. The basic operation of the maintenance switch is to lower incident energy at downstream protective devices. When performing maintenance, the maintenance switch is closed. This automatically overrides all of the breaker’s delay functions and causes the breaker to trip without any intentional delay when a fault is detected. Upon completion of the maintenance, the maintenance switch is manually opened and all previous trip unit settings are again reactivated without need for recalibration. Another method of reducing arc-flash incident energy is arc-detection sensors which provide a visual measurement of an arc flash. The light emitted during an arc-flash event is significantly brighter than the normal substation light background. The light surge is available from the initiation of the arc flash and is easily detected using proven technology.

56 The most common sensors are lens point sensors and bare fiber optic sensors. The light is channeled from the sensor to the detector located in the protective relay. Monitoring of the system integrity is accomplished using a fiber optic loop. In the case of the lens sensors, each lens has an input and output connection. The input is connected to a transmitter in the relay, and the output is connected to a detector in the relay. This loop connection allows periodic testing of the system by injecting light from the transmitter through the loop and back to the detector. This loop connection system works with either the lens sensor or the bare fiber sensor. The bare fiber sensor consists of a high quality plastic fiber optic cable without a jacket. The clear fiber cable becomes a lens, bringing in light from the area. Using a bare fiber sensor makes detection in large areas possible using only one sensor. The cable is constructed of a one millimeter plastic material that can withstand a 25-millimeter bending radius without damage. The cable can be cut to length in the field and fit to the application without excess cable. Arc-detection systems typically use a combination of lens and bare fiber sensors returning to a single relay. Proper installation of the sensors and relays provides logical detection and trip points in any system. Sensors should be located where arc detection for the specific sensor will trip the corresponding upstream circuit breaker. Using more than one sensor provides 100% coverage even during one-millisecond testing intervals. Installation of sensors varies depending on the switchgear manufacturer, type of gear, and number of sections. Multiple sensor inputs provide coverage and sectioning options. One bare fiber sensor can provide excellent coverage of the entire bus section. Using lens sensors allows better control in small, confined spaces. One obstacle in using light sensors is the need to measure and adjust for changing ambient light levels. Measuring light and current in the protective relay can make use of the analog measurements and event reporting capabilities in the relay. By monitoring the incoming light as an analog signal, the user is able to view and set the normal light levels for the application. The event reporting also provides a troubleshooting tool with time-tagged events including arc-sensor light levels. Tracking the arc-light intensity provides the detail needed to reach the root cause of an event. The added advantage of processing the arc-flash detection in the protective relay is the ability to use a true overcurrent measurement as a supervising element to improve security. In order to reach the fastest trip times, some arc-detection systems use a current setting level below the normal expected load to enable the arc-flash detector as the trip mechanism. Using current in this manner removes any time lag determining if a fault exists, but sacrifices selectivity and makes the system dependent on light detection alone. Superior security can be obtained using a high-speed overcurrent element in conjunction with the light sensor without sacrificing trip speeds.

Arc-Flash In the system presented above, a true high-speed overcurrent element is used in parallel with the arc-flash detector. The current used to trigger a trip is derived by sampling the feeder current and using a fast detection algorithm to signal that a fault has occurred. This fault is then compared with the trip levels of the arc-detection sensors to determine if an arc-flash trip is warranted. Many standard overcurrent elements have response times between 6 and 20 milliseconds. This delay is unacceptable for arc-flash detection supervision. To avoid introducing additional delay, the high-speed overcurrent protection must act as quickly as the arc detection. The combination of fast overcurrent and flash detection must be present at the same instant; the combined security is much higher than either system alone. Adding arc-flash sensors reduces the total fault clearing time. The time reduction has a dramatic effect on arc-flash energy. These are just some of the methods being used today to reduce arc-flash energy in electrical switchgear. Compliance with arc-flash hazard work rules, as defined by OSHA, NFPA 70E (Standard for Electrical Safety in the Workplace) and NFPA 70 (National Electrical Code), requires evaluation of arc-flash hazards and subsequent posting of the hazard on electrical equipment. All of the methods described above require the electrical system to be maintained to assure proper operation. It is always best to work on de-energized equipment when possible. When you must work on energized equipment, make sure you wear the appropriate personal protective equipment to perform the task. Scott Blizard has been the Vice President and Chief Operating Officer of American Electrical Testing Co., Inc. since 2000. During his tenure, Scott acted as the Corporate Safety Officer for nine years. He has over 25 years of experience in the field as a Master Electrician, Journeyman, Wireman, and NETA Level IV Senior Technician.

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WHY DO A RISK ASSESSMENT? NETA World, Fall 2016 Issue Jim White, Shermco Industries, Inc. This article discusses the whys of performing a job-safety assessment (JSA) or a job-hazard assessment (JHA). This often comes up during safety classes where attendees say, “Oh, I had no idea why we did those. It was just something we were told to do.” While employees should comply with standard operating procedures (SOPs) or company directives, since we are dealing with adults, they also need to understand why we do things. Once they do, compliance goes way up.

RISK VS. FREQUENCY Risk is defined by NFPA 70E as “a combination of the likelihood of occurrence of injury or damage to health and the severity of injury or damage to health that results from a hazard.” Risk assessment is defined as “an overall process that identifies hazards, estimates the potential severity of injury or damage to health, estimates the likelihood of occurrence of injury or damage to health, and determines if protective measures are required.” NFPA 70E adds this to the definition of risk assessment: “Informational Note: As used in this standard, arc-flash risk assessment and shock risk assessment are types of risk assessments.” Frequency, of course, is how often a task is performed during the work day. Fig. 1 shows the four quadrants comparing risk to frequency.

Fig. 1: Risk vs. Frequency High Risk/High Frequency tasks include utility work on overhead lines or live-line bare hand work on energized electrical lines or equipment. Most industrial companies try to limit or eliminate tasks such as these to prevent electrical events. Utilities, however, operate in this environment frequently. High Risk/Low Frequency tasks include racking a circuit breaker in or out of its enclosure, removing or installing a MCC bucket or a bus duct fuse.

These tasks are rarely done, but the risks involved are high. Low Risk/High Frequency tasks are things like driving a car, walking or climbing stairs. These tasks are performed thousands of times each day, but accidents are infrequent. Examples of Low Risk/Low Frequency tasks are riding a merry-go round, playing billiards, or other similar activities. Of these four types of tasks, which one would have more injuries? Surprisingly (or, maybe not), most events happen in the Low Risk/ High Frequency category. We perform these tasks day in and day out, hardly giving them a thought; and that is where we get into trouble. Our brain goes into auto-pilot mode and we just go through the motions. For example, as we drive on an interstate highway, we tend to use only that portion of our brain really needed to get us from point A to point B. Since our brain is the biggest energy user of our entire body, it automatically throttles back to conserve energy. We don’t consciously do this; it just happens. If a police car comes up behind us with its lights flashing and siren blaring, we go into full alert mode. Once that police car passes us, we drop back into interstate driving mode. We are conserving energy. Many would argue that driving a vehicle is not low risk, but consider how many millions of miles are driven each year and the number of vehicles on the road at any given time. According to the National Highway Safety Traffic Administration there were 32,719 deaths attributed to traffic accidents in 2013. That’s a lot, but there were also about 212 million drivers who drove about 2.96 trillion miles. This works out to 1.13 fatalities per million miles driven. Those fatalities were not in any way acceptable, but for the number of miles driven, the fatality rate is relatively low. The implications of the way our brain operates are tremendous. The first time we perform a task, we are focused and sharp. As we perform the task repeatedly, we tend to be less focused. Our brain is conserving energy, perserving our energy stores in case we have to run from a saber tooth tiger, climb a tree, or some other survival-related task. We go through the motions, not really paying attention. If anything different should happen — anything not planned for — we could quickly be in a safetycritical position.

PROBABILITY VS. CONSEQUENCE We are all familiar with the concept of probability. We constantly weigh probabilities, sometimes more successfully than others. If we make a sudden lane change or we decide to answer a cell phone call, we are weighing the probability of an accident, and we all deal with the consequences of decisions made every day.

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Fig. 2 shows probability vs consequence. Low Probability/High Consequence would be a task such as racking a circuit breaker in or out or inserting/removing MCC buckets. We don’t do these often, and the probability of failure is small; but if a failure does occur, the consequence of failure could be very high — even lifethreatening. High Probability/High Consequence tasks are those that have a high probability of injury and the consequences would be high. Going back to utility linemen as an example, they work in close proximity to energized lines and equipment. If they should make contact, the consequences would be high. Low Probability/ Low Consequence tasks are such tasks as sharpening a pencil or brushing your teeth, etc. The chances of injury are small, and, if it did occur, the resulting consequence would be very minor. High Probability/Low Consequence tasks are those that have a high probability of an accident, but the consequences would be very minor. This might include tasks such as playing dodge ball or playing rock-paper-scissors. You know you’re going to get it, but if you do, the resulting consequence won’t be serious.

JSA/JHA forces us to focus on the task we are about to perform and to think all the steps through. At the same time, we are assessing whether or not this task is safe to perform given the equipment, preparation, and experience of those involved. We have to evaluate the consequences of a failure and the steps that can be taken to prevent it or at least lessen its effects. As required by NFPA 70E, a risk assessment creates the focus needed to perform tasks safely when we are exposed to electrical hazards and risks. In NFPA Section 130.2(B)(2), an energized electrical work permit (EEWP) helps to satisfy the requirements of a JSA/JHA because a shock risk assessment and an arc-flash risk assessment are required to complete it. Steps required to control risk are also part of an EEWP, as are the PPE requirements of the task. Many companies fold the EEWP into their JSA/JHA and cover non-electrical as well as electrical risks.

SUMMARY Don’t make the mistake of thinking paperwork serves no purpose. The paperwork, no matter how inconvenient it may seem, is needed to keep us on track and focused. Going into autopilot on an interstate is bad business, but when performing a task with electrical risks, it can turn a benign task into a potentially fatal situation. Technicians need to be aware of the risks involved with a task, the probability of an accident, and what the potential consequences would be if an accident occurs. The two important categories are: ●● Low Risk/High Frequency tasks. These are the ones we do every day, so we tend to be less aware of the risks.

Fig. 2: Probability vs. Consequence Once we begin to roll the dice on the job, we are headed for trouble. Once a person performs a task incorrectly and is not immediately injured or killed, it becomes his way of doing it. Trying to convince people that their way is not the safest way to perform that task is very difficult because these people may have years of experience telling them it is safe. And if everything goes just right, it probably is safe. But if something changes or if something is missed during their visual assessment, they are likely to be injured. The worst part is that they don’t understand why they were injured because they have used their way successfully for so long. On-the-job safety is not about being safe most of the time or even being safe when you think it is important. It’s about being safe all of the time. If a person wants to take unreasonable risks off the job site to satisfy their sense of adventure, so be it. But on the job, that same person has to work according to rules established by the company. That is where job-safety assessments (JSAs) and job-hazard assessments (JHAs) and all the other seemingly useless paperwork comes in. Because we tend to conserve energy, we also tend to lose focus on the details involved in performing a task. A

●● Low Risk/High Consequence tasks. Even though the chances of a mishap are low, if something does go wrong, the consequences could be severe. No one wants to be a statistic, but we all have human failings. The safety industry has worked diligently to provide methods to help us overcome these failings, but we have to make use of them. As companies grow and expand, their challenge is to promote a work culture that enhances safe workplaces. How this is accomplished varies from blunt force to training and counseling, or a combination of the two. In boot camp, troops are told that those who can’t do their job well will be an example for everyone else. The smart soldier tries to let someone else be the example. An event that occurred in 2009 highlights the importance of performing a risk assessment. An employee was tasked with closing a medium-voltage circuit breaker after the switchgear was cleared by the contractor installing it. The Company A employee assessed the risk and wore the 40 cal/cm2 arc-rated flash suit provided by his company. The contractor did not remove the personal protective ground set they had installed earlier, and when the employee of Company A closed the circuit breaker, an arcflash resulted, blowing the door open. Because that employee was wearing his arc-rated flash suit, he received no injuries.

Arc-Flash The photo shows the result of the arc event. If this employee had not assessed the risk, or had downplayed the risk and not worn the required PPE, there’s no doubt he would have been seriously injured or killed. For the time it took to complete the risk assessment, this worker saved himself several weeks or months of painful recovery. Was it worth it? You bet.

Fig.3: Aftermath of the Arc Event, Works Arc-Flash Event, 12-11-2009

REFERENCES “National Highway Traffic Safety Administration Press Release 50-14,” December 19, 2004. Public Works Arc-Flash Event, 12-11-2009 James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers. Note: The author would like to thank Ray Crow of DRC Consulting and Tony Demaria and Gary Donner of Tony Demaria Electric for their permission to borrow content for this article from their joint presentations. The author and these colleagues have copresented tutorials at the IEEE Electrical Safety Workshop and at NETA’s PowerTest Conference.

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DO I NEED TO WEAR ARC-RATED PPE WHEN WORKING AROUND ENERGIZED EQUIPMENT? NETA World, Summer 2013 Issue Ron Widup and Jim R. White, Shermco Industries At this year’s IEEE Electrical Safety Workshop several people asked the same question, “Do I need to wear arc-rated PPE when working around energized electrical equipment?” This question seems to come up frequently, so there must be some confusion in the industry about when to wear arc-rated PPE. In each case the people asking the question referred to “130.7(C)(15) Informational Note No. 2” which states: “The collective experience of the task group is that, in most cases, closed doors do not provide enough protection to eliminate the need for PPE for instances where the state of the equipment is known to readily change (for example, doors open or closed, rack in or rack out).” (Remember that “Article 130.7(C)(15)” is “Selection of Personal Protective Equipment When Required for Various Tasks.”) The rationale was that if the doors do not provide protection, there exists an arc-flash hazard even if the doors are closed.

to-bus connection. If an arc were to occur, it most likely would be a serious event. Contrast that with the operation of a circuit breaker or switching device, which is designed to operate under load. These devices have arcing contacts and arc extinguishers that contain the arc, stretch it and cool it, and then extinguish it (see Figs. 1a and 1b), whereas the bus connection (primary disconnect) that makes during racking operations is more like an electrical disconnect and is not designed to operate under load (see Fig. 2).

There are several things wrong with this line of reasoning. The first is that electrical equipment with the doors closed and properly latched and secured is considered guarded. This means they are not accessible and, therefore, do not normally present a risk to people around them. The second problem with this line of reasoning is the informational note (IN) attached to the definition of arc-flash hazard in “Article 100,” which states, “Informational Note No. 1: An arc-flash hazard may exist when energized electrical conductors or circuit parts are exposed or when they are within equipment in a guarded or enclosed condition, provided a person is interacting with the equipment in such a manner that could cause an electric arc. Under normal operating conditions, enclosed energized equipment that has been properly installed and maintained is not likely to pose an arc-flash hazard.” This informational note contains important information which is intended to clarify when an arc-flash hazard may or may not be present. An arc-flash hazard may be present when energized electrical equipment is in a guarded condition, if a worker interacts with it in a manner that could cause an electrical arc. Electrical equipment that is operating normally and is not being interacted with is not designed to create an electrical arc. An electrical arc could occur during abnormal operations or during periods of interaction such as inserting or removing a circuit breaker (racking), or installing or removing fuses, or whenever a device is connected or disconnected to an energized source (MCC buckets, bus duct fuses, circuit breakers, etc). The risk of an arc flash is increased during these operations because the equipment has no arc extinguishers at the circuit breaker-

Figs. 1a and 1b: Arc-Extinguishing Components in a 480-Volt Circuit Breaker

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equipment. The higher voltages stress insulation to a greater degree, and if there is an arc flash, chances are it could be more severe. Many older installations, or newer installations that have been modified after initial construction, may not have adequate clearances between the switchgear and walls or other structures. The 70E Committee decided to err on the safe side with the higher voltage equipment and not put forth the same assertion as stated with the 600-volt rated equipment.

EVERYONE TAKE A DEEP BREATH Fig. 2: Circuit Breaker-to-Bus Connection The second part of IN No. 1 in “130.7(C)(15)” states that equipment that is properly installed and maintained is not likely to pose an arc-flash hazard under normal operating conditions. This means that if it is operating normally and has been installed and maintained in accordance with local and national codes and standards, it presents no increased risk of failure and arcflash hazard. It also means that if the equipment is operated in the manner that the manufacturer designed it to operate such as starting, stopping, opening, and closing – no increased risk of an arc flash is present. Some people have difficulty with this, as they believe opening and closing a switch or circuit breaker is interacting with equipment. It is, but it is not interacting in a manner that could cause failure such as racking or the other tasks that could cause an arc flash. To illustrate this fact further, “Article 130.6(K)” states, “(K) Routine Opening and Closing of Circuits. Load-rated switches, circuit breakers, or other devices specifically designed as disconnecting means shall be used for the opening, reversing, or closing of circuits under load conditions. Cable connectors not of the load-break type, fuses, terminal lugs, and cable splice connections shall not be permitted to be used for such purposes, except in an emergency.” Switches and circuit breakers are loadrated devices and are specifically designated by the NFPA 70E for the purpose of opening and closing of circuits while energized. To further clarify what is meant, the NFPA 70E Committee added “Article 130.7(A), Informational Note No. 2:” It is the collective experience of the Technical Committee on Electrical Safety in the Workplace that normal operation of enclosed electrical equipment, operating at 600 volts or less, that has been properly installed and maintained by qualified persons is not likely to expose the employee to an electrical hazard.” This is virtually the same language used in the informational note for the definition of an arc-flash hazard.

HIGHER VOLTAGE EQUIPMENT So the informational note in “Article 130.7(A)” references 600volt and below equipment, but what about electrical equipment rated above 600 volts? Higher-voltage, electrical equipment can present additional risks that are not present with 600-volt class

NFPA 70E provides minimum safe work practices. We would never tell workers not to wear additional protection if the worker feels it might be needed. Circuit breakers and switches have been known to fail, even though they appear to be normally operating. If we were operating higher amperage circuit breakers or switches, we would have HRC-2 arc-rated PPE and clothing on, just in case. NFPA 70E does not require this level of protection, but for peace of mind it would be our choice. What level of discomfort does this really present? Not much, really; in fact, it is likely that we already have arc-rated coveralls on (many companies already require HRC-2 daily work wear), a balaclava, and arc-rated face shield along with hearing protection and rubber insulating gloves/ protectors. The wearing of this level of PPE is preferable to spending weeks or months in a hospital recovering from an arcflash event. NFPA 70E cannot possibly foresee any and all risks, nor can it account for any and all circumstances. It is the worker about to perform the tasks(s) that has to make judgment calls as to what is needed.

Companies are responsible for the safety of their employees and may require any level of protection, or institute any safe work practice they believe necessary to provide a safe workplace. Workers may or may not agree with these work rules, but OSHA will hold companies to them if they are part of the company’s safe work practices. Several companies require workers to wear rubber insulating gloves if they are within 18 inches of energized conductors or circuit parts. NFPA 70E says 12 inches. Who is correct? The company, as it has the responsibility for worker safety at its site. Any work practice that meets or exceeds NFPA 70E minimum requirements is acceptable.

62 If a worker approaches energized electrical equipment and does not believe it is normally operating, for any reason, that worker should re-evaluate what protective equipment is required. In most cases that equipment should be shut down before working on it if there is any doubt that it is safe to proceed. If a worker receives a trouble call about a piece of equipment and has to operate it, he/ she should be wearing all the arc-rated PPE and clothing required, as it is no longer normally operating. Any type of troubleshooting task requires full arc-rated PPE and clothing. Electrical equipment that is out-of-date for maintenance, equipment that is visibly deteriorated or equipment that has no maintenance labels attached and has no record of its last maintenance, is not to be considered normally operating.

SUMMARY Everyone likes to hit the EASY button. The problem is, when working on or around energized electrical equipment, there is no EASY button. Each task and each device has to be evaluated at the time the work is to take place in order to proceed. What was true last year, last month or even earlier in the day may not hold true at the moment you are about to perform a task on equipment. Things change rapidly in the real world, and we need to be alert to those changes. Being alert also means being alert to faulty Job-Hazard Analysis information, lockout/tagout processes, other workers who may demonstrate a lack of concentration or focus, or any other potential issues in and around the equipment. Don’t be myopic when viewing safety, and don’t be lazy. Arc flash doesn’t kill as many workers as electrical shock, but the injuries are much more substantial and may require months of rehabilitation to recover. Don’t be a statistic; be smart, work smart. It’s that easy. Ron Widup and Jim White are NETA’S representatives to NFPA Technical Committee 70E (Electrical Safety Requirements for Employee Workplaces). Both gentlemen are employees of Shermco Industries in Dallas, Texas a NETA Accredited Company. Ron Widup is President of Shermco and has been with the company since 1983. He is a Principal member of the Technical Committee on “Electrical Safety in the Workplace” (NFPA 70E) and a Principal member of the National Electrical Code (NFPA 70) Code Panel 11. He is also a member of the technical committee “Recommended Practice for Electrical Equipment Maintenance” (NFPA 70B), and a member of the NETA Board of Directors and Standards Review Council. Jim White is nationally recognized for technical skills and safety training in the electrical power systems industry. He is the Training Director for Shermco Industries, and has spent the last twenty years directly involved in technical skills and safety training for electrical power system technicians. Jim is a Principal member of NFPA 70B representing Shermco Industries, NETA’s alternate member of NFPA 70E, and a member of ASTM F18 Committee “Electrical ProtectiveEquipment for Workers”.

Arc-Flash

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UNITED STATES

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

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arizona

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

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ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

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ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

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ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

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Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

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Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

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Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

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Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

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Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

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Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

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Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

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Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

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Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

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Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

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Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

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Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

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RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

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Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

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Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

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RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

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CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

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CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

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Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

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Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

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Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

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Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

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Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

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High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

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Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

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Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

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florida 50

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C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

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ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

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indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

missouri 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

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152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

182

183

184

185

186

187

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189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

197

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199

200

201

POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

206

207

208

209

210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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243

244

Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

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CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: ●● The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. ●● NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. ●● A Registered Professional Engineer will review all engineering reports. ●● All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). ●● The firm is a well-established, full-service electrical testing business.

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ANDBOOK

VOLUME 1

SERIES III

CIRCUIT BREAKERS

CIRCUIT BREAKERS Vol. 1 HANDBOOK

SERIES III

Published By Sponsored by

BCS Switchgear

CIRCUIT BREAKERS VOLUME 1

HANDBOOK

Published by

InterNational Electrical Testing Association

CIRCUIT BREAKERS–Vol. 1 HANDBOOK TABLE OF CONTENTS Predicting the Remaining Life of Vacuum Interrupters in the Field.............................. 5 John Cadick, Finley Ledbetter, Alan Seidel

Understanding and Troubleshooting Breaker Control Schemes............................... 14 Rick Youngblood

A Systemic Approach to High-Voltage Circuit Breaker Testing................................ 16 Charles Sweetser

Maintenance Testing of Low-Voltage Power Circuit Breakers in a Large Automotive Assembly Plant................................................................ 26 Mose Ramieh III, Randall Sagan

Circuit Breaker and Transducer: Where Do I Connect?......................................... 32 Robert Foster

How Disruptions in DC Power and Communications Circuits Can Affect Protection....................................................................................... 40 Karl Zimmerman, David Costello

Curb Circuit Breaker Performance Fear with Testing ............................................ 50 Roberts Neimanis, Robert Foster, Nils Wacklen

Determining Circuit Breaker Health Using Vibration Analysis................................. 53 John Cadick, Finley Ledbetter

Do You Know the True Condition of your Circuit Breaker?..................................... 61 Michael Skelton, Camlin Power

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

First Trip Testing.............................................................................................. 64

Kenneth Elkinson, Matthew Lawrence, Tony McGrail

Extending the Life of Existing Switchgear............................................................ 66 Miklos J. Orosz

Modern Protection Schemes for Low-Voltage Circuit Breakers, Part 1...................... 70 Dan Hook

Testing and Certifying Modern Protection Schemes for Low-Voltage Circuit Breakers, Part 2.............................................................. 73 Dan Hook

Field Testing Techniques for Low Voltage Circuit Breakers...................................... 77 Bruce M. Rockwell

Vacuum Interrupters: Pressure vs Age – A Study of Vacuum Levels in 322 Service Age Vacuum Breakers............................ 80 John Cadick, Finley Ledbetter, John Toney, Jerod Day, Gabrielle Garonzik, Finley Ledbetter III

The Criticality of Circuit Breaker: Testing Millisecond Performance Matters – A Lot.................................................. 86 Elsa Cantu

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024 269.488.6382

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Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Circuit Breakers Vol.1

PREDICTING THE REMAINING LIFE OF VACUUM INTERRUPTERS IN THE FIELD PowerTest 2013 John Cadick, P.E., Cadick Corporation Finley Ledbetter, GroupCBS Alan Seidel, P.E., Lower Colorado Authority

ABSTRACT Vacuum interrupters have widely replaced older air-magnetic and oil interrupters for circuit breakers rated at 1 kV or higher and offer up to 10 times the expected lifetime than newer SF-6 gas interrupters. During manufacture, vacuum interrupters undergo contact-resistance, high-potential, and leak-rate tests. However, only the leak-rate test offers insight into the remaining lifetime of the vacuum interrupter. Leak-rate testing requires the use of a magnetron, which has prevented this test from being widely used in the field. New portable magnetron and vacuum-pump equipment now makes it possible to perform leak-rate tests in the field. This paper details a new predictive vacuum field test based on the leak-rate test that uses portable magnetrons and vacuum pumps, condition based maintenance algorithms, and both device-specific and generic vacuum interrupter current-vacuum curves that are based on vacuum pressures and device geometries.

INTRODUCTION

More recently, vacuum interrupters (VI) have supplanted many airmagnetic and oil-based interrupters because of their ability to interrupt power faster – improving equipment and personnel safety – for more cycles than older interrupters, which translates to longer lifetimes for circuit protection equipment and less cost to the user for replacement interrupters. VI manufacturers use three electrical tests to validate the operation of their products before sending them into the marketplace: contactresistance, high-potential, and leak-rate testing. Of these three, only leak-rate testing provides results beyond “pass/fail,” which provides data for computerized maintenance management systems (CMMS) and enterprise asset management (EAM) systems. Leak-rate tests provide quantifiable data based on the internal pressure and vessel geometry that allows maintenance personnel to use predictive maintenance procedures and programs that result in higher equipment uptime and longer lifecycles compared to reactive maintenance programs. However, until recently, leak-rate tests could not be conducted in the field because they required large, expensive magnetrons to generate magnetic fields that are necessary for leak-rate tests. New equipment such as portable magnetrons and condition based maintenance (CBM) algorithms detailed in this paper enable technicians to perform leak-rate tests in the field, generating quantifiable data that can be used as part of a predictive maintenance program.

HISTORICAL PERSPECTIVE

Fig 1: Vacuum Interrupter External View Circuit protection protects electrical service personnel, physical assets, and production schedules against shorts, faults, and dangerous arcing conditions. In addition to protecting equipment from power surges and sags that result in immediate equipment failure, circuit breakers, interrupters, and other protective devices also protect equipment from partial failures and faults that shorten the lifetime of electrical equipment. For circuit protection application with voltages in excess of 1 kV, electricians and maintenance personnel traditionally have used circuit breakers with either air-magnetic or oil-based interrupters.

Historically, air-magnetic and oil interrupters were the only types of interrupters used on circuit breakers rated at 2.4 kV and higher. The air interrupters predominated the lower voltages in this range – from 2.4 kV to 15 kV and occasionally up to 25 kV. Above 25 kV, oil interrupters were the more commonly used primarily because of their ability to interrupt higher arc energies.

Air-Magnetic Interrupters Air-magnetic interrupters degrade somewhat each time they are opened under load, and they degrade significantly if they are interrupted under fault. The contacts can be repaired or replaced if required; however, the maintenance of these types of circuit breakers was not always properly scheduled sometimes resulting in failures. In addition to the maintenance problem, the arc chutes are very large and heavy. Some of the arc chutes on these breakers are also somewhat fragile and are broken if not properly handled.

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Circuit Breakers Vol.1

Oil Interrupters

●● They are relatively compact and sealed.

Oil interrupters are also very heavy. More importantly, the interrupter itself is submerged in oil and is difficult to reach for inspection. Testing methods such as contact micro-ohmmeter tests, insulation resistance tests, and power factor tests are quite reliable in determining the condition of the interrupter. However, like air-magnetic interrupters, these units are not always maintained as they should be.

●● The travel required to open is very short with distances that vary with age and manufacturer. The actual travel distance varies with VI geometry and voltage level; however, typical distances range from approximately 8 mm (0.314 in) to 12 mm (0.472 in).

In addition to maintenance and size problems, stricter environmental requirements make using these types of interrupters subject to increased regulation and higher cost of maintenance.

●● When VIs experience one of their relatively rare failures, the resulting damage is often much less than air-magnetic interrupters. However, they still can fail spectacularly, causing great damage.

Vacuum Interrupters Partially as a response to many of the issues with air-magnetic and oil interrupters, widespread use of VI technology and SF-6 technology in electric power distribution systems started more than 30 years ago. In the intervening years, the VI has become the choice for the vast majority of circuit breakers applied between 1,000 volts and 36,000 volts. The VI (See Figures 1 and 2) is lightweight, sealed from the atmosphere, and has a very long predicted useful life. Since VI technology was first used in the industry, typical predictions have been 20 or 30 years.

●● They have the longest expected service life of any interrupting method.

●● The low-mass movement allows for a lighter operating mechanism that is cheaper and lasts much longer.

VI OPERATING PRINCIPALS The VI’s high interrupting capacity is based on the physical principle discovered by Louis Karl Heinrich Friedrich Paschen (1865-1947):

V=

apd

ln(pd) +b

Paschen did original experimental research and discovered that the dielectric strength (V) of a gas is a function of the gas pressure (p), the distance between the two electrodes (d), and the type of gas. Equation 1 shows this relationship. Note that a and b are constants that are derived for dry air. (For more information see. 4)

Fig. 3: Paschen Curve for Dry Air Fig. 2: Internal View of a Vacuum Interrupter As might be expected, the primary basis for the wide acceptance of vacuum interrupters is financial. Consider that VIs offer vastly longer life and greatly reduced maintenance costs when compared to air-magnetic and oil interrupters. Their lifespan/number of operations specs are up to 10 times those of the older technologies; furthermore, the useful life of the VI may be up to fifty percent (50%) greater than SF-6 interrupters. At least part of the reason that a VIs is so long-lived is because of their simple, yet rugged construction. Other advantages of VIs include the following:

Figure 3 is taken from a paper presented by Falkingham and Reeves.[1] It shows that the dielectric strength of air starts to increase dramatically as the air pressure drops below approximately 10 Pa (10-1 millibar).[1] It continues to rise swiftly until pressure reaches approximately 10-1 Pa (10-3 millibar), and then remains fairly steady at slightly less than 400 kV/cm (approximately 1000 kV/in).[1] This means that the typical contact gaps (8 mm to 12 mm) will have dielectric strengths between 320 kV and 1200 kV or higher for vacuum levels between 10-1 Pa and 10-6 Pa. The interrupting capacity in a VI will vary depending on contact design, contact

7

Circuit Breakers Vol.1 separation, and vacuum level. The contact design and separation are design features for any given VI. However, we have shown that the interrupting ability will be very high and very sensitive to the pressure (vacuum) level inside the VI.

VI CONSTRUCTION The following discussion refers to Figure 2 and provides a very brief overview of the construction of the VI. Understanding this information will help the reader to better understand the later discussion about the maintenance problems associated with the VI, and provide the basis to analyze the value of the new field test which will be presented.

VI FACTORY TESTS The following tests are among those that are most commonly applied by manufacturers when a VI is manufactured and/or when it ships to a customer. The coverage is not exhaustive; however, each test and its importance will be explained in enough detail to allow understanding of the remaining parts of the paper. These tests may be performed on an entire batch of new VIs or – more commonly – on a statistically significant sampling taken from the new batch. The three that are discussed are related directly to the service life of the VI.

Contact Mechanism The contact structure comprises two parts – the moving contact assembly and the fixed contact assembly. The fixed contact is stationary and held firmly in place, while the moving contact is free to move. When the circuit breaker operates, the moving-contact stem moves the contact and compresses (open) or decompresses (closed) the bellows. The bellows system provides a much more secure seal than a bushing gasket.

Metal-Vapor Shield The metal-vapor shield has three critically important purposes. The following information is paraphrased from, The Vacuum Interrupter: Theory, Design, and Application by Paul G. Slade.2 ●● It captures the metal vapor created by the metallic arcing that occurs when the contacts open. The metal vapor is highly ionized and, in addition to the thermal expansion, is drawn to the vapor shield by electrostatic force. When the vapor contacts the shield, it quickly solidifies and adheres to the shield. This helps maintain the vacuum level inside the VI. ●● It also serves to keep the electrostatic field uniformly distributed both inside and outside the VI.

Fig. 4: The Leak-Rate Test Set Up (Magnetron Atmospheric Condition (MAC) Test)

Contact-Resistance Test

●● It protects the ceramic body from the high levels of radiation during arcing and interruption, and prevents any high-level arcs from directly contacting the ceramic body.

A micro-ohmmeter is applied to the closed contacts of the VI, and the resistance is measured and recorded. The result is compared to the design and/or the average values for the other VIs in the same run.

Ceramic Body

High-Potential Test

Porcelain ceramic has become the predominant material for the body of the VI. The characteristics that have made it the material of choice include high strength, good dielectric strength, the ability to withstand very high temperatures, impermeability to helium (He), extremely low permeability to hydrogen (H2), and the ability to form very tight seals with brazed metal connections such as the bellows, metal-vapor shield, and the fixed contact stem.

A high-potential voltage is applied across the open contacts of the VI. The voltage is increased to the test value and any leakage current is measured. Factory testing may be done with either AC or DC high-potential test sets. DC is less commonly used because high DC voltages can generate x-rays when they are applied across a vacuum contact.

While all of these are very important, tight seals and low permeability are arguably the most important with respect to the long life of a VI. As discussed above, the vacuum level is the key to the proper operation of a VI.

Leak-Rate Test (MAC Test) This test is based on the Penning Discharge Principle, which is named after Frans Michael Penning (1894-1953). Penning showed that when a high voltage is applied to open contacts in a gas and the contact structure is surrounded with a magnetic field, the

8 amount of current (ion) flow between the plates is a function of the gas pressure, the applied voltage, and the magnetic field strength. Figure 4 shows a diagram of the test set-up used for the leak-rate test. Placing the VI into a field coil sets up a magnetic field test. The field is created by a DC current and remains constant during the test. A constant DC voltage, usually 10 kV, is applied to the open contacts, and the current flow through the VI is measured.[2] Since the magnetic field (DC) and the applied voltage (DC) are both known, the only variable remaining is the pressure of the gas. If the relationship between the gas pressure and the current flow is known, the internal pressure can be calculated based on the amount of current flow. Although manufacturers’ shipping criteria vary, most new VIs ship with internal pressures of 10-5 Pa or less. The factory leak-rate test procedure is as follows: ●● The internal pressure is determined as described in the preceding paragraphs. ●● The VI is placed in storage for a period of time – usually a minimum of several weeks. ●● The VI’s internal pressure is tested again. This test is sensitive enough that even in that short time a very tiny change will be observed. ●● The difference between the two tests is used to develop a leak rate vs. time curve. Referring to Figure 3, you see that if the pressure rises above 10-2 Pa, the dielectric strength – and thus the interrupting capability – will start to deteriorate. The calculated number of years required for the pressure to reach 10-2 Pa will indicate the expected service life of the VI.

VI FAILURE MODES Although vacuum interrupters are very long-lived, they have a useful service life just like any piece of equipment. The projected life of a VI, as determined by the factory leak-rate test, assumes a constant leakage rate throughout the life of the VI – an assumption that may not be valid for any given interrupter. Also consider that if not properly maintained, all equipment will fail eventually. VIs are not an exception to this rule. There are several possible types of VI failure. ●● The most common failure occurs when a VI reaches its wear limits. The VI has a set of soft copper alloy contacts that are mechanically shocked every time the breaker is opened and closed. When no current flows, the damage to the contacts is caused primarily by the mechanical shock. Every time it is opened under load, overload, or fault current, some of the contact material is lost to metal vapor and re-deposited other places in the VI canister – hopefully, but not always, on the metal-vapor shield.

Circuit Breakers Vol.1 ●● Another common failure is internal arc flash-over caused by metal vapor and sputtering material being deposited on the inside of the canister. This is especially bad if the material is deposited on the inside of the ceramic shell as it greatly reduces the insulation quality of the shell. Since the shell must be able to withstand the recovery voltage caused by an arc interruption, insulation failure of the shell can cause a catastrophic mechanical failure of the VI. ●● A third type of failure is loss of vacuum due to mechanical failure of the bellows, pinch tube, or a manufacturing defect. This type of failure is quite often related to the number of operations multiplied by the number one killer on any VI – torsion exerted on the bellows. Even 1 degree of torsion on the bellows can reduce the number of operations by a factor of 10. This torsion can be caused by improper installation either at the factory or reinstallation during an overhaul. Wear on the breaker mechanism during operations can also introduce torsion. ●● Last is the loss of vacuum due to leak rate. The leak rate was checked at the factory and is determined generally to exceed 20 or even 30 years; however, the leak rate can be greatly increased by improper installation, failure of components, or damage during maintenance procedures. Recent field experience shows an increasing number of high-pressure and dead-in-the-box, new VI in manufactured VCBs. Of course, life extension and failure prevention can both be dramatically improved by proper maintenance.

VI FIELD TESTS Of the three factory tests discussed earlier in this paper, only two have been used in the field – the contact-resistance test and the high-potential test. Neither of these is able to determine the vacuum pressure inside the VI.

Contact-Resistance and High-Potential Field Tests The high-potential test is a go/no-go result, and even a DC highpotential test set will not give predictable results that can be used. The DC high-potential test results may show a gradual decrease in resistance over time, but it is not sufficient to determine when, or if, the gas pressure has dropped to critical levels – at least not until the interrupter fails. As previously noted, the pressure inside a VI will increase with time. There will always be some leakage in even the best-made VI. That leakage may be slow enough that the VI will meet or even exceed the manufacturer’s predicted service life. On the other hand, unexpected increases in the leakage rate can greatly shorten its life. As described in the previous paragraph, none of the classic field tests can effectively evaluate the condition of the vacuum inside the VI.

9

Circuit Breakers Vol.1

○○ The available coils used to create the magnetic field could not be used in the field. ○○ There were few VIs that had graphs showing the relationship between ionization current and (vacuum) pressure. ○○ The trending and prediction tools available for evaluating such a test were not available. However, this has changed with the introduction of new technology that has been researched extensively and developed during the last five years. ●● Magnetrons for Field and Shop Use With industry improvements in components and manufacturing capability, magnetrons such as the one shown at the right in Figure 6, are now coming onto the market for field use. It is small and portable and will retain calibration with only the normal procedures as specified in industry standards for field testing.

Fig. 5: Failed Vacuum Interrupter Many VIs have been in service for 20, 30, or more years. A huge percentage of them are well past their predicted life. Figure 5 shows a failed pole assembly. This failure occurred fairly recently. Industry studies are showing that an increasing number of such failures are occurring. It cannot be stated to a 100% certainty that the proximate or root cause of the failure shown in Figure 5 was insufficient vacuum. However, it can be stated to a high degree of certainty that had the vacuum pressure been in the acceptable range of 10-2 Pa to 10-6 Pa, the bottle would not have failed.

Predictive Vacuum Field Test Based on the long-used factory leak test, a new field test is successfully being used to measure the vacuum pressure on service aged VI’s. ●● Roadblocks and Solutions The test equipment that is used to test vacuum in a VI is called a magnetron. In the past both technical and logistical problems have prevented the use of the magnetron in the field. The major challenges have been as follows: ○○ The magnetron and its associated equipment have been too bulky to be used in the field. ○○ Existing magnetrons have been very touchy about keeping their calibration when moved.

Fig. 6: Portable Magnetron (right) with Test Stand (left) ●● Applying a Magnetic Field to the VI When tested in the factory or shop, the VI is inserted into a magnetic coil, which is energized by the magnetron. The device on the left side of Figure 6 is a stand with an integrally mounted coil used for such testing. Although these types of coils can be used in the field, they are quite bulky, especially in the sizes required for some of the larger VIs. In addition to their weight, such a coil requires that the VI be removed from the breaker mechanism to be tested. Since removing the VI from its breaker is time consuming and may lead to errors, flexible magnetic field coils (FMFC), such as that shown in Figure 7, have been developed.

10

Circuit Breakers Vol.1 and proven methods of developing this relationship. Both methods have been developed and tested using the laboratory setup shown in Figure 9.

Fig. 9: Test Setup for Developing Vacuum Versus Current Flow Data Fig. 7: Flexible Magnetic Field Coils This specially designed coil is shown wrapped around the VI itself – a method not physically possible on all vacuum breakers. Placement of the FMFC cannot be arbitrary. Research has furnished the required information on where to place the coil to create reproducible, accurate results. Further research has shown that the FMFC can also be used around one or more field pole assemblies as shown in Figure 8.

To create the vacuum vs. current curve, a VI is opened and a vacuum pump (red equipment on the left) is connected to it so that the pressure can be gradually decreased. The magnetron (not shown in this photo) is also connected to the VI. It applies the voltage and the magnetic field and records the resulting current for each different pressure point. The data collected may be saved to create graphs, tables, or even equations that express the relationship. After the information is collected it can be stored on the magnetron, and each data set is correlated to its particular VI. When a field test is performed, the operator tells the magnetron which VI is being tested. The magnetic field and the test voltage are applied, and the magnetron prints out the pressure that correlates to the resulting current flow. ●● Evaluating the Data

Fig. 8: FMFC Applied around Entire Pole Promising research is ongoing into the possibility of other, more convenient types of magnetic field coils. It is believed that this research will lead to direct application field coils that will provide acceptable results. ●● Creating Pressure vs. Current Data To determine the vacuum level in a VI, the relationship between the ionization current and pressure must be programmed into the test equipment. At present there are two well-researched

Using the magnetron in the field allows the VI vacuum pressure to be tested every time field testing is performed. The tested pressure value along with other relevant data is entered into a modern CBM diagnostic and predictive algorithm. The algorithm evaluates the results and develops a highly accurate evaluation of the current data to previous data and calculates expected future values for life prediction purposes. This approach has been used previously to accurately analyze oil test results, insulation resistance results, and a host of other such tests. The initial results on predicting the expected vacuum pressures and expected service life have proven to be equally accurate. ●● VI Size vs. Vacuum Level Because of the large number of different manufacturers and models of VIs, developing individual curves for each vacuum interrupter will be a laborious task. Curves for a large number of the

11

Circuit Breakers Vol.1 more common VIs are currently being developed, and curves for any VI can be developed on request. Research shows that the vacuum versus current relationship strongly correlates to the geometry of the VI. It has been seen that accuracies of ± 10% are realized when curves are developed solely on the basis of VI diameter. This relationship has allowed the development of six or possibly seven generic curves that can be used successfully in determining the vacuum in most vacuum interrupters in service today.

Since this was the first time that these breakers had been tested using the MAC test, there was no possibility of applying trending or prognostic programs. However, since leak rate is a trendable measurement, the MAC test will become extremely more valuable in the coming years.

VI FIELD TEST CASE STUDY During March 26 through March 28, 2012, field technicians from a qualified electrical testing firm performed field maintenance and testing on 60 vacuum circuit breakers at an electrical utility power plant. All of the breakers at this location were 25 years old or more. There had been two in-service failures in the months leading up to the service period. In addition to the standard field tests, the vacuum level was determined using a current versus pressure table that was developed for the specific vacuum interrupters on the breakers. Evaluation criteria are shown in Table 1.

Fig. 10: CBM Flow Chart

Table 1 VI Condition Based on MAC Test (Vacuum Pressure) Pressure (Pascals)

Condition

Operations*

Contact Wear**

Recommendation

A

< 1000

< 50%

P < 10-5

Retest in 10 years or less

B

< 1000

< 50%

10-5 < P < 10-4

Retest in 5 years or less

C

< 1000

< 50%

10-4 < P < 10-3

Possibility of failure place in non-critical service; retest annually

D

< 1000

< 50%

10-3 < P 10-2

High probability of failure; repair or replace

*If operations are > 1000 and breaker is used for motor sharing – degrade by one Condition (e.g. B to C) **(Actual Wear / Maximum Allowed Wear) * 100 where Maximum Wear = 0.125 in. (.32 mm)

The criteria were applied as follows: ●● The pressure criteria were used first to establish A, B, C, or D condition. ●● If the contact wear was greater than 50% or if there were more than 1000 operations, the condition was elevated by one (A to B or C to D, for example). Eight out of the 60 breakers were found to have a total of 10 vacuum interrupters that fell into Condition C and/or Condition D. Two of the 10 interrupters had excessive contact wear and might have been flagged by the contact wear test alone; however, the other eight would not have been caught by the classic tests. If the MAC test had not been performed, eight vacuum breakers that were in imminent danger of failure would have been put back into service.

CONDITION BASED MAINTENANCE (CBM) ALGORITHMS For trendable test data (such as insulating oil screening and DGA tests), CBM mathematical algorithms have been developed and proven to: ●● Provide predictions of future results out to two years with up to 95% accuracy and within ± one-half standard deviation. ●● Allow much more accurate end-of-life predictions for large equipment. Such algorithms go far beyond a simple linear trending approach by using multivariate self-learning mathematical structures and/or artificial neural networks.3

The CBM Process Although a detailed description of the application of CBM algorithms is beyond the scope of this paper, Figure 10 is a flow chart of the process. The following general steps explain the chart. ●● The maintenance and inspection program creates three basic types of data as follows: ○○ Real-time monitoring information ○○ Off-line test data ○○ Subjective data such as average temperature, age, and physical condition.[3] ●● T  he data is sorted and stored for both computation and archival purposes.

12

Circuit Breakers Vol.1

●● The CBM algorithm “crunches” the numbers. ●● The results are analyzed by the algorithm, and reports along with recommendations for further action are printed. ●● Corrective or replacement actions are then completed.

The Benefits of CBM A CBM approach to maintenance provides three key rewards to those who employ it: ●● Efficient scheduling of the frequency and intensity of maintenance ●● More accurate asset life predictions allowing long-term operational and financial planning ●● Improved employee and plant safety accruing as a result of the improved maintenance. The payback is well-known by those organizations that employ CBM.

CBM and the MAC Test Any statistical analysis package, such as a CBM process, requires a historical data set to work properly. Since MAC test is relatively new to field maintenance, the process is still early. However, data is being collected, and the comparison of collected data to previous maintenance areas (such as the evaluation of insulating liquid) is very promising. In only a few years, we expect to see a marked improvement in maintenance efficiency and a reduction in the number of unexpected failures of vacuum interrupters.

CONCLUSIONS As they reach the end of the predicted lives, VIs are starting to fail in greater numbers. In many – if not most – cases, the VIs in the field have long exceeded their manufacturer-predicted life. Failures of the VI are often catastrophic with loss of the VCB switchgear, or worse. The 20-year manufacturer’s original suggested life has generally been ignored by users. This has placed a large portion of the U.S. industrial and utility distribution switchgear at risk of failure. Only through diligent testing and some luck can users expect no events to occur in the future. No one suggests that ignoring this possible failure is acceptable. And every VI will fail; we just do not know when.

Fig. 11: The Maintenance Puzzle Thousands of medium-voltage power circuit breakers have passed through service shops and the hands of credible testing companies. When these breakers were returned to their owners, many thought that they were guaranteed to last until the next maintenance cycle. This is not true. When breakers are maintained and tested using traditional methods, they go back into service with only one guarantee: this device will function today. Many of these have failed or will fail before the next scheduled maintenance cycle. This is a problem we have been working to solve for over 10 years. With the addition of the MAC test in the field, this need no longer be the case. Figure 11 illustrates the problem. Until now, determining the remaining life of a vacuum interrupter was like working on a puzzle for weeks, only to determine the key piece was missing. The following list summarizes what we have been doing and what data we have been gathering when maintenance is performed. ●● Breaker type ●● VI part number and serial number ●● Number of operations ●● Operating environment ●● Wear indication ●● Contact resistance ●● High-potential go/no-go test ●● Circuit criticality Clearly we have been missing a key part of the puzzle.

Circuit Breakers Vol.1 Although not yet in general use, the field test described in this paper has been tried and proven. Setting up for and performing the test is no more difficult than many of the field tests that we have become familiar with such as insulation testing, power factor, and partial discharge. The results are extremely accurate in determining both the vacuum level and in developing predictive data for the future. Some have even compared it favorably to the procedures that are routinely used for insulating liquid testing. Additional research is ongoing, and we expect to see a general deployment of this test over the coming years. Remember all VIs will fail; it is only a matter of time. No assembled VI is impermeable; therefore, all have substantial leak rates. Will they fail when called upon to protect a critical load during a short circuit, or will they fail while in service and cause unexpected shutdown? When the test described in this article is employed, the possibility of such failures is greatly reduced.

ENDNOTE

[1] For those of you who are still more attuned to English units of measure, one atmosphere is approximately 14.7 psi (101 kPa). [2] The machine used to generate the magnetic field and the high voltage iss called a magnetron. It is described briefly later in this paper. [3] In this case, the term subjective is used to indicate information that is not the result of an actual test.

REFERENCES 1 Leslie Falkingham and Richard Reeves, Vacuum Life Assess-

ment of a Sample of Long Service Vacuum Interrupters, 20th International Conference on Electricity Distribution, Prague June 8-11, 2009, Paper# 0705

2 Paul G. Slade, The Vacuum Interrupter: Theory, Design, and

Application, CRC Press 2008, Page 232.

3 John Cadick, PE and Gabrielle Traugott, Condition Based Main-

tenance: A White Paper Review of CBM Analysis Techniques, PowerTest 2011 (NETA), Washington, DC, February 21- 24, 2011. 4 Husain, E. and Nema, R.S, Analysis of Paschen Curves for air,

N2 and SF6 Using the Townsend Breakdown Equation, IEEE Transactions on Electrical Insulation, Volume EI-17,August, 1982, pp 350-353 5 Storms, A.D.; Shipp, D.D., Life extension for electrical power

distribution systems using vacuum technology, Industry Applications, IEEE Transactions on, Volume: 27 , Issue: 3 , Publication Year: 1991 , Page(s): 406 - 415

6 Okawa, M., Tsutsumi, T.b Aiyoshi, T., Reliability and Field

Experience of Vacuum Interrupters, Power Delivery, IEEE Transactions on, Volume: 2 , Issue: 3, Publication Year: 1987 , Page(s): 799 – 804

13 John Cadick is a registered professional engineer and the founder and president of the Cadick Corporation. He has specialized for over four decades in electrical engineering, maintenance, training, and management. Prior to creating the Cadick Corporation, he held a number of technical and managerial positions with electric utilities, electrical testing companies, and consulting firms. In addition to his consultation work in the electrical power industry, Mr. Cadick is the author of Cables and Wiring, DC Testing, AC Testing, and Semiconductors published by Delmar. He is also principal author of The Electrical Safety Handbook (published by McGraw Hill) and numerous professional articles and technical papers. Mr. Cadick has a BSEE from Rose-Hulman Institute of Technology and an MSE from Purdue University. Finley Ledbetter, Group CBS, Inc. has worked in the field of power engineering for 30 years, including serving as an applications engineer and instructor for Multi-Amp. He was the founder of Shermco Engineering Services and Western Electrical Services, both NETA-accredited companies. Mr. Ledbetter is also the cofounder of Group CBS, Inc., which owns 12 circuit breaker service shops in the United States. He is a member of IEEE, a NETA Affiliate, and a charter member and past president of Professional Electrical Apparatus Recycler’s League (PEARL). Alan Seidel graduated from Texas A&M University in 1979 with a BSEE degree. He has worked as a plant engineer for the Lower Colorado River Authority at its Fayette Power Project since 2009. Mr. Seidel has previous power plant electrical maintenance experience with Houston Lighting & Power and Reliant Energy and is a registered professional engineer in the state of Texas.

14

Circuit Breakers Vol.1

UNDERSTANDING AND TROUBLESHOOTING BREAKER CONTROL SCHEMES PowerTest 2013 Rick Youngblood, Doble Engineering

UNDERSTANDING APPARATUS CONTROLS When first learning electrical control systems, there are fundamental problems that should be recognized. These must be resolved if progress is to be made to troubleshoot breaker control schemes. Some of these problems are:

It is extremely important to isolate the parts of the drawing that have nothing to do with the circuit being examined so to permit the mind to see only small simple circuits. An easy method is to cover up the nonessential part of the drawing with other sheets so only the circuit under observation is shown.

●● Failure to carry a mental picture of the component into the electrical circuit.

It is very important to understand each component and its use in the small circuits working with one or only a few functions at one time to eventually put each circuit together to form the entire operation of the breaker.

●● Failure to transfer physical action to conditions that are required to perform a function into electrical signals.

THREE BASIC STEPS TO TROUBLESHOOTING

●● Starting with too large or complicated circuit.

●● Understanding that an electrical circuit must perform the correct functions and not perform those actions that will result in equipment damage and/or danger to the operator or system operational errors. It must be understood that a given circuit may, under certain conditions, do both and it may be more difficult to eliminate the second undesirable part than to obtain the first. One of the greatest problems in “reading” circuits is a clear understanding of a switch or contact condition. These are designated on the schematic diagram or wiring print and the user must properly interpret its use on the breaker. Remember that an elementary diagram shows all components that operate by application of electrical energy, in their deenergized condition. It will show all components that operate by other forces such as mechanical pressure or temperature, in their condition at the start of the operation to be performed. They may be operated or un-operated. For example, a pressure switch required to be closed for the breaker to operate correctly may be shown on the print to be open due to the absence of air pressure at the start of a cycle. Once the pressure is built up the switch closes. The elementary diagram will show this switch contact in its open condition. Another example is a normally closed relay contact. It may open as soon as control power is available; as the relay may be connected to energize immediately. The schematic diagram will show this contact closed. Schematic diagrams will show the entire circuit but can be isolated for each operation of the breaker, Trip Close and Reclose.

In understanding circuits, there are three basic steps. The first step is to know what work or function is to be performed. An example would be to light a lamp on a control panel. The closing of a switch makes up the path to provide power to the lamp completing the circuit. The switch is operated to make the circuit work. The words operated, un-operated or released, and normal are often misused or misunderstood as to converting the action into electrical signal. Such items as pushbutton switches, selector switches, or limit switches are either in an operated or un-operated (released) condition. With the switch completely free of any external force being applied, it is in an un-operated (released) condition. When an external force is applied, it is operated. The point being, there is not a direct correlation between the mechanical and electrical outcomes. Operated does not always mean energized. The other word, “normal,” refers to the deenergized or un-operated (released) condition of a component. For example, if reference is made to a contact on a relay as “normally open,” it is open with the relay coil deenergized. If reference is made to a limit switch contact as “normally open,” it is open with the switch in the un-operated (released) condition. In all circuit design, there are two basic elements: ●● The means of opening or closing a circuit. This can be pushbuttons or selector switches, contacts on a relay, temperature or pressure switches. ●● The energizing of a coil to perform a definite function. This could be a valve, relay, contactor, motor starter, or solenoid.

Circuit Breakers Vol.1 The second step is to know the operating conditions under which the starting, stopping, and controlling of the process is to take place. Practically all conditions fall in one or more general groups, as affected by: ●● Position ●● Time ●● Flow ●● Pressure ●● Temperature It is imperative that an understanding of the conditions for operation be complete. A failure of understanding the process of converting mechanical signal into electrical signal means failure in troubleshooting the problem. Understanding the components well enough that a mental picture of the device and how it works, forms when reading or hearing the device name. Hearing the name pressure switch one would know the adding or loss of pressure causes a change in the electrical status of the switch. For example: If one does not understand a specific pressure or temperature must be reached before a function can take place the troubleshooting may end up following a problem path that is not truly a problem. The third step in the troubleshooting of a circuit is selecting, dividing and/or isolating. There are many times a circuit must be capable of operation under different sets of conditions and produce different results. For example: a circuit breaker may close from supervisory, a control building or local remote on the breaker. Knowing these conditions provides three separate circuits that perform the same function. By dividing and isolating the circuits, one can determine if the misoperations affect one two or all three of the conditions providing valuable information for trouble shooting the problem by looking for the components that are common to all three operating modes of the circuit. Conversely if the failure only occurs in one mode the troubleshooting path would then look for the non common parts of the circuit that end with the same operation of the breaker. In either case by dividing and isolating the circuits, an easier understanding of troubleshooting a problem can be achieved.

CONCLUSIONS Understanding apparatus control schemes and troubleshooting electrical problems can be difficult, especially with complex multi faceted circuits. Regardless of their complexity all circuits are made up of individual parts wired into simple circuits combined to form the complex ones.

15 By understanding what each device does and how it operates in the simple circuit, will define how the complex circuit operates. One must know the overall function of the machine (breaker) and understand what it is to do and be able to recognize when it is not performing the required operation. By breaking the complex circuits down into smaller segments and determining if each component is performing its assigned task, a full understanding of the control scheme can be achieved and troubleshooting of malfunctioning operation can be completed to resolve the problem and return the breaker to correct operating condition. Experimentation with simple circuits followed by more complex circuits will eventually lead to the level of understanding needed to troubleshoot the most complex of control schemes. Understanding apparatus control schemes and troubleshooting electrical problems can be difficult, especially with complex multi faceted circuits. Regardless of their complexity all circuits are made up of individual parts wired into simple circuits combined to form the complex ones. Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

16

Circuit Breakers Vol.1

A SYSTEMATIC APPROACH TO HIGH-VOLTAGE CIRCUIT BREAKER TESTING PowerTest 2014 Charles Sweetser, OMICRON Electronics Corp., USA

INTRODUCTION

BREAKER TYPES

MECHANISM TYPES

Circuit breaker technology varies depending on the application. Also, the preferred technology is dependent on the geographical region in which it is applied. Case in point, Dead Tank SF6 Filled Circuit Breakers and Bulk Oil Circuit Breakers are primarily used in North America in HV applications, while the rest of the world prefers Live Tank Circuit Breaker technology.

Bulk Oil Circuit Breaker (OCB)

Mechanical (Spring)

Dead Tank SF6 Breaker

Hydraulic

Live Tank Air Blast

Pneumatic

Live Tank SF6

Magnetic Actuator

Overall, circuit breakers, regardless of type and technology, are designed with the following three functions in mind:

Vacuum Breakers Air Magnetic

INSULATION SYSTEMS

●● Direct current flow between desired sections of an electric power system

Low Voltage Air Blast

Oil

Reclosers

SF6

●● Interrupt current flow under abnormal power system events and conditions, such as faults

Circuit Switchers

Air

Sectionalizers

Vacuum

●● Carry load current under normal power system conditions with minimal losses. These three functions must be performed under both normal and abnormal (fault) conditions, and must perform under strict performance specifications. Circuit breakers vary by subsystems: ●● Insulation System ●● Arc Quenching Method ●● Mechanism ●● Contact Technology ●● Control Circuit Schemes ●● CT’s These subsystems above need to be analyzed both separately and as a complete electro-mechanical system. Table 1, shown below, lists several different properties related to circuit breakers.

Table 1: Circuit Breaker Classifications The two types of dead tank breakers, highlighted in BOLD in Table 1, will be the main focus of this paper. Diagnostic testing can be performed in either an on-line/inservice state or an off-line/de-energized state. The manufacturer’s recommendations, duty, number of operations, and past experience should be considered when justifying the test and maintenance requirements. Table 2 and Table 3 list recommended and commonly practiced on-line/in-service and off-line/de-energized tests, respectively. Visual Inspection

Inspect External Physical Condition, Structure, Grounding, Gauges, Annunciators, and On-line Monitoring Devices

SF6 Gas Analysis

SF6 Density, SF6 Moisture, and SF6 Decomposition

SF6 and Air Leak Detection

Laser Imaging, Thermal Conductivity, Acoustic Emissions

Infrared (IR)

Thermal Imaging; Temperature Differential

Acoustic Emissions

Partial Discharge, Particles, Mechanical Defects

First Trip

Basic Operation and Timing, Control Circuit Performance, AC/DC Power Source Main contacts via Phase Currents, Lubrication

IED (Simple) Intelligent Electronic Device

First Trip, Basic Operation and Timing, Control Circuit Performance, AC/DC Power Source, Main Contacts via Phase Currents, Lubrication, Contact Wear (I2t)

IED (Advanced) Intelligent Electronic Device

Acoustic Emissions (Partial Discharge, Particles, Mechanical Defects), Air and Gas Diagnostics (Density, Moisture, Pressure, Decomposition), Heaters, and Charging System (Air and Motors).

Table 2: Online/In-Service Testing Methodologies

17

Circuit Breakers Vol.1 Visual Inspection

Inspect Internal and External Physical Condition, Structure, Grounding, Gauges, Annunciators, On-line Monitoring Devices

The following should be noted:

Bulk Oil Circuit Breakers (OCB)

Contact Resistance

Static and Dynamic (DRM)

●● Bulk OCBs use a large volume of oil to extinguish the arc.

Insulation Integrity

Power Factor/Capacitance, Partial Discharge (PD), Insulation Resistance, Withstand (AC/DC High Pot), DGA & Oil Screen, and SF6 Quality

●● Arcing occur in oil, which creates gases (hydrocarbons).

Timing

Control Circuit and Contacts, Verify TRIP, CLOSE, TRIPFREE(Dwell-Time), and RECLOSE (Dead-Time)

Mechanism

Total Travel, Velocity, Over-Travel, Rebound, Contact Wipe, Stoke

Control Circuit

Minimum Pickup, Minimum Voltage, Insulation Resistance, Operation of Protective, and Alarm Devices

Instrument Transformers

CT Saturation, CT Polarity, CT Ratio, Burden, and Winding Resistance

Table 3: Offline/De-Energized Testing Methodologies

BREAKER TYPES As indicated, this paper focuses on two circuit breaker types, Bulk Oil Circuit Breakers (OCB) and Dead Tank SF6 Circuit Breakers. These two types were selected because they are most popular in North America when used in HV applications. Both types are of the dead tank design. The OCBs are considered old technology, and have been steadily replaced by the newer Dead Tank SF6 Circuit Breakers. This change-over has been occurring for roughly 30 years. Figure 1 shows both circuit breaker types, coincidentally, side by side in the same substation.

●● Though the use of a vented interrupter chamber, gas bubbles create pressure that forces the arc to expand further into the vents, until it is able to extinguish itself at a zero crossing current. ●● The interrupter chambers often attract moisture. ●● Bulk OCBs often use condenser type bushings, resin or oil, that are equipped with tap electrodes. These bushings can be isolated and tested. These bushings often have CTs mounted on the lower ground sleeve.

Dead Tank SF6 Circuit Breakers ●● Dead Tank SF6 Circuit Breakers can utilize three different methods for arc extinction. Each of these methods utilizes SF6 gas pressure to “blow-out” or extinguish the arc. ○○ S  F6 Puffer Circuit Breaker - Mechanical compression of the arcing chamber generates SF6 gas pressure. ○○ SF6 Self-Extinguishing Circuit Breaker - Heat generated in the arcing chamber generates SF6 gas pressure. ○○ SF6 Double (Dual) Pressure Circuit Breaker - Uses a pressurized SF6 gas chamber that is released in the arcing chamber during operation. ●● Dead Tank SF6 Circuit Breakers are often equipped with SF6 gas-filled bushings that cannot be isolated for field testing. The bushings often have CTs mounted on the upper external ground sleeve near the mounting flange.

TIMING AND TRAVEL Circuit breaker timing and travel measurements entail three steps: ●● Perform a dynamic timing and travel measurement ●● Calculate performance characteristics ●● Compare results to the manufacturer’s recommendations or user-defined limits. Table 4 provides the fundamentals tests and calculations involved in circuit breaker timing measurements and diagnostics.

Fig. 1: Bulk OCB vs. Dead Tank SF6

18

Circuit Breakers Vol.1 CONTROL

MEASUREMENT

CALCULATIONS

Trip (O)

Displacement

Main Contact Timing

Close (C)

Contact State (O-R-C)

Resistor Switch Timing

ReClose (O-C)

Command Coil Current

Delta Timing (Pole Spread)

TripFree (C-O)

Auxiliary Contact State (OW-OD-C)

Velocity

(O-CO)

Battery Voltage

Total Travel

(O-CO-CO)

Phase Currents (First Trip)

Over Travel

Slow Close (C)

Dynamic Resistance (DRM)

First Trip (O)

Also, depending on the use and availability of the auxiliary contacts, such as 52a and 52b, etc., these contacts may be wet (voltage present) or dry. The measurement must be configured for such conditions. Not all of the above signals are always included; however, as signals are omitted, it limits the effectiveness of the analysis. Figure 2 and Figure 3 illustrate various signals associated with circuit breaker timing and travel measurements.

Rebound Stroke Contact Wipe Dwell Time (TripFree C-O) Dead Time (ReClose O-C)

Table 4: Circuit Breaker Timing Fundamentals Most breakers utilize a 125 VDC control circuit. However, 48 VDC, 250 VDC, 120 VAC, and 240 VAC control circuits are not uncommon. Table 5 lists typical control signal timing values used in performing timing and travel tests. Trip Coil Trip (O)

Close Coil

Fig. 2: Command Coil Currents and Main Contact State

Delay

66.6 ms (4 cycles)

Close (C)

133.3 ms (8 cycles)

ReClose (O-C)

66.6 ms (4 cycles)

Standing

> 300.0 ms

TripFree (C-O)

Standing

133.3 ms (8 cycles)

8.3 ms (1/2 cycles)

Table 5: Typical Signal Timing Values

Measured Signal When performing circuit breaker timing and travel measurements, there are five primary signals that are of interest. ●● Displacement ●● Contact State (Open-Resistor-Close) ●● Command Coil Current ●● Auxiliary Contact State (OW-OD-C) ●● Battery Voltage It is worth noting that the main contacts can take on three different states, OPEN, CLOSE, and RESISTOR, because some breaker applications require Pre-Insertion Resistors (PIRs). When the breaker performs a CLOSE operation, a resistor will be placed across the open contacts for a few to several milliseconds in order to limit potential overvoltage associated with long transmission line applications. It is important to capture the operation; specifically, the timing of this resistor switch.

Fig. 3: Trip Operation Signals

Performance Characteristics Table 6 lists all of the pertinent circuit breaker characteristics. There are 11 in all, including 5 related to timing, 5 related to displacement, and 1 for velocity.

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Circuit Breakers Vol.1

Main Contact Timing

Time between test initiation (energization of command coil) and change of main contact state (make or break)

Resistor Switch Timing

Time involving the resistor switch in the circuit.

Delta Timing (Pole Spread)

The time duration between first contact to change state and the last contact to change state, within a breaker, within a phase, or within a module.

Velocity (Average and Instantaneous)

Average Velocity is measured during referenced times, measured points in the displacement, or events (contact make or break). Time to Time, Time to Distance, Distance to Distance, Time to Contact Make/ Break, and Distance to Contact Make/Break are examples of some combinations. Instantaneous Velocity is the measured velocity at a signal point. This can be defined as a specific time, distance, or when a contact makes or a contact breaks.

Total Travel

The distance traveled by the contacts from the initial starting position to the final resting position

Table 6: Timing and Travel Performance Characteristics

20

Circuit Breakers Vol.1 Table 6: Cont. Over Travel

The distance traveled by the contacts that exceeds the final resting position. Over Travel & Rebound are measured to verify the proper operation of damping assemblies within the breaker.

Rebound

The distance traveled by the contacts beyond the final resting position after returning from over travel.

Stroke

The maximum distance traveled by the contacts during an operation (Travel + Over Travel)

Contact Wipe

The distance the contacts travel during a close operation from initial contact make to the final resting position.

Dwell Time (TripFree C-O)

The time duration that the main contacts remain open during the Trip-Free operation.

Dead Time (ReClose O-C)

The time duration that the main contacts remain closed during the Re-Close operation.

21

Circuit Breakers Vol.1 Analysis of Results Timing and travel results are directly compared to the manufacturer’s performance specifications and previous results.1 All of the performance characteristics listed above will have pass/ fail criteria. Table 7 illustrates typical performance characteristics. It should be noted that not all manufacturers document all performance characteristic limits; it may be worthwhile to baseline any missing limits with commissioning tests. Table 7: Typical Performance Limits Provided by the Manufacturer Identification

CB1

Control Circuit Open

70-140 VDC / 6.0 A

Control Circuit Close

90-140 VDC / 6.0 A

Opening Time

17-30 ms

Opening Velocity

3.8 m/s minimum

Pole Spread Open

2.7 ms

Closing Time

50-85 ms

Closing Velocity

1.7 to 2.3 m/s 

Pole Spread Close

2.7 ms

Overtravel

4.0 mm maximum 

Rebound

6.5 mm maximum 

Stroke

113 mm maximum 

Dwell Time

20-38 ms

Reclose Time (Dead Time)

300 ms minimum

A few diagnostic indicators, such as contact bouncing, dashpot damping, and command coil signatures are obtained by analyzing the recordings.

Fig. 4: Unusual Contact Bouncing ●● Dashpot Damping – Just as a circuit breaker is expected to accelerate quickly upon command, it must slowdown just as efficiently. A damping device, something like a shock absorber, is used to slow the mechanism as it approaches the final resting position. It can utilize the dynamic effects of oil or air. The motion recording is analyzed for proper deceleration near the final resting position. As the dashpot becomes worn, it can affect the contact’s performance. These motion recordings can be compared and trended over time. ●● Command Coil Signatures – By analyzing the command coil signatures, information regarding lubrication, electrical coil performance and latch operation can be extracted. However, this diagnostic is most effective when it is performed as a “First Trip” activity. First Trip is performed when the circuit breaker is in-service, and has not been operated for a long time. Lubrication problems are easiest to identify in this scenario. As the armature of the command moves, an expected command coil signature is generated. Figure 5 illustrates a typical coil current signature. These signatures can be compared and trended over time.

●● Contact Bouncing – Main Contacts, Resistor Switches, and Auxiliary Contacts can be analyzed for undesired bouncing. Phase A in Figure 4 illustrates unusual bouncing of a main contact. The measurement should be repeated, and all connections should be checked. It may be worthwhile to verify the presence of interference. If this problem is validated, it is recommended to follow-up with resistance measurements, both static and dynamic; see the contact resistance section for more information.

Fig. 5: Command Coil Current vs. Plunger Movement

POWER FACTOR Power factor and capacitance testing provides means of verifying the integrity of the insulation of circuit breaker components. Problems that impair the insulation integrity and can be detected by measuring the power factor and capacitance include:

22

Circuit Breakers Vol.1

●● Deterioration of entrance bushing insulation ●● Deterioration of interrupter assemblies, insulated operating rods and support insulators due to arcing by-products ●● Presence of particles, impurities and contamination of insulating medium ●● Moisture ingress due to leaks or inaccurate cleaning and drying ●● Damages resulting from corona discharge due to voids within the internal insulation system.

Test Procedure

If the Bulk Oil Circuit Breaker is equipped with condenser type bushings, C1 and C2 should be performed and evaluated. These tests are similar to bushing tests performed on power transformers. ●● Dead Tank SF6 Breakers There are nine recommend and three optional tests performed on Dead Tank SF6 Breakers. Table 9 shows the 12 tests. Insulation Tested

Breaker Position

1

C1G

Open

Bushing 1

-

-

GST

2

C2G

Open

Bushing 2

-

-

GST

3

C3G

Open

Bushing 3

-

-

GST

4

C4G

Open

Bushing 4

-

-

GST

5

C5G

Open

Bushing 5

-

-

GST

6

C6G

Open

Bushing 6

-

-

GST

7

C12G

Open

Bushing 1

Bushing 2

-

UST-A

8

C34G

Open

Bushing 3

Bushing 4

-

UST-A

9

C56G

Open

Bushing 5

Bushing 6

-

UST-A

10

C1G + C2G

Closed

Bushing 1&2

11

C3G + C4G

Closed

Bushing 3&4

-

-

GST

12

C5G + C6G

Closed

Bushing 5&6

-

-

GST

Test

Power factor and capacitance test procedures depend on the design and type of apparatus. The following test procedures are those required to test Bulk Oil Circuit Breakers (OCB) and SF6 Dead Tank Circuit Breakers. However, these test procedure concepts apply to a number of different breaker types. The applied test voltage should not exceed the line-to-ground rating of the test specimen, or otherwise stated by the manufacturer. The test specimen should be solidly grounded for safety and proper measurement. ●● OCB A total of nine tests are performed on a Bulk Oil Circuit Breaker, including six in the open state and three in the closed state. By varying the breaker state, we are attempting to isolate various components. Table 8 provides a list of the nine tests. Insulation Tested

Breaker Position

1

C1G

Open

2

C2G

3

Test

respective bushing being energized, interrupter assemblies, and the lift rod guide. Closed breaker tests (Test 7-9) isolate both phase bushings being energized, tank oil/liner, and lift rod.

HV

IN A

IN B

Test Mode

Bushing 1

-

-

GST

Open

Bushing 2

-

-

GST

C3G

Open

Bushing 3

-

-

GST

4

C4G

Open

Bushing 4

-

-

GST

5

C5G

Open

Bushing 5

-

-

GST

6

C6G

Open

Bushing 6

-

-

GST

7

C1G + C2G

Closed

Bushing 1&2

-

-

GST

8

C3G + C4G

Closed

Bushing 3&4

-

-

GST

9

C5G + C6G

Closed

Bushing 5&6

-

-

GST

NOTE: All unused bushing should be left floating

Table 8: Recommended Tests: Bulk Oil Circuit Breaker NOTE: All unused bushing should be left floating Although all components influence power factor and capacitance measurements, open breaker tests (Test 1-6) primarily isolate the

HV

IN A

IN B

Test Mode

GST

Table 9: Recommended and Optional Tests: Dead Tank SF6 Breakers NOTE: All unused bushing should be left floating Tests 1-6 primarily measures the insulation integrity of the energized bushing and also include any insulated support structure, operating rod and SF6 gas. Tests 7-9 assess the condition of the contact assembly and SF6 gas within the interrupter chamber. Tests 10-12 are optional tests that are performed on circuit breakers with more than one contact chamber per phase. This test mode helps stress the additional support structures that will not be seen while the circuit breaker is in the open position.

Analysis of Results ●● OCB Power factor and capacitance measurements are used cautiously to determine the overall condition of the insulation. OCBs, in general, especially the interrupter assemblies, are prone to moisture. Elevated power factor measurements are not uncommon. Comparisons can be made against previous data, similar units and phases on the same units. From a single measurement, it is difficult to deter-

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Circuit Breakers Vol.1 mine the cause or source of elevated power factor. As stated above, caution should be used when analyzing elevated power factors.

of bushings, the insulated support structure, operating rod, contact assembly, and/or SF6 gas.

Because open and closed breaker tests influence individual components differently, a special comparison can be performed. This comparison, known as Tank Loss Index (TLI), includes three measurements from each phase (two open breaker tests and one closed breaker test). The losses (in Watts) generated from different components for each tests are weighted against each other. TLI is calculated as follows:

On circuit breakers with grading capacitors Tests 7-9 are dominated by the grading capacitors. High power factor or loss readings may indicate deteriorated capacitors. An unexpected increase in capacitance may indicate short-circuited capacitance layers.

TLI = (closed breaker test in Watts) – (sum of open breaker losses in Watts) The polarity sign of the TLI calculation helps determine the questionable circuit breaker components. General guidance for investigating abnormal TLI values for dead tank oil circuit breakers is given in Table 10, shown below. Negative TLI (-)

Positive TLI (+)

Lift Rod Guide

Lift rod

Interrupter Assembly

Oil

Figure 6 illustrates typical results obtained from a Dead Tank SF6 Breaker. It can be seen that tests [1 3 5], tests [2 4 6], tests [7 8 9] can be compared, respectively.

CONTACT RESISTANCE Contact Resistance can be a complicated subject. Contact assemblies can consist of both main and arcing contact components. To see both main and arcing contact components, the Contact Resistance is analyzed, both statically and dynamically, respectively.

Static

Tank Liner

Table 10: Tank Loss Index: Component vs Polarity Limits for TLIs vary depending on OCB design. As a general statement, HV OCBs should be investigated when TLIs exceed +/- 150 mW.2 ●● Dead Tank SF6 Breakers For low capacitance specimens like Dead Tank SF6 Breakers it is generally recommended to assess losses (in Watts) instead of power factor. As stated in IEEE C57.152-2013 3: “PF calculations should not be used to determine the integrity of insulation if the measured current is less than 0.3 mA. At low measured currents, PF calculations are susceptible to large swings, which could be misleading. Therefore, in those cases, the test results should be evaluated based on current and loss readings”.3 Not all Dead Tank SF6 Breakers are assessed according to measured losses, just those units with very low capacitance. Elevated power factor or loss readings can indicate degradation

The micro ohm measurement or static contact resistance measurement determines the continuity integrity of the main contact components. Abnormal readings may indicate improper alignment, pressure, or damaged contact surfaces, such as plating or coating. This is the standard test that is performed to measure the actual resistance value of contact continuity and associated series components, such as bushing connections and tulips. The static measurement produces a single, temperature dependent value in Ohms (Ω). A static contact measurement is to be performed on each phase, using a DC current source. Typical measurements are less than 100 µΩ; however, the manufacturer’s literature should be used to determine the actual expected value. Considering all breaker types, experience has shown measurements range from 10 µΩ to 150 µΩ depending on the type, with low voltage vacuum breakers associated with very low measurements, and higher voltage SF6 Dead Tank Breakers producing the higher measurements. It is recommended that at least 100A DC is injected for this test.2 Also, it should be noted that if the breaker is equipped with CTs, it may take several seconds to saturate the opposing effects. Precautions should be taken to ensure that the injected high primary current does not affect protection circuits.

Fig. 6: Power Factor and Capacitance Results

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Circuit Breakers Vol.1

Due to the very low resistances, in the µΩ range, it is recommended that a high DC current source be used in conjunction with a Kelvin connection. The Kelvin 4-wire method is the most effective method used to measure very low resistance values. The Kelvin 4-wire method will exclude the resistance from the measurement circuit leads and any contact resistance at the connection points of these leads. The concept of the Kelvin 4-wire method is to apply the voltage and current leads separately. This is shown in Figure 7.

MINIMUM PICK-UP The minimum pick-up measurement is performed to determine the minimum command coil (trip or close) voltage required to operate the circuit breaker. This is the minimum energy need for the command coil to release the “latch”. The latch can either be a mechanical release mechanism or a value used to control a pneumatic or hydraulic system. This test is done for each control coil of a circuit breaker. Different considerations must be given to ganged versus independent pole operation (IPO) circuit breakers. The test needs to be done for all command coils independently. The IPO breaker may require several more tests to include all command coils. The test procedure includes the following: ●● Determine the command coil parameters and ratings, AC or DC, and operating voltage.

Fig. 7:Kelvin Connection Used for Contact Resistance Measurement

Dynamic (DRM) The dynamic resistance measurement is a diagnostic tool to assess the condition of the arcing contacts in SF6 nozzle style interrupters. By measuring the current, voltage, and displacement associated with the contact assembly, it is possible to determine the wear level and integrity of the arcing contact. This measurement, like the static contact resistance measurement, requires high current injection to be successful. Common practice is to use at least 100A DC. Caution must be taken when analyzing the results. As implied by the name (DRM), “resistance” is being isolated and measured. However, in actuality, due to the speed of the contact interaction (roughly 15-20 ms), it is impedance, which includes both real and reactive components, that drives the response. Source leads, CT’s, and capacitances, both stray and fixed, contribute to the unexpected reactance.

●● Determine a start and stop voltage for the command coil under test. Example, 125 VDC command coil, Start [10 VDC] – Stop [125 VDC] ●● Determine pulse time: the pulse time should be limited so the command coil does not overheat, 300 ms is the default starting point. ●● Determine dead time: this is the time that the command coil pauses between pulses. The dead time should be long enough to assist in cooling of the command coil. Two seconds is a reasonable starting point. ●● Determine the voltage step increment: This is the amount that the voltage is increased between command coil pulses. 5V DC is a reasonable starting point. The voltage is increased linearly until the command coil operates. This behavior is illustrated in Figure 9, shown below. The blue response is current (A), and the purple response is voltage (V).

Figure 8 illustrates a typical dynamic resistance measurement. Motion and the resistance (impedance) response are plotted together. The length of what is left of the arcing contact is determined by comparing it to the distance traveled.

Fig. 9: Minimum Pick: Voltage and Current Responses

Fig. 8: Typical Dynamic Resistance Measurement

The smaller the steps, the more accurate the test result. In general, experience has shown that most healthy command coils will operate at less than 50% of rated voltage. However, this is not an official limit.

Circuit Breakers Vol.1 CONCLUSION Timing and Travel measurements determine and validate the performance characteristics of circuit breakers. The control coils, mechanical linkages, energy storage device, contacts, and dashpots are all monitored for proper operation. Power factor and capacitance testing provides means for verifying the integrity of the insulation of circuit breaker components. Depending on the type of breaker and the insulation components that are present, the proper test procedure and analysis strategy must be implemented. Contact Resistance measurements can be performed in either the static mode or the dynamic mode. Traditionally, static measurements have been performed allowing only the main contacts to be assessed. With the introduction of DRM, the integrity of the arcing contacts on SF6 nozzle style contacts can be determined. The minimum pick-up measurement is performed to determine the minimum command coil (trip or close) voltage required to operate the circuit breaker. This will ensure that the circuit breaker will operated at a specified reduced voltage.

REFERENCES ANSI/NETA MTS-2011, “Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems” 1

P. Gill: “Electrical Power Equipment Maintenance and Testing” Second Edition, CRC Press, 2009 2

IEEE C57.152-2013, “IEEE Guide for Diagnostic Field Testing of Fluid-Filled Power Transformers, Regulators, and Reactors”. 3

Charles Sweetser received a B.S. Electrical Engineering in 1992 and a M.S. Electrical Engineering in 1996 from the University of Maine. He joined OMICRON electronics Corp USA, in 2009, where he presently holds the position of Technical Services Manager for North America. Prior to joining OMICRON, he worked 13 years in the electrical apparatus diagnostic and consulting business. He has published several technical papers for IEEE and other industry forums. As a member of IEEE Power & Energy Society (PES) for 14 years, he actively participates in the IEEE Transformers Committee, where he held the position of Chair of the FRA Working Group PC57.149 until publication in March 2013. He is also a member of several other working groups and subcommittees. Additional interests include condition assessment of power apparatus and partial discharge.

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Circuit Breakers Vol.1

MAINTENANCE TESTING OF LOW-VOLTAGE POWER CIRCUIT BREAKERS IN A LARGE AUTOMOTIVE ASSEMBLY PLANT PowerTest 2015 Mose Ramieh III, Power & Generation Testing, Inc. Randall Sagan, Mercedes-Benz U.S. International, Inc.

GENERAL FACILITY INFORMATION This automotive assembly plant sits on 1,000-acres located in central Alabama. The total plant area is over five-million square feet under roof. Production capacity of this plant is 300,000 vehicles per year. Refrigeration machines in the Energy Center produce chilled water for plant-wide air conditioning and process cooling. This is to protect the raw steel in the Body Shop from oxidizing. Chilled water is also used to maintain very tightly controlled temperature and humidity setpoints in the Paint Shop spray booths. This means that during hot and humid summer months in Alabama, the chilled water plant in the Energy Center uses more than 50% of the energy for the entire site. The electrical substation rooms are air conditioned by the same filtered air that serves the general plant spaces. This increases the reliability of the electrical substation equipment by maintaining lower ambient air temperature and relative humidity. Additionally, airborne dirt and dust generated in production spaces does not contaminate the electrical equipment. This is particularly important in the Body Shop where weld dust is prevalent.

SITE POWER DISTRIBUTION SYSTEM The utility substation is located on the plant site and is fed by two separate 115-kV transmission lines. Substation transformers feed the plant “Utility Center” at 13.8-kV. Primary switchgear in the Utility Center utilizes a main-tie-main configuration to feed two separate main buses, “A” and “B”, with the tie breaker operated normally open. Site-wide power distribution is 13.8-kV with both “A” and “B” feeder circuits routed to unit substations in each of the production shops. Most unit substations are located in rooftop electrical penthouses scattered across the plant. Some of the older substations in the Body and Assembly Shops are located in the production areas on top of restrooms. The standard unit substation is doubleended to provide 100% backup redundancy for maintenance and failure contingency. Each unit substation has an “A” transformer and a “B” transformer with the secondary 480-volt breakers set up in a main-tie-main arrangement. Refrigeration machines and air compressors in the Energy Center operate at 4,160-volts and their associated unit substations have the same double-ended configuration as the low-voltage substations.

ANNUAL POWER SYSTEM MAINTENANCE TESTING PROGRAM Power system maintenance is performed in January each year with scheduled power outages taking place over the Martin Luther King, Jr. holiday weekend. Cooler January weather allows for more flexibility in switching plant loads around since the plant power demand is lower. This is due to the fact that the chilled water plant in the Energy Center is running at a reduced capacity. All of the electrical substation and switchgear rooms are cleaned prior to the start of testing. This helps protect circuit breakers and test equipment from picking up dirt and debris when placed on the floor during testing. Safety equipment and other supplies are also inspected to assure that everything is ready to use for the upcoming switching activities. One half of the power system is tested each year, alternating between “A” and “B” sides. Each unit substation is transferred to its “B” source in order to perform maintenance on the “A” components, and vice-versa in years when doing maintenance on “B” components. Secondary tie breakers are closed and Main “A” breakers opened. This puts the entire plant load on the “B” system (see Diagram 1). In the colder winter months, when the chilled water plant is operating at reduced capacity, the entire plant can operate at full production in this configuration.

DIAGRAM 1: Typical 480-volt unit substation with TIE breaker closed and MAIN A open. Transformer P5-B supplies power to loads while Transformer P5-A and its primary switch are cleaned and tested. The plant can operate at full production with all unit substations in this configuration.

Circuit Breakers Vol.1 The testing program is based on the ANSI/NETA Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems.2 The first step is to de-energize the 15-kV “A” feeder breakers in the primary switchgear lineup. Maintenance testing is then performed on these feeder breakers and their associated protective relays, as well as the “A” transformers and primary disconnect switches throughout the site. Since the plant production is not affected with the power system in this configuration, this work can be performed on straight-time during the week without having to rush through a tight “outage” schedule. The next step is to test the 480-volt unit substation circuit breakers. Since this requires scheduled power outages, this work is done over the MLK holiday weekend when the plant is not running production. Each unit substation is taken out of service one-at-atime. The tie breakers are opened and racked out to de-energize the “A” feeder circuits (see Diagram 2).

DIAGRAM 2: The “A” side low-voltage power circuit breakers are taken out of service during scheduled power outages over the MLK holiday weekend. Over 100 breakers are cleaned and tested each year.

LOW-VOLTAGE POWER CIRCUIT BREAKER COMPONENTS AND OPERATION There are two types of low-voltage power circuit breakers at this facility, depending on their date of installation. The older unit subs have type “DS” circuit breakers and the newer subs have “MasterPact” circuit breakers. Both kinds are equipped with solid-state microprocessor-based trip units. Although there may be some specific differences, the function and operation of both types of breakers is generally the same. A typical low-voltage power circuit breaker has a set of contact fingers that grip the three-phase bus stabs in the back of the cubicle when the breaker is racked into its connected position. One set of stabs are attached to the main bus and the other set of stabs attach to the feeder cables. When the breaker’s main contacts are closed, current flows from the main bus through the breaker contacts to the feeder cables and on to the load. The breaker contacts are operated by a set of springs that quickly open or close them. This is

27 to safely interrupt current flowing through the breaker to the load. Arc-chutes help extinguish the arc produced when opening the contacts under high load or a short circuit (also called a “fault”). A manual lever or built-in motor is used to charge and latch the close spring inside the circuit breaker. When the mechanical CLOSE pushbutton is pressed, the spring releases to close the breaker contacts and simultaneously charge and latch the trip spring. To open the breaker, either the mechanical TRIP pushbutton or a solenoid releases the latch which releases the trip spring and opens the breaker contacts. The solenoid is activated by the trip unit when an overload or fault is detected. The solid-state trip unit is the “brains” of the circuit breaker that perform the logic functions required for circuit protection. Without the trip unit, a circuit breaker is nothing more than a switch. Current transformers (CT’s) installed inside the breaker sense load currents and feed representative secondary current signals to the solid-state trip unit. The trip unit converts the analog sine wave to a digital signal for analysis by the microprocessor. Using the pickup and time delay settings, when an overload or fault is detected, then a trip signal is sent to the solenoid which release the spring and opens the breaker. Time delay settings are used to coordinate with other downstream devices. This prevents a main breaker, for instance, from shutting down an entire substation for a fault on a downstream feeder circuit. LED’s on the front of the trip unit indicate which function caused the breaker to trip-overload, phase fault, or ground fault (see Diagram 3). The trip unit gets its control power directly from the CT secondary current, so no external power supply is required to operate the unit.1 As long as primary phase current is above a minimum value, the trip unit will be powered on. A battery in the trip unit powers indicating LED’s after the breaker has tripped. This provides useful information even when the trip unit is powered off. It is important to know if a breaker tripped due to an overload or a fault. An overloaded circuit can be quickly re-energized and general purpose components such as lighting and HVAC can be restored. Process equipment operation can then be evaluated to determine the cause of the overload. If the breaker tripped due to a fault however, then the damaged components must be isolated from the rest of the circuit before it can be re-energized. Otherwise, there is a risk of additional equipment damage, fire, or even injury. Typically, this process takes longer and usually results in an interruption in production. That is why it is so critical for maintenance and engineering personnel to understand what caused the breaker to trip.

28

Circuit Breakers Vol.1 interiors and the circuit breakers. Contact fingers are checked for signs of pitting, arcing, or overheating which could indicate improper contact alignment or loose connections. Maintenance tests performed on the circuit breakers include electrical and functional tests. These include insulation resistance and contact resistance tests. The functional tests check the trip unit to verify all of the protective functions operate properly and that the trip signal correctly activates the solenoid and trip mechanism of the breaker. Insulation resistance on the 480-volt components is measured using a 1,000-volt DC ohmmeter. Measurements are taken poleto-pole and pole-to-frame with the breaker closed, and across open contacts with the breaker open. This is to check the integrity of the insulation and to verify there is no physical damage or tracking caused by dirt or other foreign residue. This could result in an internal phase-to-phase or ground fault. A low-resistance ohmmeter is used to measure contact resistance of the breaker contacts. This is to check for carbon buildup, contact wear, proper contact pressure, and surface alignment. Abnormal contact resistance could lead to excessive heating or premature component failure. The functional tests verify that the trip unit can detect overload and fault conditions and that the breaker trip and close mechanisms operate correctly. In order to fully evaluate the integrity of all the circuit breaker components involved with sensing, logic analysis, and tripping functions NETA maintenance testing specifications recommend primary injection testing.2 Using this method, test currents are injected through the circuit breaker with magnitudes that simulate actual overload and fault conditions on the 480-volt level.

DIAGRAM 3: Solid-state microprocessor-based trip units mounted on the front of low-voltage power circuit breakers. Pickup and time delay settings are adjusted by the dials associated with each function. Power supplies operate off of secondary CT current. Batteries power LED’s after an operation to indicate which function tripped the breaker.

MAINTENANCE TESTING OF LOW-VOLTAGE POWER CIRCUIT BREAKERS

Primary injection testing verifies that the CT’s send the correct secondary signals to the trip unit, that the trip unit powers up, that the microprocessor sends a trip signal to the solenoid after the appropriate time delay, and that the trip mechanism operates correctly to open the breaker. Actual test data is then compared to expected data to determine if the breaker is operating within acceptable parameters. This method for breaker testing is extremely comprehensive but requires large and bulky test equipment that is capable of producing thousands of amps of current.

SECONDARY INJECTION TEST

Most circuit breakers in this facility have never had to operate for an overload or fault. But even after years of service, the safety and reliability of the power system relies on a circuit breaker’s electronics and moving parts to perform flawlessly, just as they did when the breaker was brand new. Therefore, the main purpose for circuit breaker maintenance is to identify and correct component failures that could result in an unplanned outage or a failure to operate at all.

The power system maintenance testing program implemented at this facility encompasses over 100 low-voltage power circuit breakers each year. Due to the location and accessibility of most of the electrical substation rooms, it is very difficult to move test equipment and manpower from one location to the next, and still maintain a carefully orchestrated outage schedule. The risks of injury, equipment damage, or switching errors are exacerbated by time constraints and the physical exhaustion from carrying tools and test equipment up and down stairs.

Once a unit substation is de-energized according to the outage schedule, all of its breakers are taken out of their cubicles for maintenance testing. Visual inspections are made of the cubicle

In order to reduce these risks, an alternate test method for lowvoltage power circuit breakers was proposed by a testing agency about ten years ago. The proposed solution utilizes secondary in-

Circuit Breakers Vol.1 jection testing to verify the operation of the trip unit and breaker tripping mechanisms, but with the caveat of using low-level primary injection to verify CT integrity and trip unit power supply. The biggest advantage of this method is the use of a much smaller and lighter test kit. All of the same trip unit functions are tested by this method as would be with primary injection, and the mechanical operation of the breaker trip mechanism is also confirmed. Since the trip unit only requires 10% of rated primary current to operate, the magnitude of injected current needed is greatly reduced. It is also significant to note that all new circuit breakers undergo primary injection tests during acceptance testing at this facility. This identifies any problems such as mis-wired current circuits or CT’s installed backwards, or with incorrect turns ratios, before the breakers are put in service. The assumption is made that there is little or no chance that a CT circuit would be changed after the initial installation. Therefore, there is no need to repeat these same checks every year. If a CT were to be replaced, or wiring were modified, then a primary inject test would be performed at that time. By implementing this alternate method for testing low-voltage power circuit breakers, an aggressive outage schedule is able to be maintained without impacting the safety, efficiency, or reliability of the maintenance program. The reduction in test equipment and manpower also results in more than a 20% savings in the annual cost of performing power system maintenance testing. For these reasons, the proposed secondary injection testing method was adopted.

FAILURE ANALYSIS In twenty years, fifteen trip units at this facility have failed maintenance testing and one CT was found defective. Trip unit failures were due to out-of-tolerance pickup values or an inability to operate at all. Several trip units failed to power on, either by secondary injection or primary injection testing. All defective trip units were replaced with spares. The defective CT was identified when low-level primary current injection did not activate the trip unit power supply. The entire breaker was replaced with an on-site spare and sent back to the manufacturer for repair. To date, only one low-voltage power circuit breaker has misoperated at this facility. An inspection of that breaker revealed corrosion had shorted out the terminals of the trip unit rating plug. No breaker has ever failed to operate under overload or fault conditions. Given the environmental conditions of the electrical substation rooms, the relatively light loading on most circuits, and the comprehensive power system maintenance program, this is not entirely unexpected.

CIRCUIT BREAKER VIBRATION ANALYZER Approximately fifty percent (50%) of low-and medium-voltage, distribution class circuit breakers that have not been properly

29 maintained will fail to operate within their published specifications. This statistic has been determined in research studies performed within the last four decades.4 Circuit breakers in an electrical power system serve two critical roles. The first is to remain closed and provide reliability to the load being served. Nuisance (tripping when no fault is present) trips can have significant financial implications on a production facility. The second critical role is to operate properly in the event of a fault (over current) situation. This critical function is clearly related to the safety of personnel and also to the expensive equipment that the circuit breaker protects. A breaker that fails to operate or operates too slowly during a fault increases the arc fault energy and can produce catastrophic results, or at the very least, increased damage to the equipment. These situations cause damage that takes a significant amount of time to repair or replace, resulting in a longer outage and increased financial costs from the production lost during the shutdown. Traditional circuit breaker testing is not capable of determining if the circuit breaker that is expected to stay closed (for reliability) will open (trip) in the designed clearing time in the event of a fault. This critical first trip information is lost when the breaker is manually opened to begin traditional maintenance. Technology continues to improve many areas of our work. Breaker testing is also benefiting from the technology improvements. Traditional testing is focused on the electrical operating parameters of the breaker once it has been removed from service. The critical first trip information can now be obtained using vibrational information that is transmitted through the breaker, without removal of the breaker. Utilizing new technology available on tablets and laptops we use in our everyday lives makes the testing not only convenient but also relatively inexpensive compared to other traditional test equipment. The Circuit Breaker Analyzer app, running on the Windows Operating System in conjunction with a USB accelerometer, provides this critical information quickly. The test is straightforward and can be accomplished by qualified electrical technicians. After entering some basic breaker data, the accelerometer is magnetically attached at a pre-determined position on the breaker to be tested. The breaker can then be opened/tripped and the operating information is recorded by the Circuit Breaker Analyzer device. Once recorded, this information is transmitted to the CBA database where it is compared to a known good profile for the breaker that was tested. After comparison is complete, a pass/fail result is immediately available on the user’s testing device. Once opened, the breaker can have traditional electrical testing conducted. In situations where maintenance time or personnel is in short supply and additional testing cannot be performed, the breaker can be returned to service. The CBA data can be analyzed and those breakers with questionable trip times can then be scheduled for additional maintenance. This allows maintenance dollars to focus on breakers with potential operational issues.

30 CIRCUIT BREAKER VIBRATION ANALYZER TECHNICAL ASPECTS 5 Basic Concept The basic concept of CBVA is that any properly maintained circuit breakers of the same type and manufacturer will have a vibration signature that is consistent within a calculable percentage. This concept has been proven through extensive research and field case studies.

Data Capture The test is performed by capturing the vibration of the circuit breaker as it operates. The vibration may be captured during: ●● Open ●● Spring recharge (if applicable) ●● Closing ●● Any combination of the breaker operations An accelerometer is magnetically attached to the breaker in such a way that the vibrations are captured in three dimensions. The data capture rate is 100 Hz or 400 Hz depending on the accelerometer being used. Higher frequency is preferred for the increase sample data. The captured data is then used to chart the breaker vibration profile in three dimensions as shown in Figure 1. The three different traces show circuit breaker vibration in the vertical, front to back, and lateral dimensions. The vertical axis of the chart is in gravities (g) and the horizontal axis is in time (seconds). Note that gravity offsets the vertical axis by 1 g (9.8 m/sec2 or 32.2 ft/sec2).

Circuit Breakers Vol.1 three single-axis traces into a single profile. This profile is then compared to a Known Good Profile (KGP). The KGP is developed by performing a statistically significant analysis of multiple breakers of the same type.

Equipment/Software Used: The performance of CBVA requires the following: ●● An accelerometer ●● A laptop or tablet PC (for Windows 7) ●● User software that allows data capture and transmission ●● Backend software that is accessible through the internet. Accelerometer: The original research and development of CBVA used the Apple iPhone® or Apple iPod Touch® (iPhone, iPod, and iPod Touch are registered trademarks of Apple, Inc.) These devices have an accelerometer built into them. The accelerometers are accessed at a data rate of 100 Hz. A more robust Windows® 7 application uses a stand-alone accelerometer. This accelerometer can be accessed at 100 Hz or 400 Hz. (Windows is a registered trademark of Microsoft Corporation.) The placement of the accelerometer must be consistent for each type of breaker. The following three requirements must be met: ●● It must be placed in the same location for every test. ●● It must be placed in the same orientation for every test ●● The location and orientation of the accelerometer is the same as that used to develop the KGP.

Fig. 2: A Windows 7 Tablet Computer and an External Accelerometer Fig. 1: Three Axis Vibration Signature for a Circuit Breaker

Graphical Envelope Comparison: Analysis of the data requires that a single trace profile be developed from the three dimensional traces. The single trace is developed by an advanced mathematical algorithm that merges the

User software/hardware: The user software communicates with the accelerometer to capture the vibration data. The Windows 7 application utilizes a USB connection with the outboard accelerometer. It can be run on any Windows 7 compatible PC. Some of the rugged PC tablets are especially well suited for this. Backend Software: The backend software is an internet appli-

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Circuit Breakers Vol.1 cation that provides data storage and the advanced mathematical algorithms that are used to create the profiles for each test and compare them to the KGPs.

Capturing the Vibration Data Capturing the vibration data requires only six steps: 1. Position and orient the accelerometer as previously described. 2. Initiate a ten second countdown in the software. 3. When the countdown reaches 0, the software goes into Record mode and waits for the first vibration to occur. 4. The technician initiates whatever test is being performed by actually operating the breaker. The technician has the option of performing a trip, charge, close, or any combination of the three. 5. The accelerometer senses the start of the test and begins recording the vibration signature. 6. After the test is finished, the tester presses the Stop button. Then the application saves the data in a tabular format. (Figure 1) The three-axis trace (Fig. 1) is immediately available for viewing.

CONCLUSION: Reliability of power systems and the circuit breakers in them is crucial and requires consistent maintenance. Many facilities are dealing with the growing difficulty of reduced outage times, growing infrastructure (more equipment to inspect and test), and having to maintain power for other production related changes (re-tooling) when outages are taken. These industry demands put growing pressure on those responsible for ensuring that the power system is not only reliable but safe. Using proven testing strategies and taking advantage of improving technology, discussed in this paper, enable facilities to have confidence in their circuit breakers.

REFERENCES Schneider Electric, Class 0600, “Electronic Trip Circuit Breaker Basics, Circuit Breaker Application Guide, Square D,” Data Bulletin 0600DB1104, Section 2 (March 2012): 7.

1

“GENERAL SCOPE,” ANSI/NETA Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems, Section 1 (2011): 1

2

“Section 7.6.1.2: Circuit Breakers, Air, Low-Voltage Power” and “Part B: Electrical Tests,” ANSI/NETA Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems (2011): 70.

3

Dennis Neitzel and Dan Neeser, “Preventive Maintenance and Reliability of Low-Voltage Overcurrent Protective Devices,” Pulp and Paper Industry Technical Conference, 2007, Conference Record: 164-169. 4

John Cadick, P. E., Cadick Corporation and Finley Ledbetter Group CBS, Inc., Determining Circuit Breaker Health Using Vi-

5

bration Analysis, A Field Study. Mose Ramieh III is a Texan, University of Texas graduate (BA) and former US Navy Lieutenant, Mose Ramieh knows a thing or two about getting things done. He is the Manager of Business Development for the Southeast for CE Power and has over 20 years in the electrical testing and maintenance business. Over the years, he has held numerous technical and management positions in the industry and in the US Navy. In 1997, Mose joined PGTI eight months after it was founded. The company served industrial and utility customers in Tennessee and the greater Southeast market. Last year, he was instrumental in the company’s transition to CE Power. He is a certified NICET Engineering Technician, NETA Level IV Technician, Level II Thermographer and a Steam Engineer with Turbine Endorsement (Los Angeles, CA). He has served on the NETA safety committee and is currently a SME for the NETA exam development and CTD Reviewer. Mose is a master at using simple processes to solve seemingly complicated problems, leading and teaching others to do the same. Randall Sagan earned his Electrical Engineering degree from the University of Kentucky. Upon graduation, he worked as a relay engineer at Kentucky Utilities, then became a facility electrical engineer at Toyota Motor Manufacturing. In 1994, he joined the groundbreaking design team at Mercedes-Benz U.S. International (MBUSI) where he currently serves as Electrical Engineer in the Factory Planning Department. Randall recently designed and implemented the safest medium-voltage switchgear in any MercedesBenz facility worldwide. Randall is a Senior Member of the IEEE, a member of the Association of Energy Engineers, NFPA, and NETA. He has served as a Ballot Pool Member for the ANSI/NETA Standards for Acceptance Testing, Maintenance Testing, and Electrical Commissioning Specifications. In addition to teaching and speaking engagements, Randall has presented at numerous technical conferences. Randall retired from running after two marathons and multiple half-marathons. Kayaking and hiking have now become some of his favorite activities. He also finds cooking, theatre, and college sports great diversions to his busy schedule.

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Circuit Breakers Vol.1

CIRCUIT BREAKER AND TRANSDUCER: WHERE DO I CONNECT? PowerTest 2016 Robert Foster, Megger

INTRODUCTION There are numerous types of equipment in the electrical transmission and distribution network that all perform a specific and necessary operation, the circuit breaker is no exception as it serves to protect the valuable assets in the substation. The circuit breaker is unique in the fact that at one time it must function as a nearly perfect conductor while at another time it must function as a nearly perfect insulator, transitioning from one state to the other in a matter of milliseconds, occasionally dispersing enormous amounts of energy during the transition. A circuit breaker is defined as “A mechanical switching device” and the way to determine if the mechanical switching function is working correctly is to hook up a time and travel analyzer to evaluate the operating characteristics of the circuit breaker. When bulk oil circuit breakers were the prevalent technology in substations, travel measurements were performed without question. Over the years, because of various reasons such as lack of outage time, lack of maintenance personnel, and the complexity of hooking up a transducer to the circuit breaker, travel measurements are being performed less and less. Time and travel measurements have been replaced with just contact timing or reduced to solely first trip testing. A recent study by CIGRE working group A3.06 released in 2012 found that 50% of the major failures in a circuit were due to the operating mechanism and 30% were due to the electrical control and auxiliary circuits. While contact timing and first trip are important tests and should be performed, they will not fully test the operating characteristics of the mechanism; therefore neglecting travel measurements should not be standard practice if the true health of the circuit breaker is to be determined.

BASIC MEASUREMENTS MADE WITH THE TRANSDUCER Although the transducer can be attached to the circuit breaker to determine the travel of different parts of its components such as the dashpot, the primary application of a motion transducer is to measure the motion of the main/arcing contacts in the circuit breaker. For the context of this paper, the transducer representing the motion of the main/arcing contacts shall be the focus. The transducer can be hooked to many different parts of the circuit breaker, directly to the pull rod of the main contacts, directly to the mechanism, somewhere on the linkage in between or even to an auxiliary switch.

Many parameters are determined from the transducer but the most important measurement is the stroke of the circuit breaker, in fact all other parameters are derived from the stroke of the circuit breaker. The stroke is defined as the total travel distance of the contacts from resting position in one state, e.g. Closed, to the resting position in the other state i.e. Open or vice versa. It is imperative that one is diligent in connecting the transducer to the manufacturer’s recommended attachment point on the circuit breaker and correcting for any multiplication factors if a direct connection to the contacts cannot be made. At the very least the technician must be consistent in measuring the stroke through periodic maintenance in order to trend the results. If the circuit breaker is gang operated i.e. it has one mechanism operating all three phases then only one transducer is needed: if the circuit breaker has separate operating mechanisms for each phase, then an individual transducer should be used for each mechanism. Once the stroke of the circuit breaker is determined you can derive the velocity of the contacts in different regions of the travel. The most common region to measure velocity is during the arcing zone of the circuit breaker where it is actually interrupting or clearing the fault. Occasionally damping is also measured on the travel curve by calculating the velocity in the damping zone or the time between two predefined points on the travel curve in the damping zone. By observing the closing time along with the travel measurement the penetration or contact wipe can be determined, this is how far the contacts are engaged. Penetration is the length measured from initial contact touch to the final resting position after the operation. Overtravel is measured directly from the travel curve and is the maximum displacement past the resting position that the contacts reach during the operation. Similarly, Rebound is measured from minimum displacement, after the maximum displacement (Overtravel), to the final resting position of the contacts. See Figure 1 for examples of the different parameters that can be measured with a travel transducer. Other parameters can be determined as well but they are all derivatives of the actual stroke measurement of the contacts so it is important to connect the transducer correctly and to accurately measure the stroke of the circuit breaker.

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Circuit Breakers Vol.1

Fig. 1: Typical motion trace

length is selected, the next consideration in size is to make sure the transducer will fit in the space provided. There are two types of measurements made with a linear transducer, the first is a direct measurement as in Figure 2, where the transducer or linkage rod is connected directly to the moving contacts; direct measurements are common in bulk oil circuit breakers, minimum oil breakers, most vacuum CBs and some dead tank SF6 circuit breakers. Although finding a suitable mounting bracket and correctly mounting the transducer can be difficult at times, this method is beneficial because the actual stroke of the transducer is equal to the actual stroke of the contacts, therefore no conversion factor is needed and all parameters measured with the transducer are direct representatives of the motion of the contacts in the circuit breaker; the motion isn’t distorted by any gears, linkages or mechanical play of the interconnections.

TYPES OF TRANSDUCERS AND THE PARAMETERS NEEDED FOR PROPER MEASUREMENTS There are two types of transducers used to measure the contacts of the circuit breaker, linear or rotary. A linear transducer will measure a value of length typically in either inches or millimeters whereas a rotary transducer will measure a value of angle, typically degrees, which then must be converted to inches or millimeters. There are various designs of transducers such as resistive, optical, magnetic etc. but they generally give an analog or digital output. Linear transducers are available in a wide variety of lengths ranging from 25 mm or less, commonly used for vacuum circuit breakers, all the way up to 1000 mm or more, typical lengths are from 225-300 mm for SF6 dead tank circuit breakers and 500-600 mm for bulk oil circuit breakers. When first setting up for motion measurements, the type of transducer to be used, rotary or linear, must be selected. Although a lot of breakers allow you to use either type of transducer, the manufacturer generally will specify a preference and it is always recommended to use the manufacturer’s specified attachment point, transducer type, and conversion factor (if needed). Caution: Before connecting the transducer, always ensure that the circuit breaker is in the open position, make sure no energy is stored in the mechanism, or if it is impractical to discharge all the energy in case of some pneumatic or hydraulic mechanisms, make sure the maintenance pin that blocks operation is set, finally de-energize the power going to the control circuitry. No matter where the transducer is placed, no part of the transducer, mounting bracket, or travel rod if used, must be in the direct path of any moving parts of the circuit breaker that will cause damage to the transducer or its accessories. If a linear transducer is used it must be of suitable length to cover the total travel distance the transducer will encounter, including overtravel, on both close and open operations. If unsure of whether the transducer is of suitable length, a common practice is to attach the transducer in one positon e.g. closed, then detach the transducer and operate the circuit breaker so it changes state. Now that the circuit breaker is in the opposite position i.e. open, re-attach the circuit breaker to see if it is of suitable length. Once a transducer of adequate

Fig. 2: Bulk Oil circuit breaker with direct linear connection The second type of measurement with a linear transducer is an indirect measurement as in Figure 3, where the transducer is not connected directly to the moving contacts but to a part of the circuit breaker that is connected to the moving contacts such as the mechanism or interconnecting linkage. When this type of connection is used, the travel of the transducer may or may not be equal to the travel of the main contacts. If the travel of the transducer is different, a conversion factor or ratio should be used in order to obtain the correct stroke length and travel parameters of the circuit breaker. For example, 80 mm of transducer stroke can be equivalent to 120 mm of contact stroke so a multiplication factor of 1.5 shall be used.

Fig. 3: SF6 dead tank circuit breaker with indirect linear connection

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Circuit Breakers Vol.1

When a rotary transducer is used, the measured quantity is in degrees, or occasionally radians, and is then converted to a unit of length. There are two types of conversions, the first is a constant conversion where one degree is equal to a certain value of length throughout the entire travel of the contacts. This is common where the mechanical linkage is simple with few interconnecting parts. When the linkage is more complicated, the ratio of the angle to length may not be constant throughout the total travel of the contacts i.e. one degree might equal one and a half millimeters for the first ten degrees then for the next ten degrees of travel, one degree might equal two and a half millimeters. In these cases a conversion table must be used to account for the varying values. Rotary transducers have the advantage of being relatively small and with a few accessories one kit can hook up to many different styles or types of circuit breakers. The disadvantage of the rotary transducer is that you need to know the conversion factor or table in order to calculate the correct parameters of your circuit breaker. If the conversion factor or table is not provided in the manual, the breaker manufacturer should be contacted. Rotary transducers are most common on live tank SF6 circuit breakers but are also used on certain types of dead tank SF6 breakers, bulk oil circuit breakers and generator circuit breakers. See Figure 4 and Figure 5 for examples of rotary transducer connections.

Fig. 5: Rotary transducer on SF6 dead tank circuit breaker Once the proper transducer, and conversion factor if needed, is selected, most of the parameters such as stroke, overtravel, rebound, penetration etc. will come out of the measurements automatically. One of the exceptions to this is the velocity measurement. In order to calculate the velocity the analyzer must be told where on the curve velocity should be measured. Two different points on the travel curve are selected and the average velocity between these two points is calculated. These points can reference many different points on the curve such as distance below close, distance above open, percentage of stroke, distance below upper point etc. Another common reference point is an event during the timing e.g. contact touch or contact separation. The two most important factors that influence the selection of the speed calculation points are that the velocity is measured on a linear portion of the travel curve and that it is measured during the arcing zone, therefore the calculation points are generally near contact touch on the close and contact separation on the open. A common misconception for calculating velocity is to take the total travel distance (stroke) and divide it by the total time it takes for the contacts to reach the fully closed positon, this will not determine the velocity during the arcing zone but the average velocity for the total travel. In this case the acceleration at the beginning of the travel and deceleration at the end will mask the instantaneous velocity around the arcing zone.

The speed calculation points can vary by manufacturer, type of circuit breaker, type of mechanism etc. so the manufacturer should be consulted to select the proper speed calculation points; this information is generally available in the manual or in the original test report provided with the circuit breaker. If no information is given, it is recommended to use contact touch and 10 ms before for the close calculation Fig. 4: Rotary transducer on SF6 live tank circuit breaker points and contact separation and 10 ms after for the open calculation points. See Table 1 for a list of common transducer types and speed calculation points used by different manufacturers. Note: the manufacturer or manual should always be consulted for proper transducer and speed calculation points. Table 1: Typical transducer types and speed calculation points Circuit Breaker Type Manufacturer Transducer Type Bulk Oil

ITE

Linear

Conversion Factor

Open Speed Points

Close Speed Points

None

See commissioning test

See commissioning test

Bulk Oil

Pacific Electric

Rotary

Constant: See Manual

See commissioning test

See commissioning test

Bulk Oil

Westinghouse

Rotary

Constant: See Manual

See commissioning test

See commissioning test

SF6 Dead Tank

ABB

Linear

None

SF6 Dead Tank

Alstom

Rotary

Constant: See Manual

See manual: Typically Below Closed and a Differential in length is referenced Contact Seperation, 10 ms after

Contact Touch, 10 ms before

SF6 Dead Tank

Mitsubishi

Linear

None

Contact Seperation to 90% of travel

10% of travel to Contact Touch

SF6 Dead Tank

Siemens

Linear

Constant: See Manual

Contact Seperation, 10 ms after

Contact Touch, 10 ms before

SF6 Live Tank

ABB

Rotary

Table: Consult Manufacturer

SF6 Live Tank

Various

Rotary

Table: Consult Manufacturer

Consult Manufacturer

Consult Manufacturer

Vacuum

Various

Linear

None

Consult Manufacturer

Consult Manufacturer

Consult Manufacturer: Typically Below Closed and a Differential in Time

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Circuit Breakers Vol.1 CASE STUDY OF SIEMENS SPS2-38-40-2 CIRCUIT BREAKER In order to investigate how transducer placement affects travel measurements, several transducers, both rotary and linear, were attached to a Siemens SPS2-38-40-2 SF6 dead tank circuit breaker fitted with an FA2.20 mechanism. The breaker is rated at 38kV and capable of interrupting 40kA, it has one break per phase and is gang operated, see Figure 6 and Figure 7.

Fig. 8: Transducer connection Linear Mech

Fig 6: Siemens SPS2-38-40-2 nameplate Siemens recommends measuring motion with a linear transducer that is attached to an actuating arm on the mechanism (Figure 8). They state that 80 mm of travel at the mechanism is equal to 120 mm of travel at the contacts i.e. there is a 1.5 multiplication factor used to determine the true contact motion. They also state that the speed calculations points of Contact Touch and 10 ms before for the close operation and Contact Separation and 10 ms afterwards for the open operation shall be used. In addition to the standard transducer connection, four more transducer connections were made; one linear transducer was connected to the end linkage arm on the third phase and three rotary transducers were attached to the rotating splines that drive the interrupter (Figure 9). The same speed calculation points were used for all connections.

Fig 7: Siemens SPS2-38-40-2 circuit breaker with FA2.20 mechanism

Fig 9: Transducer connections, from left to right Linear Linkage, Rotary C, Rotary B, and Rotary A In order to compare the different transducer measurements, at first no conversion factors were used on the two linear transducer connections and a factor of 1 degree equals 1 millimeter was used for the rotary transducer. In Figure 10 below you can see the motion traces from the three different connections for a close operation, all three are scaled at 10 mm per division. M A on the graph in red is the linear transducer connected directly to the mechanism per Siemens recommendations, this will be referred to as Linear Mech. M B in black is the rotary transducer and is connected to the rotating spline on B Phase, this will be called Rotary B. Lastly M C in blue is the linear transducer connected to the end of the interconnect linkage near the rotating spline on C phase and shall be referred to as Linear Linkage. For all graphs, the bottom of the curve is the fully open position and the top of the curve is the fully closed position. The timing for each phase is also included where a thin line is open and a thick line is closed. From the timing results, all three phases are relatively in sync with 0.3 ms difference between the slowest and the fastest phase with a close time of about 48 ms. As expected the travel measurements vary widely due to the different connection points. The stroke for Linear Mech is 78.9 mm, Rotary B is 59.0 mm (degrees) and Linear Linkage is 106.5 mm. From these stroke measurements the travel dependent parameters i.e. velocity, overtravel, penetration, rebound etc. will all vary by transducer placement as well.

36

Fig 10: Close with no conversion, Linear Mech in red (center trace), Rotary B in black, and Linear Linkage in blue (top trace) An examination of the open operation will show similar variance in stroke values for the different connections as seen in Figure 11.

Circuit Breakers Vol.1

Fig 13: Close with conversion factors applied, bottom to top: Linear Mech in red, Rotary B in black, and Linear Linkage in blue

Fig 14: Open operation with conversion factors applied, Linear Mech in red, Rotary B in black, and Linear Linkage in blue Fig 11: Open with no conversion, Linear Mech in red (center trace), Rotary B in black, and Linear Linkage in blue (top trace) As mentioned above, the circuit breaker manual states that 80 mm of motion at the mechanism is equivalent to 120 mm of contact movement, therefore with a transducer stroke of 78.9 mm the contact stroke is determined to be 118.35 mm. Since the other transducers were measuring motion on the same operation, the ratios of the alternate linear transducer and rotary transducer can be calculated. Using simple algebra the ratios of 59.0° = 118.35 mm (Rotary B) and 106.5 mm = 118.35 mm (Linear Linkage) are used to determine the conversion factors of 2.003 mm/° and 1.1099 mm/mm respectively. With this information the circuit breaker was measured again with the appropriate conversion factor applied to each transducer. The results are shown in Figure 12, Figure 13, Figure 14, and Figure 15.

Fig 12: Close operation with conversion factors applied, Linear Mech in red, Rotary B in black, and Linear Linkage in blue

Fig 15: Open with conversion factors applied, bottom to top: Linear Mech in red, Rotary B in black, and Linear Linkage in blue From the results above it can be seen that even with three different transducer attachment points and two different types of transducers, that all three produce very similar results as long as the correct conversion factor is applied. The maximum difference between stroke values is 0.2 mm on the close operation and 0.5 mm upon opening. Penetration, overtravel, and rebound are very close for the three different measurements too. One interesting observation is that the travel trace of Linear Mech, the linear transducer connected directly to the mechanism, has an oscillation throughout the entire movement, and Linear Linkage, the linear transducer connected to the end of the linkage, has a slight oscillatory movement at the beginning and the end of travel. Most likely the flex in the travel rod and the connection of the rod to the transducer is causing some of this movement. Additionally since Linear Mech is connected directly to

Circuit Breakers Vol.1

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the mechanism, the vibrations of the mechanism are affecting the motion throughout the entire travel. Since the close operation requires more energy, closing the breaker and charging the opening spring, this effect is more apparent on the close operation. One interesting note is that the velocity is different for each connection, this is in part due to the calculation points being based on contact touch and separation so the variance in the timing will affect where on the curve the velocity is calculated. On Linear Mech the vibrations will also affect the velocity calculations, if one of the speed calculation points rests on the crest of an oscillation and the other speed calculation point rests on the trough of an oscillation, the speed can vary dramatically compared to points taken on a neutral part of the oscillation. This effect can be seen by examining several operations in a row and observing that the velocity of Linear Mech can vary by 0.16 m/s or 3%, whereas the other two connections vary by a magnitude less. Play in the linkages will have some effect on the velocity calculations. One last thing to consider is that a linear conversion factor was assumed, i.e. a conversion constant was used. Comparing Rotary B to Linear Linkage, they align better at the beginning and a the end of travel, in the middle of the movement they diverge slightly, since this is the portion of the curve that velocity is calculated, it follows that the speeds would diverge slightly as well. If the geometries were analyzed and a conversion table was built for both connections, they would most likely overlap throughout most of the travel and the velocities would align more closely. The motion traces of the three different rotary transducers can be examined to see how the same connection can be placed at different distances from the mechanism, i.e. at different parts along the interconnecting linkages, and yield similar results. Figures 16 and Figure 17 show the results from a close operation. M A on the graph in red is the rotary transducer connected directly to the rotating spline that drives the interrupter in Phase A, this will be referred to as A phase. Similarly M B in black is the rotary transducer connected to Phase B and will be referred to as B phase. Lastly M C in blue is the rotary transducer connected to Phase C and shall be referred to as C phase.

Fig 17: Close operation with conversion factors applied, Rotary A in red, Rotary B in black, and Rotary C in blue Once again all three traces are very similar with a variance in stroke of only 1.2 mm between the shortest and the longest phase. A few things to note are that A phase begins to move approximately 0.5 ms before phases B and C which can be expected since it is the closest connection to the mechanism. Both A and C phase produce very smooth traces throughout the motion but B phase has some oscillations in the first 20 ms of travel. These oscillations are most likely due to a mechanical delay, B phase is pushed by the linkage from A phase and then it has to push the linkage to phase C. Any mechanical play within the connections between B and the other two phases will result in small perturbations. The velocities of A and C are fairly close but B phase is 0.2 m/s slower. This is most likely caused by two different factors, first the oscillations in the trace can cause different speed points to be taken as mentioned above, secondly the timing of the three phases is slightly different and the speed calculation point is based on contact touch, careful observation of the speed calculation points reveals that they do not line up in time. Observing the open operation in Figure 18 and Figure 19 shows even more consistency between the different phases.

Fig 18: Open operation w/conversion factors applied, bottom to top: Rotary A in red, Rotary B in black, and Rotary C in blue Fig 16: Close operation with conversion factors applied, bottom to top: Rotary A in red, Rotary B in black, and Rotary C in blue

38

Fig 19: Open operation with conversion factors applied, Rotary A in red, Rotary B in black, and Rotary C in blue All three traces practically lay on top of each other with no deviation until the contacts reach the closed position. The stroke of the different phases is closer with only a 0.5 mm difference between the shortest and the longest phase. Once again the velocities of the three phases are different but observing the contact times and speed calculation points shows that the velocity is calculated at slightly different points on each curve thus changing the values slightly. If the speed calculation points are changed to reference below closed and a differential, then B and C travel at the same velocity while A phase travels slightly slower due to it having to push the other two phases.

RECOMMENDATIONS WHEN LITTLE OR NO INFORMATION IS PROVIDED BY THE MANUFACTURER Occasionally the manufacturer may not provide the appropriate information for travel measurements and it is left to the technician to decide what type of transducer to use and where to connect, what conversion factor/table to use (if any) and the proper speed calculation points for determining the velocity of the contacts. Careful consideration should be taken before attaching a transducer and once a method is determined, the same attachment and measurement parameters should be used in the future for trending purposes. Although these travel recordings will provide valuable data and can be used for future reference, it should be noted that the values obtained may not necessarily be comparable to the factory test reports or parameter limits. Once again, no matter where the transducer is placed, no part of the transducer, mounting bracket, or travel rod if used, must be in the direct path of any moving parts of the circuit breaker in order to avoid damage to the transducer and its accessories. The first thing to look for in deciding where to connect the transducer is if connection directly to the contacts or actuating arm of the contacts is possible. Then a linear transducer can be connected and the correct stroke, velocities and other parameters will be measured without the need of a conversion table. If direct connection to the contacts is not possible, which is often the case,

Circuit Breakers Vol.1 then a spot that is very close to the contacts with the minimal amount of linkages between the connection point and the contacts should be selected; either a linear or rotary transducer can be used. Per IEC 62271-100, the mechanical characteristics can be recorded with a travel transducer at “convenient locations on the drive to the contact system where there is a direct connection, and a representative image of the contact stroke can be achieved.” Connecting directly to the mechanism can cause unwanted vibrations and influence the results, if possible this should be avoided. If an indirect connection is used then there are two options, create a conversion table/factor, or measure the absolute value of the motion, in either length or angle, and trend the results with the transducer connected in the same spot during future testing. If a conversion factor or table is to be used, the connection points and linkages can be examined and measured to develop a trigonometric function that relates the transducer movement to the contact motion. The function can also be determined from the mechanical drawings of the circuit breaker. If the stroke of the contacts are known, another, less accurate, method of creating a conversion factor is to assume a linear relationship between the connection point and the contacts. The known stroke of the contacts can be divided by the measured stroke of the transducer to create the conversion factor. This value can then be used to measure the travel characteristics for initial fingerprint measurements and future testing. It should be noted that if the relationship between the connection point and the contacts is not linear, the other stroke dependent parameters such as velocity, overtravel, rebound etc. may not be correct. Additionally, if this measurement is made when there are issues with the circuit breaker i.e. the stroke is not correct, the subsequent measurements will also be incorrect. If there are other circuit breakers of the same type available it is beneficial to compare measurements to verify the correction factor. If no speed calculation points are provided by the manufacture then it is recommended to use contact touch and 10 ms before for close and contact separation and 10 ms after for the open. This will assure that the velocity is measured in the critical arcing zone of the interrupter. Once again it should be mentioned that once a method of transducer connection, conversion factor, and speed calculation points are used, they should continuously be employed through the life of the circuit breaker in order to trend the results.

CONCLUSION Circuit breakers are a key element in the electrical transmission and distribution network throughout the world. IEEE C37.09 states that “Travel-time curves shall be obtained for all outdoor circuit breakers with an interrupting time of three cycles or less” and NETA requires time and travel analysis on medium and high voltage SF6 and Oil circuit breakers. In order to verify that the circuit breaker will operate effectively when called upon to protect various assets in the network, time and travel analysis must be performed.

Circuit Breakers Vol.1 When determining what type of transducer should be used, where it shall be connected, and what conversion factor and speed calculation points are to be applied, the first step to be taken is to consult the manual, if there is no directions contained in the manual or if the directions are unclear, the next step is to contact the manufacturer. If this option is not available either, then the technician performing the testing must decide how to proceed. Preferably a direct connection to the contacts shall be obtained but if this is impractical, a connection point that is near the contacts with a minimal amount of linkage that can accurately represent the travel of the contacts shall be used. If the geometry of the circuit breaker is known, a conversion factor or table can be created to accurately measure the stroke and the parameters that are dependent on the stroke. Even if the original measurement points that the manufacturer used are not known, valuable data will still be measured with a transducer as long as it is placed in a sensible location. In fact, even if motion is measured at different points on the circuit breaker, as long as the correct conversion factor is applied, the results will come out very similar. If an accurate conversion factor or table cannot be created or is not known, the absolute value of the transducer stroke and its parameters can be measured upon commissioning or when the circuit breaker is in a known good condition. These values can then be trended over time to track any changes in the movement or operation of the circuit breaker. Lastly, once one type of connection and conversion factor is chosen, all future measurements should be made using the same setup in order to correctly trend the results.

REFERENCES “IEEE Standard Definition for Power Switchgear,” IEEE Std C37.100-1992 (R 2001). CIGRE TB 510: “Reliability of High Voltage Equipment – Part 2: SF6 Circuit Breakers;” WG A3.06; 2012 Siemens Type SPS2-38-40-2 Circuit Breaker Manual IEC 62271-100: “International Standard High-voltage switchgear and controlgear – Part 100: Alternating-current circuitbreakers.” CBTestingGuide_AG_en_V02: “Megger Circuit Breaker testing guide” (2012). IEEE Std C37.09-1999 (R2007): “IEEE Standard Test Procedure for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis.” NETA ATS 2013: Standard for Acceptance Testing Specifications Robert Foster is an applications engineer with Megger U.S.

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Circuit Breakers Vol.1

HOW DISRUPTIONS IN DC POWER AND COMMUNICATIONS CIRCUITS CAN AFFECT PROTECTION PowerTest 2014 Karl Zimmerman and David Costello, Schweitzer Engineering Laboratories, Inc.

THE ROLE OF DC AND COMMUNICATIONS IN PROTECTION SYSTEMS Fig. 1: Two-Terminal Digital Line Pilot Protection Scheme. shows a one-line diagram of a typical two-terminal line protection system using distance relays in a communicationsassisted pilot scheme. Bus S

Bus R 52

21

52

Communications Equipment

Communications Equipment

21

Channel

125 Vdc

48 Vdc

48 Vdc

125 Vdc

Fig. 1: Two-Terminal Digital Line Pilot Protection Scheme. To successfully clear all faults on the line within a prescribed time (e.g., less than 5 cycles), all of the elements in Fig. 1: Two-Terminal Digital Line Pilot Protection Scheme.—breaker, relay, dc supplies, communications, current transformers (CTs), voltage transformers (VTs), and wiring—need to perform correctly. It is not unusual for lines to have redundant and backup protection schemes, often using different operating principles, with multiple channels and/or dc supplies. Human factors (such as design, settings, procedures, and testing) are not shown in Fig. 1: Two-Terminal Digital Line Pilot Protection Scheme. but must also perform correctly. Additionally, security is as important a consideration as dependability. All of the elements and human factors must perform correctly to ensure that the protection scheme correctly restrains for out-of-section faults or when no fault is present.

THE EFFECT OF DC AND COMMUNICATIONS DISRUPTIONS ON OVERALL RELIABILITY Protection systems must be robust even with transients, harsh environmental conditions, and disruptions in dc supply, dc circuits, or interconnected communications. These disruptions include loss of dc power due to failure or human action, noise on the battery voltage, dc grounds, interruptions in dc supply, and subsequent re-

start or reboot sequences. In the case of communications, these disruptions include channel noise, channel delays, interruptions due to equipment problems or human action, unexpected channel switching, and restart or resynchronization sequences. Fault tree analysis has been beneficial in analyzing protection system reliability, comparing designs, and quantifying the effects of independent factors. For example, the rate of total observed undesired operations in numerical relays is 0.0333  percent per year (a failure rate of 333 • 10–6). By comparison, the rate of undesired operations in line current differential (87L) schemes where disturbance detection is enabled is even lower at 0.009 percent per year (a failure rate of 90 • 10–6). However, undesired operations caused by relay application and settings errors (human factors) are 0.1 percent per year (a failure rate of 1,000 • 10–6). 1 Unavailability, which is the failure rate multiplied by the mean time to repair, is another measure used to compare reliability. The unavailability of dc power systems is low at 30 • 10–6, compared with 137 • 10–6 for protective relays and 1,000 • 10–6 for human factors. These data assume a faster mean time to repair a dc power system problem (one day) compared to relays and human factors (five days). Communications component unavailability indices are similar to those of protective relays.2 The North American Electric Reliability Corporation (NERC) State of Reliability 2014 report found that from the second quarter of 2011 to the third quarter of 2013, 5  percent of misoperations involved the dc system as the cause, compared with 15 percent for communications failures, 21 percent for relay failures, and 37 percent for human factors. 3 From these data, we can see that dc and communications failures are a small but significant factor in reliability. Fault trees allow us to see how the failure rate of one device impacts the entire system (see Fig. 2). Fault trees also allow us to evaluate how hidden failures, common-mode failures, improved commissioning tests, and peer reviews impact reliability.

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Circuit Breakers Vol.1

Fig. 4: DC Control Circuit Showing Bus Differential Trip Output.). Fortunately, due to testing that was being performed that day, the lockout relay output contacts were isolated by open test switches that kept it from tripping any of the 230 kV circuit breakers.

1178 Note: Numbers shown are unavailabilities • 106

Protection Fails to Clear In-Section Fault in the Prescribed Time

3

589

589

Protection at S Fails

Protection at R Fails

Same as Protection at S 2

17 203

4

Common-Mode Common-Mode Hardware/ Settings/Design Firmware Errors Failures 500 5

18

204 13

Breaker at S Fails to Interrupt Current 80 1969

Main 2 Protection at S Fails

87-Z OUT 1 TS

2219

Main 1 Protection at S Fails

TS

14

1

G Relay Fails 137

Relay App. or Settings Errors 1000

Breaker Trip Coil Fails 120

DC System Fails 30

CT Fails 3•9 = 27

VT Fails 3 • 15 = 45

CT Wiring Errors 50

VT Wiring Errors 50

DC Wiring Errors 50

Hidden Microwave Microwave Microwave Comm. Failures Channel Tone Transceiver DC 10 Fails Equipment Fails System 100 Fails 200 Fails 100 50

F 86B

Fig. 2: Dependability Fault Tree for Dual-Redundant Permissive Overreaching Transfer Trip (POTT) Scheme.2 However, fault trees do not easily identify how a failure or activity in one subsystem affects another subsystem. Inspired by Christopher Hart, acting chairman of the National Transportation Safety Board, we wanted to investigate the interaction of components, subsystems, and human factors on the reliability of the entire protection system. At the 2014 Modern Solutions Power Systems Conference, Mr. Hart spoke of the aviation industry as a complex system of coupled and interdependent subsystems that must work together successfully so that the overall system works. In aviation, a change in one subsystem likely has an effect throughout other subsystems (see Fig. 3: Aviation Safety Involves Complex Interactions Between Subsystems.). 4

C B

Fig. 4: DC Control Circuit Showing Bus Differential Trip Output. The bus differential relay contact closure was easily repeated by bumping the relay chassis. The simple apparent cause could have been classified as human error, product defect (failure to meet industry shock, bump, and vibration standards), or relay hardware failure. However, subsequent analysis by the relay manufacturer showed momentary low resistance across the normally open contact when the chassis was bumped. Additionally, visual inspection noted evidence of overheating in the contact area (the outside of the plastic case was slightly dimpled). The contact part was x-rayed while it was still mounted on the main printed circuit board. The adjacent, presumed-healthy contact was x-rayed for comparison. The x-ray images are shown in Fig. 5: X-Ray Images of the Healthy, Adjacent Contact (Left) and Damaged Contact (Right)., with the adjacent, healthy Form-C contact on the left and the damaged Form-C contact on the right. In each contact, there is a stationary normally open contact surface (top), a moving contact surface (center), and a stationary normally closed contact surface (bottom). Note the difference in contact surfaces and spacing. The relay manufacturer estimated that the output contact was likely not defective but rather had been damaged due to interrupting current in excess of the contact’s interruption rating.

Fig. 3: Aviation Safety Involves Complex Interactions Between Subsystems. The protection system, and the entire power system, is very similar to the aviation industry. Fault trees and high-level apparent cause codes do not necessarily make these subsystem interdependencies apparent. For example, in December 2007, while performing maintenance testing, a technician bumped a panel and a microprocessor-based, high-impedance bus differential relay closed its trip output contact (87-Z OUT1 in Fig. 4: DC Control Circuit Showing Bus Differential Trip Output.), tripping the bus differential lockout relay (86B in

Fig. 5: X-Ray Images of the Healthy, Adjacent Contact (Left) and Damaged Contact (Right).

42 The output contact manufacturer further inspected the output contact part. The output relay cover was removed and the inside of the part was observed and photographed (see Fig. 6: Pictures From Contact Manufacturer Confirming Heat Damage From Exceeding Current Interruption Rating.). The plastic components were melted, the spring of the contact point was discolored and deformed by heat, and the contact surfaces were deformed, rough, and discolored. The root cause of the contact damage was confirmed: at some point prior to the misoperation, the interrupting current was in excess of the contact’s interruption rating.

Circuit Breakers Vol.1 sure that let-through currents from connected output contacts did not inadvertently cause these auxiliary relays to pick up. Especially when used with transformer sudden pressure relays with poor dielectric withstand capability, extra security measures were taken to prevent auxiliary relays from operating in case a voltage surge caused a flashover in the normally open contacts of the pressure relay. In Fig.  7: Typical Security Precaution for Dielectric Strength Failure of a Sudden Pressure Relay Contact., the normally closed contact from the sudden pressure relay (63) shunts the auxiliary relay operating coil (94) so that if the normally open contact flashes during a voltage transient, the auxiliary relay will not operate.7 (+) 63

63

In this example, the failure mode was a relay contact closing when the relay chassis was bumped. According to NERC data, 60 percent of root-cause analyses stop at determining the mode.5 True root-cause analysis requires us to dig deeper to understand the failure mechanism or process that led to the failure. Then, we can educate others and ensure that improvements prevent the problem from reoccurring. In NERC contributing and root-cause vernacular, this incident would be due to a defective relay (A2B6C01) caused by an incorrect test procedure (A5B2C07) caused by a failure to ensure a quality test procedure (A4B2C06). An important theme in the case studies that follow is how an action or failure in one subsystem affects other subsystems and overall reliability.

TRADITIONAL DC PROBLEMS The dc control circuits used in protection systems have always been complex. Problems that need to be mitigated include circuit transients, sneak or unintended paths, stored capacitance, letthrough and leakage currents, and more.6 For example, electromechanical auxiliary relays were once commonly used for local annunciation, targeting, or contact multiplication. Some of these relays were high speed and quite sensitive. Care was taken to en-

94

94

86

Fig. 6: Pictures From Contact Manufacturer Confirming Heat Damage From Exceeding Current Interruption Rating. It is important at this point to persist in analysis and examine testing mandates, procedures, and work steps to find root cause. In this case, commissioning testing, represented as one human factor subsystem in the fault tree (relay application), performed to improve reliability was flawed in such a way that the protective relay hardware was damaged and induced a failure in that subsystem. In addition, maintenance testing, mandated by NERC and intended to improve reliability, was flawed in such a way that the relay was damaged and could have potentially caused a misoperation.

94

(–)

Fig. 7: Typical Security Precaution for Dielectric Strength Failure of a Sudden Pressure Relay Contact. Precautions must be taken to avoid these same dc circuit anomalies as we transition to new technology platforms and design standards. As auxiliary relays are replaced by microprocessor-based relays, pick-up time delays are required on relay inputs that are used to directly monitor these same sudden pressure relay normally open contacts to maintain security. 8

TRADITIONAL COMMUNICATIONS PROBLEMS Communications that are used for protection systems perform well but are not perfect. One well-known communications component problem involves the application of power line carrier for transmission line protection schemes. In directional comparison blocking (DCB) schemes, high-frequency transients can produce an undesired momentary block signal during an internal fault. Fig.  8: Momentary Carrier Block Input Produced by Fault-Induced Transient. shows one such incident. Engineers must adjust frequency bandwidths, add contact recognition delay, or tolerate the possibility of a slight delay in tripping for internal faults. Conversely, if an external fault occurs, the momentary dropout of the carrier blocking signal, referred to as a “carrier hole,” can produce an undesired trip, as shown in Fig. 9: Carrier Holes in a DCB Scheme.. These dropouts are often attributed to a flashover of the carrier tuner spark gap and can be avoided by improved maintenance of the carrier equipment or can be dealt with by adding a dropout delay on the received block input.

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Circuit Breakers Vol.1

ed by opening test switches. After successful secondary-injection testing, the relay tripped the circuit breaker during the process of putting the protection system back into service. 9

Momentary Carrier Block

Fig. 8: Momentary Carrier Block Input Produced by Fault-Induced Transient.

Event data showed only one current (A-phase) at the time of trip. This indicated that the technician had reinstalled the trip circuit first by closing the trip output test switch. Next, a single current was reinstalled by closing its test switch. Because there was load flowing through the in-service breaker and CTs, the relay, at this step in the sequence of events, measured A-phase current and calculated 3I0 current and no voltages. It issued a trip. This was a valuable lesson for this utility in the early adoption phase of these relays and led to a specific procedure and sequence that is used when returning a relay to service. The sequence of steps used to restore the system to service is the reverse of that used to remove the system from service and is as follows: 1. Place all three voltage circuits back into service (i.e., close the voltage test switches). 2. Place all three current circuits back into service. 3. Use meter commands or event data to verify the proper phase rotation, magnitude, and polarity of the analog measurements. 4. Reinstall the dc control inputs.

Carrier Holes

5. Use target commands or event data to verify the statuses of control inputs. 6. Reset relay targets and verify that trip and breaker failure outputs are reset.

Fig. 9: Carrier Holes in a DCB Scheme. Protection system communications options today include many media in addition to power line carrier, such as microwave, spreadspectrum radio, direct fiber, multiplexed fiber networks, Ethernet networks, and more. Each medium has its own set of potential problems, such as channel noise, fault-induced transients, channel delays, dropouts, asymmetry, security, buffers and retry, interruptions due to equipment problems or human action, unexpected channel switching, and restart or resynchronization sequences. The trends in our industry include communicating more, exploring new and creative applications for communications, and replacing intrastation copper wiring with microprocessor-based devices and communications networks. As more and more communications and programmable logic are used, it is critical to analyze, design, and test for potential communications problems.

TRADITIONAL PROCEDURE PROBLEMS The sequence in which work tasks are performed is important. A familiar example will highlight this concept. A primary microprocessor-based line relay had been taken out of service for routine maintenance testing. Trip and breaker failure initiate output contacts, as well as voltage and current circuit inputs, had been isolat-

7. Place the trip and breaker failure output circuits back into service. Similarly, when disrupting communications circuits or dc power, we must thoughtfully consider what parts of the protection system should be isolated and the careful order of steps to take in the process of returning the system to service. Analysis, design, and testing should be devoted to this, considering our increased dependence on interdevice communications and programmable logic. The following section highlights some interesting system events where disruptions in dc and/or communications directly affected protection.

PROTECTION SYSTEM EVENTS CAUSED BY DC OR COMMUNICATIONS SYSTEM DISRUPTIONS Case Study 1: Breaker Flashover Trip After Relay Restart Fig. 10: Case Study 1 System One-Line Diagram Uses Remote I/O Module for Breaker Interface. shows the simplified one-line diagram of a 161 kV substation for an event in which a breaker failure flashover logic scheme operated after a relay restart (i.e., dc power supply to the relay was cycled off and on), causing a substation bus lockout.

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Circuit Breakers Vol.1

Remote I/O Module

Communications Link

50FO 52a

21, 67, etc. 50BF With Breaker Flashover Logic

161 kV

The user can define a time delay for breaker failure to be declared. In this case, it was 9 cycles.

Trip or Close

Dropout Delay 0

S

Q

6

Breaker Failure Flashover Timer 9 0

Breaker Failure Flashover

R

12.47 kV Lockout Relay

Fig. 12: Breaker Failure Flashover Logic. Fig. 10: Case Study 1 System One-Line Diagram Uses Remote I/O Module for Breaker Interface. In this system, the breaker status auxiliary contacts (52a and 52b) and other monitored breaker elements are connected to a remote I/O module. The I/O module converts hard-wired inputs and outputs to a single fiber link from the module at the breaker to the relay located in a remote control house (see Fig.  11: Monitored Points From the 161 kV Circuit Breaker Using a Remote I/O Module and Fiber Interface to the Relay.).

The event data in Fig. 13 show the status of the relay elements immediately after the power cycle. Current is already present, but the breaker status (52AC1) is a logical 0 (not asserted). Thus, the breaker failure flashover element (FOBF1) asserts and produces the breaker failure output (BFTRIP1), which subsequently operates the substation lockout relay.

52 Trip 1 52 Trip 2 52 Close Communications Link

52 Low Gas Alarm 52 Low Gas Trip I/O Module Alarm

Remote I/O Module

Relay

52 Spring Charge Alarm 52 Trip Coil Monitor 1 52 Trip Coil Monitor 2 52a 52b

Fig. 11: Monitored Points From the 161 kV Circuit Breaker Using a Remote I/O Module and Fiber Interface to the Relay. The user applied the I/O module to eliminate extra wiring and inherent noise and hazards associated with long (i.e., several hundred feet) runs of copper wire. Also, the fiber connection was continuously monitored. The monitored communications link can be set to default to a safe state, as specified by the engineer. In this case, if communications were lost (e.g., fiber was disconnected or damaged or there was an I/O module failure), the breaker status would default to its last known state before the communications interruption. The breaker failure flashover logic is shown in Fig. 12: Breaker Failure Flashover Logic.. It detects conditions where current (50FO) flows through an open breaker (NOT 52a). When a breaker trips or closes, the logic is blocked with a 6‑cycle dropout delay.

Fig. 13: Breaker Failure Flashover Logic Asserts Due to Current Measured While Breaker Is Sensed Open. The undesired trip occurred because the breaker failure flashover logic began processing before the communications link between the I/O module and the relay was reestablished. We can see the communications link status between the relay and the I/O module (ROKB) asserted about 14 cycles later. The event report does not show much about what happened before the trip during the relay restart process. However, from an internal sequential event record, we were able to assemble the timeline, as shown in Fig. 14.

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Circuit Breakers Vol.1

Pre-Event Report Relay Restart

Event Report 9 Cycles

22 Cycles

S

87

R

Line Switch (89)

Q FOBF1

86

b

89

1/4 Cycle

BFTRIP1 52AC1

T

ROKB

Communications Link Reestablished

Fig. 14: Event Timeline Shows Relay Restart and Arming of Flashover Logic Before Breaker Status Is Recognized. The relay restart sets the latch (Q) and starts the 9‑cycle breaker failure flashover timer. At 9 cycles, FOBF1 asserted. By the time the communications link was established (at 22  cycles), the trip had already occurred. Important lessons were learned in this case study. Relays and I/O modules might reboot, operators may cycle power to relays when looking for dc grounds or performing other troubleshooting, relays may employ diagnostic self-test restarts, and so on. There is no default state for most logic during a relay restart. In a relay restart, all of the logic resets and begins processing from an initial de-energized state, as is the case when a relay is powered up and commissioned for the first time. In this case, designers considered a loss of communications but did not consider how a loss of dc supply or relay power cycle would affect the communications status and the logic processing order during a start-up sequence. In the breaker failure flashover logic, the breaker status is used directly in a trip decision. We should supervise the breaker failure flashover logic with the monitored communications bit (i.e., FOBF1 AND ROKB) to prevent the flashover logic from being active until communication is established. To further avoid such undesired operations, commissioning tests should include power cycles to test for secure power-up sequences in logic processing.

Case Study 2: Protective Relay Applied as a Lockout Relay Operates Due to a Power Cycle In Case Study 2, a microprocessor-based transformer differential relay was applied as a lockout relay, as shown in Fig. 15. When dc power to the relay was switched off and on, the lockout logic output asserted, causing a substation trip and loss of supply to several customers.

Alternate Source

Fig. 15: One-Line Diagram of Relay Applied as a Transformer Differential Relay and Lockout Relay Together. Discrete lockout and auxiliary relays are widely used in protection systems. Why not use a discrete lockout relay here instead of building these functions inside the microprocessor-based relay? The decision to do this was driven by several factors. One factor was reduced cost—fewer relays and less panel space and wiring. In addition, periodic maintenance testing was reduced by having fewer devices and by extending the maintenance intervals due to the inherent self-monitoring capability of the microprocessor-based relay versus the electromechanical lockout relay. Additionally, some system events have also led engineers away from using discrete auxiliary and lockout relays. One infamous event that is often cited for this change in design was initiated by a failed auxiliary relay at Westwing substation.10 The internal relay lockout logic for Case Study 2 is shown in Fig. 16. External Trip

LT1 S R

Q

LT2 87T Trip

S R

Q

86 (Lockout)

LT3 63 Trip

S R

Manual Reset

Q

89b (Line Switch Open)

0.5 0.5 Debounce Timer

Fig. 16: Internal Lockout Logic. The “latch” functions (LT1, LT2, and LT3) are all retained in nonvolatile memory. That is, even if the relay loses control power, it retains the status of the latch functions. In this case, an actual internal transformer fault occurred. The transformer protection

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(87T) and internal lockout function (86LO) operated to clear the fault. Dispatchers were able to switch load to an alternate source. All operations were correct up to this point. The timeline in Fig. 17: Event Timeline Shows 86LO Trips for DC Off and On. shows the sequence.

S R

S

Dispatchers Close Breaker T DC Off

Q

LT2 87T Trip

R

Initial Fault and Trip

Relay Enabled

LT1

External Trip

86 (Lockout)

Q

LT3 63 Trip

DC On

87T Trip LT2 (Latch) 89b Asserted (When Line Switch Open) 86LO DC Supply

S R

86 Lockout Reset Pushbutton 89b (Line Switch Open)

On power down, the relay stayed enabled for several cycles after the point at which logical inputs deasserted. Thus, the 89b input was sensed as deasserted (line switch closed) before the relay was disabled, producing the 86 lockout. On power up, the relay enabled before the 89b input was sensed, thus producing the 86 lockout again. The first and most obvious lesson learned in this case study is that, as technology changes, engineers and operators must strictly adhere to updated operating procedures for resetting lockout functions. Well-understood interfaces, such as physical lockout relays, are being mimicked or replaced, and it is important to document and train field personnel. Another lesson learned is to test the impact of cycling dc power off and on. Protection systems should be robust, relays and I/O modules might reboot, and operators may cycle power to relays when looking for dc grounds or performing other troubleshooting. In this case, designers did not consider how a loss of dc supply or relay power cycle would affect the programmable logic processing order during a power-down or power-up sequence. The user has since added logic so that the lockout function is supervised by a healthy relay (Relay Enabled). In addition, the line switch status is now supervised by a dropout delay that is longer than the relay power-down enable time (see Fig. 18: Modified Lockout Function Logic.).

12

0 Debounce Timer

86 Lockout Reset Pushbutton

When the maintenance crew arrived at the station, the correct procedure was to reset the lockout using a pushbutton on the relay. Instead, as stated earlier, the dc supply was switched off and on. The 86LO function asserted incorrectly when dc was switched off and asserted incorrectly again when dc was switched on.

0

0

Relay Enabled

Fig. 17: Event Timeline Shows 86LO Trips for DC Off and On.

Q

Dropout Delay

Fig. 18: Modified Lockout Function Logic.

Case Study 3: Direct Transfer Trip Due to a Noisy Channel Fig. 19: One-Line Diagram of a 138 kV Transmission Line. shows the protection one-line diagram for a 138 kV system with two-ended transmission. The line is protected by distance and directional elements in a permissive overreaching transfer trip (POTT) scheme, along with a direct transfer trip (DTT) scheme if either end trips. T M2

M1

POTT and DTT A

21/67

Relay-to-Relay Digital Communications Link Multiplexer

Multiplexer

21/67

Network

Fig. 19: One-Line Diagram of a 138 kV Transmission Line. In this case, the communications channel is a multiplexed digital network. The channel was abnormally noisy, with about 10 channel dropouts per minute and an overall channel unavailability around 0.5 percent. One of the noise bursts and associated channel dropouts resulted in a momentary assertion of the DTT input (see Fig.  20: Channel Noise Results in a Momentary DTT Assertion.). Note that the protection system also experienced an unrelated breaker failure. Significant efforts are made to secure protective relays that use channels; these efforts include data integrity checks, debounce de-

47

Circuit Breakers Vol.1 lays, disturbance detectors, watchdog counters, and more. In this case, even with a 50 percent bit error rate, the probability of a bad message getting through the relay data integrity checks was one in 49 million. 11 Although the probability was low, it was not zero, and if enough bad messages were sent, it was still possible for one to get through the integrity check, as in this case.

In Fig. 21: 87L Produced Undesired Trip Due to Communications Failure With Disturbance Detection Not Enabled., we can observe the channel status (ROKX) chattering—it should be solidly asserted. Eventually, bad data, in this case erroneous remote terminal current (IBX), made it through data integrity checks and caused an undesired 87L operation. Disturbance detection was not enabled.

In this example, we see how monitoring a noisy channel may provide a leading indicator for detecting problems. Also, regardless of media and integrity checks, it is prudent to add security on schemes that use direct transfer tripping. In this case, requiring two consecutive messages (an 8‑millisecond delay) instead of one (a 4-millisecond delay) improved security by an additional 104 factor.

Important lessons were learned in this case study. Channel performance must be monitored, and alarms, reports, and other notifications of noise and channel dropouts must be acted on with urgency. In modern 87L relays, regardless of data integrity checks, disturbance detection should be applied to supervise tripping. If disturbance detection had been enabled in this case, the 87L element would have been secure and the undesired operation would have been avoided.

Case Study 5: Relay Trips During Power Cycle While Performing Commissioning An older microprocessor-based relay was being commissioned. During testing, the dc control power was cycled and the relay tripped by directional ground overcurrent. The problem was repeatable.

Communications Drop Out

DTT BFI

Fig. 20: Channel Noise Results in a Momentary DTT Assertion.

Case Study 4: Communications Channel Problem on 87L Another two-terminal transmission line was protected by an 87L scheme. In the event data shown in Fig.  21: 87L Produced Undesired Trip Due to Communications Failure With Disturbance Detection Not Enabled., the system experienced a degradation of one of the optical fiber transmitters used in the 87L scheme. This failing component injected continuous noise into the channel and its connected equipment.

The relay power supply produces two low-voltage rails from its nominal input voltage for use by various hardware components. A 5 V rail, in this case, was used by the analog-to-digital (A2D) converter, and a 3.3 V rail was used by the microcontroller (µP) and digital signal processor (DSP). Protective circuits reset components when their respective supply voltages drop below acceptable operating limits. Recall from a previous case study that, due to ride-through capacitance, the power supply stays active for several cycles after input power is removed. Fig. 22: DC Supply Voltage Ramp Down to 0 V After a Power Cycle at Time T1. provides a graphical representation of how the power supply rails decay at a certain ramp rate, rather than an instantaneous step change, after power is turned off at time T1. Supply Voltage Nominal

5.0 V 3.3 V

T1

�t

Time

Fig. 22: DC Supply Voltage Ramp Down to 0 V After a Power Cycle at Time T1.

Fig. 21: 87L Produced Undesired Trip Due to Communications Failure With Disturbance Detection Not Enabled.

The root cause for this case study was a hardware design that allowed the µP and the DSP to remain enabled for several milliseconds after A2D disabled. As A2D disabled, it sent erroneous data to the µP and the DSP, which appeared as a false 3I0 current pulse, which caused the trip.

48 Fortunately, this design issue was found during commissioning tests instead of much later when pulling relay dc power (with trips enabled) to find a dc ground. Important lessons were learned in this case study. Cycling control power, while replicating as accurately as possible in service conditions, is invaluable and as important as industry standard environmental tests. In this case, the criticality of the power-down sequence of components common to one piece of hardware was revealed. Consider that the North American Northeast Blackout of 2003 was aggravated by a lack of up‑to-date information from the supervisory control and data acquisition (SCADA) system. A remote terminal unit (RTU) was disabled after both redundant power supplies failed due to not meeting industry dielectric strength specifications. Independent testing (simple high-potential isolation testing) had not detected this product weakness. Self-test monitoring did not alert the operators that the RTU was dead. Fail-safe design practices, such as reporting full-scale or zero values for all data fields during loss of communications or for watchdog timer failures, were not in place. Redundant power supplies, installed to improve the availability of the system, did not overcome these larger handicaps.2, 12 These problems are not “hidden failures” just because we do not test or check for them. As the industry moves toward more complicated and interdependent Ethernet IEC 61850-9-2 systems, power cycling tests become even more critical. Such systems may employ a data acquisition and merging unit built by one manufacturer, a subscribing protective relay built by a second manufacturer, and an Ethernet network built by a third manufacturer. What if the data acquisition shuts down at 5 V and outputs erroneous data to the rest of the components that remain active for a few cycles more?

CONCLUSION Protection systems and the power industry have much in common with the aviation industry. Both are complex systems of coupled and interdependent subsystems that must work together successfully so that the overall system works. We must continue to understand root cause and that changes in one subsystem have an effect throughout other subsystems. DC control circuits and communications channels have always had complexity and problems to overcome. Our work instructions and procedures have always had to be carefully considered. However, as we transition to new technology platforms and design standards, special precautions must be taken to avoid the types of pitfalls discussed in this paper. When disrupting dc control circuits or communications channels, we must thoughtfully consider what parts of the protection system should be isolated from trip circuits. Isolate trip circuits before indiscriminately cycling power in relay panels when, for example, troubleshooting dc grounds. Analysis, design, and testing should be devoted to understanding

Circuit Breakers Vol.1 what happens when power is cycled on systems and subsystems, especially considering our increased dependence on interdevice communications and programmable logic. Critical communicated logic inputs should be supervised with device and communications link statuses. Logic should be forced to a secure state during communications interruptions. Status dropout delays should be included as a necessity for security margin. DTT signals should be supervised with debounce delays. Received analog values should be supervised with disturbance detectors. Include the ability to isolate trip circuits and devices, whether by physical test links or virtual links for communicated signals. Especially when implementing new technology platforms, strive to make the operator interface familiar and ensure that operating procedures are clear, documented, and proven. Test, test, test; avoid undesired operations by including power cycle and logic processing sequence checks in design and commissioning tests.

REFERENCES 1

K. Zimmerman and D. Costello, “A Practical Approach to Line Current Differential Testing,” proceedings of the 66th Annual Conference for Protective Relay Engineers, College Station, TX, April 2013. 1

E. O. Schweitzer, III, D. Whitehead, H. J. Altuve Ferrer, D. A. Tziouvaras, D. A. Costello, and D. Sánchez Escobedo, “Line Protection: Redundancy, Reliability, and Affordability,” proceedings of the 37th Annual Western Protective Relay Conference, Spokane, WA, October 2010. 2

North American Electric Reliability Corporation, State of Reliability 2014, May 2014. Available: http://www.nerc.com/pa/rapa/ pa/performance analysis dl/2014_sor_final.pdf.

3

D. Costello (ed.), “Reinventing the Relationship Between Operators and Regulators,” proceedings of the 41st Annual Western Protective Relay Conference, Spokane, WA, October 2014.

4

B. McMillan, J. Merlo, and R. Bauer, “Cause Analysis: Methods and Tools,” North American Electric Reliability Corporation, January 2014.

5

T. Lee and E. O. Schweitzer, III, “Measuring and Improving the Switching Capacity of Metallic Contacts,” proceedings of the 53rd Annual Conference for Protective Relay Engineers, College Station, TX, April 2000. 6

GE Multilin, HAA Auxiliary or Annunciator Instruction Leaflet. Available: https://www.GEindustrial.com/Multilin. 7

D. Costello, “Using SELogic® Control Equations to Replace a Sudden Pressure Auxiliary Relay,” SEL Application Guide (AG97-06), 1997. Available: https://www.selinc.com.

8

D. Costello, “Lessons Learned by Analyzing Event Reports From Relays,” proceedings of the 49th Annual Conference for Protective Relay Engineers, College Station, TX, April 1996.

Circuit Breakers Vol.1 9

North American Electric Reliability Corporation, “Transmission System Phase Backup Protection,” Reliability Guideline, June 2011. Available: http://www.nerc.com. 10

IEC  60834-1, Teleprotection Equipment of Power Systems – Performance and Testing – Part 1: Command Systems, 1999.

11

IEEE Power System Relaying Committee, Working Group I 19, “Redundancy Considerations for Protective Relaying Systems,” 2010. Available: http://www.pes-psrc.org. Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying. David Costello graduated from Texas A&M University in 1991 with a B.S. in Electrical Engineering. He worked as a system protection engineer at Central Power and Light and Central and Southwest Services in Texas and Oklahoma and served on the System Protection Task Force for ERCOT. In 1996, David joined Schweitzer Engineering Laboratories, Inc. as a field application engineer and later served as a regional service manager and senior application engineer. He presently holds the title of technical support director and works in Fair Oaks Ranch, Texas. David has authored more than 30 technical papers and 25 application guides and was honored to receive the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference. He is a senior member of IEEE, a registered professional engineer in Texas, and a member of the planning committees for the Conference for Protective Relay Engineers at Texas A&M University, the Modern Solutions Power Systems Conference, and the I-44 Relay Conference.

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Circuit Breakers Vol.1

CURB CIRCUIT BREAKER PERFORMANCE FEAR WITH TESTING NETA World, Spring 2013 Issue Roberts Neimanis, Robert Foster & Nils Wäcklén, Megger

Circuit breakers are not the life of the substation. In fact, they spend a lot of time quiet, unused, waiting in anticipation. There will come a moment, however, when that circuit breaker needs to perform flawlessly—and to do so instantly. If the circuit breaker does not work as expected, disturbances can cascade, and the results can be catastrophic. Technicians and substation managers can quell fears about circuit breaker performance through testing. Circuit breakers provide protection for equipment that is necessary to the infrastructure and expensive to replace. Keeping them maintained prevents outages which saves a utility customer and personnel headaches as well as money. Additionally, there is a true public service component in ensuring the reliable supply of power and preventing business downtime and customer dark time. Proper functioning of a breaker relies on a number of individual components which must be calibrated and tested at regular intervals. The trigger for maintenance intervals differs greatly between power utilities, but the intervals are often based on time since the last test, number of operations, or severity of fault-current operations. Environmental considerations such as humidity and temperature (whether the breaker is located in a desert or coastal region) also play into the maintenance scheme. One additional factor is that the testing plan should be based on related standards for high-voltage circuit breaker design and operation such as: ●● IEC 62271-SER, ed1.0, High-Voltage Switchgear and Controlgear. ●● ANSI/IEEE C37, various guides and standards for circuit breakers, switchgear, relays, substations, and fuses ●● IEC/TR 62063 Ed1.0b (1999), TC/SC 17A, High-voltage switchgear and controlgear—The use of electronic and associated technologies in auxiliary equipment of switchgear and controlgear Overall, an adequate testing scheme reveals the condition and potential performance quality of circuit breakers. This will help those in charge of circuit breakers to be confident that, when called upon to operate, the circuit breaker will not fail.

TESTING TIMING The general function of the circuit breaker is to close and open the circuit, to be able to remove faults, and connect or disconnect objects and parts of the electricity network. The majority of the switching operations of a circuit breaker are normal load operations. Breakers are complicated, mechanically sophisticated devices requiring periodic adjustments. Sometimes a technician can notice these needs with a visual overview, and the problem can be solved without testing. However, with most circuit breaker issues, testing will be required. When maintaining a circuit breaker, technicians should start with timing and motion measurements. In fact, if the technician only has time for a single measurement, that measurement should be timing. A note on timing: It is vital that circuit breakers open and close within the time the manufacturer has specified. Times that range longer than manufacturer’s specifications, especially during the process of switching short-circuit currents, lead to longer arcing time between contacts. That longer arcing time results in excessive wear (in the best case scenario) and can also cause an equipment emergency, namely the melting of contacts. If those contacts melt, that breaker will require service or replacement. However, contact melting is not the worst case scenario in these situations; a potential explosion is. Technicians should be aware that, without proper timing, the potential results are not just expensive, they can be explosive. Additionally, along with long opening and closing timing issues, correct synchronization is imperative, both between phases and, in case of more than one break per phase, between elements of the same phase. Sometimes those complicated interplays can reveal unique issues. For example, if the tripping time is normal during testing but the closing time is slower, there has been a change in the characteristics of the closing system, perhaps from poor lubrication. On breakers with multiple trip springs, one could be broken, resulting in less energy for tripping but a faster closing time. A slower tripping time due to that broken trip spring, paired with a faster closing time should tell a technician testing the circuit breaker that a broken trip spring could be one possibility. (See the Timing Table for more examples of timing issues and their effects.)

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Circuit Breakers Vol.1 TRIPPING TIME

CLOSING TIME

EFFECT/POTENTIAL CAUSE

NORMAL

SLOWER

Changes in closing system could indicate bad lubrication.

SLOWER

NORMAL

Changes in tripping system.

SLOWER

FASTER

Malfunction in tripping drive system could indicate broken trip spring.

SLOWER

SLOWER

Increased friction in the drive system could indicate corrosion or bad lubrication on external linkages.

The distance throughout which the breaker’s electric arc must be extinguished is usually called the arcing zone. (See Figure 2.)

Timing measurement tests should be performed at the time of installation as well as during the service life of the circuit breaker.

TESTING MOTION Motion measurements allow for assessment of contact travel during breaker operation, close and open speeds, contact stroke and penetration, damping dynamics, velocity, and acceleration at different stages. The measurement can be illustrated by Figure 1.

Fig. 2: Actual measurement during open operation showing time, travel and coil current Motion measurement tests should be performed as part of a regular maintenance routine.

FIRST-OUT TIMING Along with timing and motion measurements, a good and timeeffective way to check the condition of a circuit breaker is to document its behavior at the first open operation after it has been idle for long time. The measurement and connections to the circuit breaker are carried out while it is still in service, and all of the connections are made inside the control cabinet.

Fig. 1: Motion Diagram and Timing Graphs for Close-Open Operation A high-voltage breaker is designed to interrupt a maximum short-circuit current, and it is required to operate at a given speed in order to build up an adequate cooling stream of air, oil, or gas depending on the type of breaker. This stream quenches the electric arc sufficiently to interrupt the current at the next zero-crossover. It is important to interrupt the current in such a way that the arc will not restrike before the breaker contact has entered the damping zone. Speed is calculated between two points on the motion curve. The upper point is defined as a distance in length, degrees, or percentage of movement from the breaker’s closed position or the contact closure or contact separation point. The lower point is determined based on the upper point. It can either be a distance below the upper point or a time before the upper point. The time that elapses between these two points ranges from 10 to 20 milliseconds, which correspond to 1-2 zero crossovers.

The biggest benefit of using first trip is to test actual operating conditions. If the circuit breaker has not operated for years, first-trip testing will reveal if the circuit breaker is slower due to problems in the mechanism linkages or coil armatures caused by corrosion or dried grease. With traditional methods, the testing is carried out after the circuit breaker has been taken out of service and has been operated once or even twice. On a gang-operated breaker, a breaker with a common operating mechanism, one coil current is measured, while on an independent pole-operated breaker, three coil currents are measured. Analyzing the coil current signatures gives information about the condition of the circuit breaker. Auxiliary contact timing can also be measured. Opening times can be measured by monitoring the protection current transformer’s secondary current; however, the arcing time will then be included. If there is a parallel current path available, the opening times can be more accurately determined since the arcing is minimized. A more advanced approach to first-trip testing is to additionally measure vibration. This addition provides detailed information of the status of the circuit breaker. Extra caution must be taken since there are live circuits in the control cabinet and the mechanism is fully charged. The breaker can operate at any time a fault condition occurs.

52 TESTING VACUUM BREAKERS When testing circuit breakers, one area that may be routinely overlooked deals with the details within the growing number of medium-voltage vacuum breakers. While the long life and durability of these circuit breakers make them valuable to utilities, small cracks in the interrupter enclosure may be difficult to spot. Vacuum breakers are used in circuits with voltage up to 70 kV. Because there is no gas to ionize to form the arc, the insulating gap is smaller than in other types of circuit breakers. An arc does form from the vaporized contact material. The insulation distance in a vacuum breaker is about 11-17 millimeters between plates. Normally there is one break per phase, but there can be two interrupters in series. The contact plates are formed to conduct the current in a way that creates a magnetic field that causes the arc to rotate and extinguish. The benefits with a rotating arc include uniform heat distribution and even erosion of the contacts. Other advantages with vacuum breakers are their relatively long operational life time and their relatively limited impact on the environment since they are designed without poisonous gases and relatively few components. Vacuum circuit breakers also suffer less wear on the main contact than air and oil circuit breakers. Vacuum breakers are based on high breakdown strength of vacuum. There are not many particles to be moved in the vacuum. However, if the vacuum seal is broken and air enters, a problem with the interrupter chamber can be expected since the breakdown of air is much lower than vacuum. The vacuum bottles on a breaker are usually tested with high ac or dc voltage at least 2.5 times higher than nominal. The electrical resistance of the vacuum in a breaker is identical in behavior for ac and dc voltage. The main difference is that ac is additionally sensitive to the capacitance of the breaker. The dc (resistive) current component is 100 to 1000 times lower in magnitude than the ac (capacitive) current component, depending on the individual bottle capacitance. It is, therefore, difficult to distinguish the resistive leakage current when testing using ac. As a result of the higher capacitive current, ac requires much heavier equipment for testing compared to dc test instruments. (Refer to standards ANSI/ IEEE 37.20.2-1987, IEC 60604 or ANSI C37.06.) Regular circuit breaker maintenance depends on many variables like voltage level, type, age, significance of breaker in the network, and the owner’s view on maintenance. This article has discussed three of the most valuable tests, namely timing, motion, and first-out testing of circuit breakers. There are many more variables involved in testing and many more testing options to evaluate the condition of circuit breakers such as power-factor, contact resistance, and insulation resistance. Nevertheless, the one test that should always be performed is main contact timing. Timing should be the beginning of all maintenance testing programs.

Circuit Breakers Vol.1 Roberts Neiman is an applications engineer with Megger’s Täby, Sweden office. Robert Foster is an Applications Engineer with Megger, specializing in high voltage circuit breaker and transformer testing. He graduated from California State University, Chico with a Bachelors of Science in Physics and Mechatronic Engineering. After graduation he worked as a Field Service Engineer for ABB in the high voltage dead tank circuit breaker division. He is involved with customers and product development supporting products and applications throughout North America. Nils Wäcklén is the TM1700 circuit breaker analyzer product manager with Megger’s Täby, Sweden office.

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DETERMINING CIRCUIT BREAKER HEALTH USING VIBRATION ANALYSIS PowerTest 2014 John Cadick, Cadick Corporation and Finley Ledbetter, Group CBS Inc.

INTRODUCTION All objects can be characterized by their response to physical stimuli. When struck by its clapper, a bell will ring with a certain fundamental frequency and numerous overtones (harmonics). The frequencies of the fundamental and the overtones are determined by the size and geometry of the bell as well as the material from which it is made. Imperfections such as cracks will cause the bell to respond at different frequencies and/or different amplitudes. If the normal frequencies and amplitudes are known, it is theoretically possible to determine the type, size, and location of an imperfection. These basic physical facts have led to the well proven scientific method of vibration analysis (VA), which is used extensively for determining existing or impending problems in rotating equipment such as motors or generators. Past attempts to use VA for circuit breakers have met with only limited acceptance, primarily because of the size and complexity of the test equipment, added expense, and the lack of good vibration signatures for comparison purposes. This paper discusses a new VA method that is being used successfully for determining the mechanical condition (and thus the electrical performance) of circuit breakers. Using a marriage of compact and modern communications equipment, internet data transfer, and sophisticated condition based maintenance algorithms (CBMA) offers a number of valuable features such as: ●● ●● ●● ●●

Extreme portability Easy transmission of data to a central location Capture of first trip data[1] A basic comparison method of analysis based on a vibration envelope and/or a detailed mathematical analysis of results ●● Ability to perform testing during routine switching ●● Reduces the risk of human error (and thus provides additional safety) since it requires no modification or removal of the circuit breaker. Field tests on circuit breakers have long provided diagnostic and prognostic data for the electrical components. Since the majority of circuit breaker failures are mechanical in nature, this new method helps to fill the toolbox of test methods available to field technicians. For the remainder of this paper, this new method of vibration analysis will be referred to as CBVA. This acronym is a simple four-letter contraction of Circuit Breaker Vibration Analyzer or Circuit Breaker Vibration Analysis.

WHAT ADVANTAGES DOES THIS NEW TEST TOOL OFFER? The CBVA provides a holistic, single-signature graph in three dimensions. The graph can be analyzed for quantitative information concerning the breaker operation and condition. The following points illustrate why the CBVA can be an important addition to the existing suite of circuit breaker test procedures.

FIRST TRIP DATA Consider the following facts: ●● Circuit breakers are mechanical devices and depend upon correct lubrication to operate correctly. ●● Many circuit breakers stay in service with no operations for years or even tens of years. ●● NFPA 70E-2012 Article 210.5 requires that, “protective devices shall be properly maintained to adequately withstand and interrupt available fault current.” An information note immediately below Article 210.5 states that, “failure to properly maintain protective devices can have an adverse effect on the arc flash hazard analysis incident energy values.” The three facts taken together define the importance of a breaker’s first trip operation because studies performed during the last fifty years have shown that fully 50 percent of unmaintained circuit breakers will fail to operate correctly after being in service for a period of five years or longer. An excellent paper by Neitzel and Neeson provides background on this.1 In the past, the first thing that was done when preparing to perform maintenance on a circuit breaker was to open the breaker and then start the maintenance, thus losing any information about the initial trip. With this new technique, the trip information can be captured when the breaker is first opened providing invaluable information as to the efficacy of the ongoing maintenance plan.

SIMPLE SPOT CHECK TESTING One of the complicating factors of maintenance efforts is the need to have a shutdown before any maintenance can be performed. CBVA allows a quick vibration check during routine switching operations; furthermore, since the test involves simply attaching the test device and operating the breaker, maintenance personnel can be easily trained to perform the test quickly and safely.

54 OVERALL MECHANICAL CONDITION Time-travel analyses (TTA) in conjunction with thorough visual-mechanical inspections (VMI) provide a wealth of information as to the mechanical condition of the breaker. A good vibration analysis of the circuit breaker will provide most of the information that the TTA and VMI yield together. This is not to say that equipment owners and service providers should stop TTA or VMI in favor of performing vibration analysis. Any good maintenance and testing regimen should include all three because CBVA can be performed multiple times between normal maintenance cycles at little or no additional cost. Using all three provides a much more comprehensive picture of a breaker’s mechanical condition.

Circuit Breakers Vol.1 If the object has a large damping factor, the oscillations will taper off very quickly. The damping factor for any object is a function of its mass and geometry as well as the material of which it is made. Thus if the geometry of the object changes or if the object is changed or damaged in some way, its damping factor will change consequently changing the frequency and waveform of the vibrations. A simple object, such as a tuning fork, will have very pure vibration signature. That is, the oscillations will have few overtones, and the waveform will tend to be more sinusoidal. This is why the sound that a vibrating tuning fork makes sounds so pure. A more complex object with many different parts will tend to have a very complex vibration pattern. As a result, when the object is stressed, each individual part will contribute to the overall vibration waveform.

BREAKER TIMING

CIRCUIT BREAKER VIBRATION

During operation the vibration signature peaks at the moment of trip, the moment of spring charging, and the moment of close. As will be shown later in the paper, a careful analysis of the signature can be used to determine trip time and close time. The CBVA trip time signature displays the vibration events from mechanism motion and mechanism stop. Thus it captures the entire time, not just the time that the contacts open or close.

A circuit breaker is a very complex mechanical mechanism. It has a huge variety of parts including springs, lever arms, sheet metal, pivots, rubber stops, contacts, and many other such items. This means that the vibration signature of a circuit breaker will be very complex. Figure 1 shows such a vibration signature.

SAFETY Safety is enhanced in at least two ways: ●● By using remote operating mechanisms, the test can be performed when the technician is well outside the arc-flash boundary. ●● When a breaker is being racked, there is a much higher probably of failure than when it is just sitting. This new test does not require that the breaker be racked.

WHY DO CIRCUIT BREAKERS VIBRATE? Fundamentals of vibration When any real object is subjected to physical stress, the object will tend to deform. If the stress is great enough, the object’s deformation may be partially or totally permanent. Consider the dent in your fender when that post jumped out and struck it. The stress (force) of the impact was so great that it permanently deformed the fender. If the force of the impact is small enough, the fender will deform, but then it will spring back into shape leaving little or no permanent damage. This is because virtually all materials have some degree of elasticity. As long as the deformation does not cross the threshold of elasticity, the material will spring back into shape. All physical objects in motion have the property of inertia.[3] So after the object springs back into shape, it tends to go past the undeformed state to another deformed position. The object will do this several times until the back-and-forth oscillations are reduced to zero by the natural damping effect. This leaves the object in its original shape.

Fig. 1: Three-axis vibration signature for a circuit breaker (Courtesy of Group CBS Inc.) There are three different waveforms – one each for the x-, y-, and z-axes. Note that the trace on each of the axes is similar but not identical to the others. This is because the breaker will not vibrate exactly the same in each of the three directions. The Z-axis is displaced by one G from the other two. This is because the G-axis is the vertical axis and is always subjected to the force of gravity – 9.8 m/sec2 (32.2 ft/sec2). The other two axes are horizontal; therefore, gravity has little effect on them. Considering just one of the traces, notice that there are three major segments. The first segment is the vibration signature created when the breaker trips, the second segment shows the vibration created when the charging mechanism resets the closing springs, and the third segment shows the vibration created when the breaker is reclosed. The decreasing magnitude of the vibration in each segment is caused by the damping factor of the entire breaker mechanism.

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Circuit Breakers Vol.1 Any damage to the components, loose hardware, or failure of lubrication will cause the vibration signature to change. Given that this signature is a known good profile (KGP), any subsequent changes will show up as changes in the signature. With more research and experience, analysis techniques will be able to identify the causes of those small changes.

One of the key pieces of information shown by the motion curve is found in its smoothness. There are no large jumps in the curve as the mechanism moves. This indicates that there is no binding anywhere in its travel.

Parameters

Figure 4 shows a drawing of another type of circuit breaker motion curve. In this example the breaker is first closed and then tripped. Note that at the end of the close cycle, the mechanism overtravels slightly. This is normal operation unless the overtravel exceeds a manufacturer’s specification or it differs significantly from the average of previous tests.

There are at least four different parameters that are used in analyzing the performance of a circuit breaker – vibration, travel distance (also called displacement or amplitude), travel velocity, and travel acceleration.

The same phenomenon is seen in the trip motion curve. Note that there is some oscillation at the end of the trip stroke. This is also normal. Some overtravel on trip creates less stress on the operating mechanism.

CAPTURING MOTION AND VIBRATION IN CIRCUIT BREAKER TESTING

●● Travel distance (Displacement)

Fig. 2: Time-travel curve for a circuit breaker (Courtesy of Megger, Inc. www.megger.com)

Fig. 4: A close and trip motion curve (Courtesy of Megger, Inc. www.megger.com) ●● Travel velocity The slope is relatively constant in the sections between the points labeled Speed calculation points. This means that the velocity remains constant between those points. The speed of the close or open operation can be calculated by taking the difference between the positions and dividing it by the time between those two positions. This velocity information is compared to a manufacturer’s specification and/or the average of previous tests. Any deviation could indicate some sort of problem, such as weakened springs or friction. ●● Travel acceleration

Fig. 3: A modern circuit breaker time-travel test set (Courtesy of Megger, Inc. www.megger.com) Figure 2 shows a time-travel curve taken for a breaker captured by the type of time-travel analyzer shown in Figure 3. The motion curve is taken by a transducer and fed into the test set. The test set plots the position of the contacts as the breaker moves from closed to open.

The slopes of the curves in Figure 2 and Figure 4 change throughout the operating cycle. Since a change of slope indicates a change in velocity, these parts of the curve represent acceleration or deceleration. Changes in slope are expected; however, if the change occurs in a part of the curve where there should be no change, a problem is indicated. ●● Vibration The final parameter, and the main one of interest for this paper, is vibration. Figure 1 shows a vibration signature taken with the

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CBVA. The vibration analysis creates a signature that is a comprehensive view of the condition of the entire breaker. As Figure 5 shows, it can even be used to calculate contact parting (or closing) time by observing the distance between the first two major vibration excursions.

Since the mass5 and the applied acceleration are known, Newton’s second law can be used to determine the force:

Since the two forces are equal we can write

Solving for a gives

Since k and x are known, we can calculate the applied acceleration.

Fig. 5: CBVA tripping and charging signature compared to time-travel data (Courtesy of Group CBS, Inc.)

THE ACCELEROMETER

Accelerometers used in modern, more sophisticated equipment are built on a silicon chip just like any integrated circuit. They do not use weights and springs; rather, they rely on sophisticated techniques that are beyond the scope of this article. Furthermore they may be sensitive to motion in 1, 2, or 3 directions. The acceleration is usually calculated using a small onboard microprocessor and printed out graphically as shown in Figures 1 and 5.

The new approach Since the performance of vibration analysis depends on an accelerometer, the question is: Where can I find an accelerometer?

Fig. 6: A simple accelerometer Figure 6 shows a diagram of a simple accelerometer. When the system is stationary, as shown in 6(a), the spring is in its relaxed position. When the system accelerates to the left, 6(b), the inertia of the mass tends to hold it in place. This means that the spring will stretch. How far it will stretch is dependent on the mass of the weight (m), the spring constant (k), and the acceleration (a). To analyze this, we start with Hookes law which states:

Where: F is the force applied to the spring, k is spring constant, and x is the distance the spring stretches.

Fig. 7: The iDevice, an accelerometer in your pocket (Courtesy of Group CBS Inc.)

The Device As it turns out, millions of people throughout the world are carrying an accelerometer in their pocket (Figure 7) – the ubiquitous iDevice.6,7 Did you ever wonder how an iDevice knows whether you are holding it horizontally or vertically or how the service tech knows if you have dropped it when you take it in for service? It has a builtin, three-axis accelerometer. Any force applied to a mass causes the mass to accelerate. The force of gravity is no exception. The internal accelerometer in an iDevice is acted on by the force of gravity. If the iDevice is held vertically, the accelerometer senses

Circuit Breakers Vol.1 the pull of gravity and orients the screen so it is displayed in portrait mode. If the iDevice is held horizontally, the accelerometer and its attendant software rotate the screen to a landscape view. Other software applications use the accelerometer for other purposes. Many game apps ask the user to shake the device as an input response. Does software exist to use the iDevice as a CBVA device? There’s an app for that!

57 and orientation of the iDevice is very important. First, since the circuit breaker is a complex assembly, the vibration signature will be different depending on where the iDevice is placed. Therefore, it must be located in approximately the same location for the initial and all subsequent tests. The app asks the user to identify the breaker type that is being tested. It then allows the user to bring up a photograph showing the recommended location of iDevice placement.

As you might expect, the use of an iDevice for a circuit breaker test device has involved a substantial amount of research and development – including development of an iDevice app named the CBAnalyzer.©™ 8

Fig. 8: Screen shots of CBAnalyzer (Courtesy of Group CBS, Inc.) Figure 8 is a montage of screen captures from CBAnalyzer. Starting from the upper left and moving counterclockwise the shots show: ●● The screen that appears showing a countdown timer. When it reaches 0, the user initiates breaker operation. ●● The initial main menu that appears after the user has logged in. ●● A screen that allows the user to tell the app whether the breaker is closed or open before the test is initiated. ●● The screen that appears after the test cycle is completed. It shows the total elapsed time for the test. The app is designed to take the user with little or no breaker service experience step-by-step through the entire process. Inexperienced maintenance personnel and highly experienced technicians alike will find the app very user friendly.

Application of the Test Device The iDevice is attached to the circuit breaker magnetically using a special case designed for the purpose. Figure 9 shows the iDevice incorrectly applied (9a) and correctly applied (9b). The location

Fig. 9: The iDevice attached to a DS-206 circuit breaker (Courtesy of Group CBS, Inc.) Second, the iDevice must be level and oriented in the same manner every time. Research has shown that attaching it horizontally provides excellent results. It must also be attached in such a way that the navigation button of the iDevice is placed to the right for all tests. This keeps the X-, Y-, and Z-axes in the same orientation for each test. In figure 9a you see that the iDevice is not level. Notice the two level lines in the upper left area of that screen. To be sure that the iDevice is leveled, the technician adjusts it until the level lines are over the crosshairs as shown in 9b.

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CAPTURING THE VA SIGNATURE Actually performing the test is quite straightforward. 1. Position and orient the phone as previously described. 2. When the Start button turns blue, press it and a countdown from 10 begins. 3. When the countdown reaches 0, the iDevice goes into Record mode and waits for the first vibration to occur. 4. The tester initiates whatever test is being performed (trip, charge, close, or any combination by actually operating the breaker). 5. The iDevice senses the start of the test and begins recording the vibration signature. 6. After the test is finished, the tester presses the Stop button. The data is saved and sent to a database which analyzes the results. Note that if the tester is distracted and forgets to stop the test, the app will stop taking data after a short time period.

THE SIGNATURE DATA Figure 1 and Figure 5 show the basic structure of two types of tests. The data itself is captured digitally by the app. Figure 10 shows a partial data list. The left column shows the time of the data capture after the event started. The next three columns list the acceleration of X-, Y-, and Z-axes respectively. Note that the acceleration data is given in terms of g, minus the acceleration due to gravity.

Fig. 10: Partial data capture list (Courtesy of Group CBS, Inc.) After the data table is stored in the test device, it is sent as a CSV file to an online website which receives it, interprets it, and graphs it using Microsoft EXCEL.® 9 If there is no internet service, the data will be cached and sent to the CBVA website when the iDevice comes in contact with a suitable network.

ANALYZING THE SIGNATURE Visual inspection An experienced analyst can capture some information by simple inspection and comparison of current vibration signature graph versus a KGP. Such an inspection can identify obvious problems such as those caused by a major mechanical problem. However research shows that a more sophisticated method will provide a wealth of information. The visual inspection can be made by using the additional data or the trace showing an envelope (Figure 11).

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Circuit Breakers Vol.1 ●● Provides quantitative data that can be analyzed, thus pinpointing problems.

●● Although no pricing structure has even been investigated at the time of the writing, the cost of the test set itself (an iDevice or iPod Touch) is extremely low by the standards of other test equipment. ●● Easy first trip data collection. ●● Since this is a noninvasive test, the chance of accidental damage to the breaker during maintenance is reduced.

Fig. 11: A vibration signature showing the calculated envelope (Courtesy of Group CBS, Inc.) During the breaker operation, data can be sampled by the iDevice (or other data acquisition devices) at rates from 100 Hz to 400 Hz depending on which version of the device is being used. Even the lowest rate is suitable for the purposes of CBVA. To create the envelope curve, the peaks of the signature curve are captured and connected by a straight line.

Pattern recognition Pattern recognition software (PRS) is employed feeding the raw data file to the CBAnalyzer. The PRS captures the peaks and valleys of the data and compares it to a KGP. The PRS will identify differences from the KGP to such fine detail that a problem can even be traced to a worn or missing tooth in a gear, bad or failing lubrication, or even misalignment of mechanism parts.

CBMA The PRS discussed above works well for many existing problems. Research is currently underway to use very powerful CBMAs to provide predictive information. While this particular research is in its infancy, the algorithms being used are proven in other applications, and it is expected that very good predictions will be possible.

SUMMARY AND CONCLUSION Research has been underway on this new method for several years. Recent breakthroughs have allowed the project to progress into the development stage. At the time of this writing (late September 2012) the beta release of the app is deployed. Several test sites are starting to use the app, with preliminary results being excellent. The existing circuit breaker tests such as time-travel analysis yield excellent data. The cost and ease of implementation of this new approach to vibration analysis makes it very attractive to add to the arsenal of test tools. The CBVA approach using the iDevice offers the following: ●● Simplicity in application. ●● Easily implemented during routine switching operations yielding easy spot checks.

●● Web-based analysis tools allow an almost instantaneous condition report. ●● Test results can also be used to time the open and close of the breaker contacts. ●● Data is stored for easy retrieval and future comparison against subsequent tests. ●● Added safety since the test can be accomplished with the tester(s) located a safe distance away using remote switching devices. ●● Easily established baseline data when breaker is first commissioned. ●● Allows scanning of breakers quickly, and then the reconditioning or heavy maintenance focus can be on only the breakers with anomalies in their CBVA test results. ●● It is expected that this test method will be welcomed by insurance providers because of the ease of implementation and the quality of the results. ●● Results can be qualitatively analyzed by visual inspection of the signature graphs or quantitatively analyzed using pattern recognition software and/or CBMA. By the time this paper appears in print a great deal of empirical data will have been gathered in the field. The authors believe that this new method will be of great value to the testing industry. The conclusion – a simple new device for efficiently determining circuit breaker condition using CBVA has been developed to allow maintenance personnel the ability to focus attention on the breakers that need it the most. The advantages for incorporating this new instrument into existing maintenance testing programs promises to be of great benefit.

ENDNOTE [1]

First trip is defined as the first time a circuit breaker opens after an extended time in service. The quality or state of being flexible : flexibility, bendability, ductility, elasticity, flexibleness, give, limberness, malleability, plasticity, pliancy, resilience, suppleness. – Excerpted from American Heritage Talking Dictionary, Copyright © 1997 The Learning Company, Inc. All Rights Reserved. [2]

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The tendency of an object to stay in motion unless it is acted on by an external force. [3]

The action of a substance or of an element in a mechanical or electrical device that gradually reduces the degree of oscillation, vibration, or signal intensity, or prevents it from increasing. [4]

Here we are assuming that the mass of the spring and all other components are negligible compared to the weight’s mass. [5]

Throughout this paper the term iDevice shall mean iPhone®, iPad®, or iPod Touch®. All three are registered trademarks of Apple, Inc. [6]

Although all three iDevices can be used, size and weight make the iPhone or the iPod Touch the obvious choices. [7]

CBAnalyzer.©™ is Copyrighted and Trade Marked by CBS ArcSafe.

[8]

[9]

EXCEL is a registered trademark of Microsoft.

REFERENCES 1

 ennis Neitzel and Dan Neeson, “Preventive Maintenance and D Reliability of Low-Voltage Overcurrent Protective Devices,” Pulp and Paper Industry Technical Conference, 2007, Conference Record: 164-169.

John Cadick is a registered professional engineer and the founder and president of the Cadick Corporation. He has specialized for over four decades in electrical engineering, maintenance, training, and management. Prior to creating the Cadick Corporation, he held a number of technical and managerial positions with electric utilities, electrical testing companies, and consulting firms. In addition to his consultation work in the electrical power industry, Mr. Cadick is the author of Cables and Wiring, DC Testing, AC Testing, and Semiconductors published by Delmar. He is also principal author of The Electrical Safety Handbook (published by McGraw Hill) and numerous professional articles and technical papers. Mr. Cadick has a BSEE from Rose-Hulman Institute of Technology and an MSE from Purdue University. Finley Ledbetter, Group CBS, Inc. has worked in the field of power engineering for 30 years, including serving as an applications engineer and instructor for Multi-Amp. He was the founder of Shermco Engineering Services and Western Electrical Services, both NETA-accredited companies. Mr. Ledbetter is also the cofounder of Group CBS, Inc., which owns 12 circuit breaker service shops in the United States. He is a member of IEEE, a NETA Affiliate, and a charter member and past president of Professional Electrical Apparatus Recycler’s League (PEARL).

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DO YOU KNOW THE TRUE CONDITION OF YOUR CIRCUIT BREAKER? NETA World, Spring 2013 Issue Michael Skelton, Camlin Power

BACKGROUND One of the most critical devices on any electricity network is the circuit breaker which can be described as the silent sentinel, standing guard over the network and only being called into action when a fault occurs. The circuit breaker needs to operate within its composite tripping time (relay trip time + circuit breaker main contact opening time) to ensure correct discrimination with upstream circuit breakers and, therefore, minimize the number of customers disconnected during a fault operation. A slow tripping circuit breaker will not only result in unnecessary disruptions to electricity supplies, but maintaining high fault currents for extended durations can stress the network and cause damage to plant and equipment. Traditional diagnostic testing procedures usually require the circuit breaker to be isolated and removed from service; therefore, not only has the opportunity to detect the cause of the defect been missed, but also the tests do not focus on the condition of the operating mechanism apart from overall speed of operation.

CONVENTIONAL CIRCUIT BREAKER TESTING – WHAT ARE YOU MISSING? Conventional testing usually requires removing the circuit breaker from service. However, isolating the circuit breaker is time consuming, as it requires a planned outage involving switching instructions and safety documents, and will often involve several engineers or technicians on site. This process results in vital information relating to the first trip not being captured, and often the problem that caused a slow trip in a circuit breaker is temporarily cleared during this first trip operation. When a slow trip operation occurs, the focus tends to be on timing tests to determine if the problem lies within the protection relay or the circuit breaker operating mechanism. Rarely are the problems due to slow operation of the protection relay especially if they are the electronic or microprocessor type. Occasionally problems occur with the older electromechanical type relays due to friction in the moving parts such as the induction disc. However, this is usually revealed during secondary injection tests of the relays. Timing of the circuit breaker main contacts from initiation of a trip to main contact opening merely indicates the circuit breaker is operating within its design specification. Therefore, the initial tests are inconclusive, so the focus then turns to inspecting the main operating mechanism and lubricating the numerous

mechanical components. In some cases this further compounds the problem if the wrong type of lubricant is used, especially with the advent of spray penetrants which could be liberally applied. This causes an organic chemical reaction between the solvent and propellant (within the penetrant) and the soap (within the grease), resulting in varnish which causes the mechanism to stick. Instead of fixing the problem that causes the slow trip, the effort in testing and maintaining the circuit breaker is largely counterproductive.

DIAGNOSTIC TESTING FOR SLOW TRIPPING CIRCUIT BREAKERS The failure of conventional timing tests to diagnose the causes of slow tripping circuit breakers led to the search for a technique that would pinpoint the cause during the critical first trip. Although timing tests can confirm that a circuit breaker’s overall operation is within set limits, it was discovered that monitoring the current flowing through the trip coil provides a very powerful methodology for analysing the readiness of a circuit breaker to trip. Trip coil profiling was developed as a condition monitoring technique where deviation from a standard profile could help to pinpoint a potential problem within either the trip coil or circuit breaker’s main operating mechanism.

ANALYSIS OF A TRIP COIL PROFILE The trip coil has an electric and magnetic circuit due to the action of a plunger moving within an energized coil. This electromagnetic circuit has reluctance in the magnetic part as well as inductance and resistance in the electrical part. Normally, in most electrical circuits, we can think of the inductance as being fixed. However, in the trip coil, as the plunger moves the reluctance of the magnetic circuit is reducing which means the inductance in the electric circuit is increasing. The applied voltage, which is a constant (apart from a small voltage drop), is proportional to the rates of change of both current and inductance. So, as the rate of change of inductance goes up the rate of change of current must go down, and vice versa. Hence an instantaneous drop in the rate of rise of the inductance, due to the plunger striking the latch or the end-stop, will cause an instantaneous rise in the rate of change of current. Diagram 1 shows a typical trip coil profile with its distinct shape where each stage of the trip coil mechanism can be identified through its operation and problems identified if the profile deviates from a signature trace

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Circuit Breakers Vol.1 TRIP COIL PROFILE ANALYSIS Using First Trip Profiling to Minimize Arc-Flash Hazards Working close to live equipment when an arc flash occurs due to an electrical fault can result in serious injury unless adequate precautions are taken. These will include selection of the right personal protective equipment and working distances which require an arc-flash hazard analysis. A key parameter in determining the available energy from an arc flash is its duration which is directly related to the tripping time for the upstream protection device; therefore, it is vital to know that the circuit breaker will clear the fault within the specified time as a slow tripping circuit breaker will significantly increase the arc-flash energy. This is another example of where capturing the first trip and knowing how the circuit breaker will perform during fault conditions is absolutely critical.

Development of Portable Technology for Measuring Trip Coil Profiles

Diagram 1: Comparison of First and Second Trips Highlights Slow Operating Main Mechanism in Circuit Breaker. Table 1 provides examples of what will cause a deviation in any section of the profile curve. These examples are not exhaustive and can be simulated on a trip coil mechanism by varying the parameters that cause deviations, capturing the current profile and overlaying it on a signature profile. Each type of circuit breaker will have its own characteristic profile and therefore it is essential that this signature profile is acquired. Comparisons can then be made with profiles captured during on-site testing of the first trip operation and subsequent trip operation to identify potential defects.

Initially the monitoring of trip coil profiles required the hard wiring of equipment into the circuit breaker; however, this was cost prohibitive and could only be justified for circuit breakers located at extremely critical nodes on the network. The development of portable, light weight, hand-held devices with noninvasive connections to monitor the key current and voltage parameters has revolutionized the testing of circuit breakers. The process of testing a circuit breaker only takes a few minutes, enabling a condition assessment of the operating mechanism to be obtained during the first trip operation. As well as indicating the health of the circuit breaker’s trip and close coil mechanisms, other useful parameters are obtained which include : ●● measuring the main contact operating time ●● measuring the auxiliary contact operating time ●● checking the integrity of control circuit wiring

DESCRIPTION

REASON FOR DEVIATION FROM STANDARD

EXAMPLES

Zero to A

Problem with electrical characteristics of trip coil or supply voltage

•

Circuit Breaker fitted with incorrect trip coil (should operate at 85% nominal)

Restrictive forces impede travel of plunger/striker pin

•

Oil and greases providing a dashpot action

•

Insufficient lubricant

•

Misalignment of coil

•

Incorrect adjustment of latching mechanism

•

Inadequate lubrication

•

Misalignment of trip bar and striker pin guide

•

Guide wear causing striker pin to make partial contact

Energizing of Trip Coil

A-B-C Plunger and striker pin travel and contact is made with trip bar C-D Striker pin making contact with trip bar and overcoming inertia of latch D-E Plunger, striker pin, trip bar and latch move together. E represents point at which plunger strikes buffer

Increased resistance of trip bar/latch mechanism

The trip bar is restricted throughout its travel

Table 1: Causes for Deviation from Trip Coil Normal Profile

●● indicating problems with the dc supply. Furthermore, this information is immediately available for on-site analysis, and corrective maintenance can be targeted at a defect.

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Fig. 2: First Trip Testing of an SF6 Circuit Breake

Michael Skelton works for Camlin Power and is the Product Manager for the Profile P3 first trip circuit breaker analyzer. He previously worked in Northern Ireland Electricity (NIE) for 33 years and has extensive experience in design of rural protection schemes for the 11kV overhead network, low voltage cable fault location, testing and commissioning of distribution switchgear, high voltage network planning, and general operational experience on the 11 kV and low voltage distribution network.

Fig. 1: Portable First Trip Analyzer for On-Site Detection of Circuit Breaker Defects It is becoming increasingly important to make connections within the circuit breaker cubicle to ensure that the right circuits are being monitored. Some modern circuit breakers use capacitive charged power supplies, so it is important that the current probe which monitors the dc current to the trip coil is connected close to the trip coil. The advantage of a portable, hand-held device that can be used at any circuit breaker location can be considered as an invaluable addition to the maintenance technician’s toolkit.

In his role as Director of Network Operations for NIE, one of his key targets was to reduce customer minutes lost. He fully appreciates the importance of a correct circuit breaker operation during faults to minimize the number of customers disconnected.

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FIRST-TRIP TESTING NETA World, Spring 2013 Issue Kenneth Elkinson, Matthew Lawrence, Tony McGrail Doble Engineering Co.

It is common knowledge in the electrical power industry that outages are increasingly difficult to get. Systems and assets are being pushed closer to, and even beyond, their rated limits more now than ever before. When this is combined with cuts to the testing and maintenance budget, it becomes obvious that taking circuit breakers out of service to test them does not happen as often as it should. Circuit breakers, particularly higher-voltage, transmission circuit breakers, tend to sit in open or closed positions for long periods of time, often carrying load without any operations. This is generally considered good for customer satisfaction as it is an indication that no system faults have been seen on that circuit. The question is will that same breaker operate successfully, at expected speed, clearing the next unforeseen fault when called upon to do so? Ideally, when testing a circuit breaker, the off-line tests performed will measure travel, speed, and timing characteristics of the breaker. These tests are looking at the mechanical performance of the circuit breaker and are not focused on the dielectric integrity. First-trip testing can help the test technician determine if the circuit breaker mechanism is operating correctly by capturing the breaker’s mechanism operational characteristics and providing a graphical representation of how the circuit breaker performed in an as-found state since its last operation, no matter how long ago. From the data captured in the first-trip test, the following problems can be identified: ●● Mechanism lubrication deficiencies ●● Trip coil damage ●● Auxiliary contact problems (dirty, burned, etc.) ●● Loose connections in mechanism

of the acceptable tolerances. This can lead to severe problems including circuit breaker failure. Circuit breaker failure definition includes not correctly opening to clear a fault or closing to pick up load or even worse, insulation failure causing arcing and severe damage to the circuit breaker and possibly surrounding equipment.

Fig.1: Circuit Breaker Failure With this in mind, maintenance engineers are very interested in how a circuit breaker will operate if it has not been operated for a long period of time. First-trip testing is effective because it gives the engineer a glimpse of how the breaker operates in just this type of condition. Lubricated parts of the circuit breaker will typically have a greater friction on the first trip as compared to subsequent trips, so it is important to capture this information in an as-found condition rather than after the breaker has been switched out of service for maintenance.

●● Station battery and/or battery charger problems ●● Control cable sizing and contamination issue Circuit breakers, especially their mechanisms, are complex mechanical devices. As in all mechanical devices, any portion of the circuit breaker that is required to move needs to be exercised and correctly lubricated in order to be expected to operate in a dependable manner when called upon. When these movable parts do not move for long periods of time, the lubrication tends to dry out and gum up, which causes moving parts to stick. Circuit breakers are engineered to very tight tolerances with regards to distances that contacts should move and the speed with which they are to move. If any of these parts stick for any reason, it can cause the circuit breaker to function outside

Fig. 2: Trip Coil Current – first-trip test results in red; results after multiple operations in blue

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Circuit Breakers Vol.1 All of the normal test parameters are captured including trip and close coil currents, main current and auxiliary voltages, and power supply voltage. When performing the first-trip testing, these values may differ slightly from normal testing results but still need to be considered, as it is the closest test to actual in service conditions. The key is to establish a baseline and track the performance of the breaker. The knowledge can be applied to other breakers in the same family with similar mechanisms.

rent measurements, contact separation, auxiliary contact timing, and battery voltage. Documented case studies have diagnosed lubrication issues, plunger problems, and mechanical mechanism and linkage issues. As with all testing, first-trip testing is another tool in the maintenance engineer’s toolbox to help justify tough decisions that must be made quickly. Of course, first-trip testing may provide the engineer with results that are not clear, in which case additional testing of the breaker will be required, including the normal time and travel testing, power-factor testing, contactresistance testing, and dielectric quality.

REFERENCES J. Levi, “First-Trip Testing Using the TDR Test Instruments,” 77th Annual International Conference of Doble Clients, Boston, MA, 2010.

Fig. 3: Trip Coil Current – first-trip plunger stop in red; after multiple operations in blue Another valuable aspect of the first-trip test is that it is a very fast, simple test to perform. As previously mentioned, testing and maintenance resources are scarce and need to be optimized as much as possible. If the maintenance engineer performing the test can analyze the results on the spot, the results should provide guidance as to whether additional testing is required, whether additional maintenance is required, or if the breaker can go back in service as is. This, of course, would require having previous firsttrip testing results for comparison or expected results from similar type mechanisms on hand while the test is being performed. Increasingly, crews are being instructed to avoid intrusive maintenance on circuit breakers unless there is evidence it is necessary. First-trip testing can provide first-hand evidence that this type of maintenance is or is not necessary. The key here is the result of the test and having an understanding of what is being tested in the first place. Circuit breaker motion testing requires interpretation of the results, as what the results mean may not always be obvious. Adequate training and an understanding of the mechanical nature of circuit breakers are two key building blocks to analyzing the information the test is providing. Managing the results across a fleet of circuit breakers becomes the next consideration. Circuit breakers of similar make and model tend to have similar travel and timing test results. The value in these types of tests is fully realized when the results from a fleet of circuit breakers can be managed to allow for appropriate intervention, using today’s timing results to identify which breakers are still within specification, and predicting which look slower and which are already out of specification. This allows for planning of intervention and maximizing resources. Typically, first-trip testing will provide information about trip coil currents including opening time analysis, arcing contact cur-

Kenneth R. Elkinson, P.E., received his Bachelor of Science in Electrical Engineering degree from the University of Massachusetts at Lowell. Kenneth has held a number of positions at Doble Engineering, as Field Engineer, Client Service Engineer, and now Apparatus Analytics Engineer. Previously, Kenneth worked with National Grid in the US as a Substation Engineer. Mr. Elkinson is a licensed Professional Engineer in the state of Massachusetts. Matthew B. Lawrence is the Solutions Manager for SFRA and circuit breaker diagnostics at Doble Engineering, focusing on diagnostic testing solutions.  Before joining Doble in 2011, Matthew held positions in substation maintenance and operations and equipment maintenance engineering departments at National Grid and its New England based legacy companies. His most recent role was Manager of Substation O&M Services. Mr. Lawrence is a member of IEEE, Affiliate of the IEEE Transformer Committee, and a member and past chair of the Doble Engineering SFRA Users Group Committee. He holds an Associates of Science in Electronics Engineering from New England Institute of Technology and attended Worcester Polytechnic Institute School of Industrial Management.  He also holds an Electricians License in the State of Rhode Island. Tony McGrail is the Doble Engineering Solutions Director: Asset management and Monitoring Technology. His role includes providing condition, criticality, and risk analysis for utility companies. Previously Tony has spent over 10 years with National Grid in the UK and the US. He has been both a substation equipment specialist and has also taken on the role of substation asset manager and distribution asset manager. Tony is a Fellow of IET, a member of IEEE, ASTM, CIGRE and the IAM, and is currently on the executive of the Doble Client Committee on Asset and Maintenance Management. His initial degree was in physics. He has an MS and a PhD in EE and an MBA. Tony is an Adjunct Professor at Worcester Polytechnic Institute, Massachusetts, leading courses in power systems analysis.

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EXTENDING THE LIFE OF EXISTING SWITCHGEAR NETA World, Winter 2013 Issue Miklos J Orosz, Schneider Electric The rapid growth of utilities and heavy industry, such as steel manufacturing and oil refineries, has increased the need for more, better, and reliable power distribution and control. Loss of power in today’s manufacturing environment could mean the total loss of production and equipment. According to studies published by the Hartford Steam Boiler Insurance Company and FM Global, “Electrical equipment failures account for millions of dollars in damage and lost business every year.”

SWITCHGEAR CONSTRUCTION 101 Electrical switchgear is composed of passive and active components. The switchgear’s frame, enclosure, and horizontal and vertical bus sections make up the passive elements of the equipment. Circuit breakers and fusible switching devices have an active role in the equipment’s operation which includes protecting the electrical assets downstream, disconnecting the circuit, and reducing or eliminating the arc-flash hazards associated with switching high magnitude currents. This article will primarily focus on the most commonly utilized active component in switchgear, the circuit breaker. As such it plays a vital part in determining the best way to extend the life of your switchgear. Medium-voltage switchgear can consist of one of four types of circuit breakers based on the arc-quenching medium: air, vacuum, oil, or SF6 gas. These circuit breakers are typically a draw-out type, a design which facilitates removal from the power source and simplifies maintenance. Air, vacuum, oil, and SF6 gas circuit breakers require similar maintenance; however, each has unique characteristics and testing procedures.

MAINTENANCE REQUIREMENTS Major electrical equipment manufacturers generally require annual maintenance for power circuit breakers to ensure proper operation and to maintain equipment warranties. This maintenance consists of cleaning and lubrication of the primary and secondary disconnects, racking mechanisms, and cell interlocks. A thorough on-site maintenance work scope for power circuit breakers includes:

• Inspection • Cleaning and lubrication • Adjustments • Overcurrent protective device testing

• Insulation testing • Charge/close/trip circuit testing • Dielectric testing • Time and speed testing

The use of new or refurbished parts or subassemblies may be required to return a circuit breaker to its designed operating condition. A more intensive maintenance option for circuit breakers is inshop reconditioning. With this option, the breaker is initially tested to relevant ANSI standards and then completely disassembled, cleaned and inspected. Damaged parts are refurbished or replaced, and pivot points are cleaned and lubricated before the circuit breaker is reassembled. The reconditioned breaker is retested to relevant ANSI standards, including primary current injection and timing tests. Even with annual maintenance, however, power circuit breakers may need additional upkeep or upgrades. Factors to consider include the operating environment, availability of spare parts, reliability, and the cost of ongoing maintenance. There may also be the need to increase the switchgear’s short-circuit or continuouscurrent rating, or the desire to upgrade technology. As a result, facility managers are often faced with the choice of maintaining aging (or obsolete) equipment or replacing it with a new switchgear lineup to take advantage of current technology.

FINANCIAL CONSIDERATIONS WHEN REPLACING SWITCHGEAR In addition to the initial cost of new switchgear, it is important to consider the potential disruption to the facility’s processes and workflow during the course of changing out the equipment. Unless process loads can be rerouted temporarily during the demolition of old equipment and installation of the new switchgear, the cost of lost production can be substantial. Another consideration that is often overlooked is conduit placement. Installing new switchgear (which is usually smaller than the older/obsolete equipment it is designed to replace) requires that existing conduit above and below the equipment be moved. Cabling may need to be replaced or spliced. This is an expensive and time-consuming process, often costing more in labor and material than the cost of the new equipment.

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Circuit Breakers Vol.1 Facility managers now have another option to consider for the repair vs. replace dilemma. New design capabilities exist to modernize and extend the life of the active components, i.e., circuit breakers, while leaving the existing passive switchgear structure intact. All things considered, extending the life of existing switchgear in this way is most often a real advantage.

WHY UPDATE? Modern power circuit breakers are designed using state of the art materials and arc-extinguishing technology. Since power circuit breakers provide such a vital function in protecting the electrical system, as well as reducing or eliminating arcing-fault hazards, these design improvements are a quantum leap forward in equipment and operating personnel protection. In addition, they have lower maintenance requirements than the older design circuit breakers With this in mind, following are eight reasons to extend and optimize the life of your electrical switchgear equipment and improve its reliability:

Rating Upgrades – As the need for more and more power

at many industrial facilities increases so does the need for improved and increased protection of the electrical system. In most cases the switchgear bus, bracing, frame, or enclosure are usually higher rated than the circuit breakers, but if not they typically can be upgraded. The circuit breaker used in the switchgear also can be upgraded at least one class, for example, from 25 kA shortcircuit interrupting capability to 40 kA, and in some cases, even up to 50 kA. The continuous-current carrying capability also can be increased by reviewing the existing switchgear bus design and updating it. Modern vacuum circuit breakers are also faster, most having short-circuit current-interrupting ratings of three cycles or less, compared to the older circuit breakers with interrupting time of five cycles, eight cycles or even more.

Environmental Upgrades – Many old design air magnetic

circuit breakers used asbestosbased arc chutes, oil used in the oil circuit breakers may contain hazardous chemicals, and SF6 gas was recently classified as a greenhouse gas. By replacing these designs with the new technology of vacuum interrupters, environmental concerns can be resolved.

Performance and Safety Upgrades – Circuit breaker and

switchgear upgrades can offer enhancements for performance and improved safety. Integrating new state-of-the-art, arc-resistant technology into the retrofit can increase protection for both personnel and equipment. As an added benefit, because the short-circuit interruption and opening time is generally faster, the upgraded circuit breaker is better suited for load transfer applications. Upgrading can also increase the capabilities of circuit breakers and switchgear.

• Arc-fault current interruption ○ New circuit breakers are available with higher ratings ○○ In most cases the interruption capacity of the entire switchgear can be increased with an engineering study and a circuit breaker upgrade or replacement • Arc-flash limiting circuit breaker availability • Trip unit accuracy and repeatability with new circuit breakers • Power metering, monitoring, and communication Upgrades to Meet the Latest ANSI Standards - A major improvement in circuit breaker design is that vacuum circuit breakers are operating with the voltage factor K=1, which means that the interrupting capability is not affected by the system voltage. A vacuum circuit breaker with an assigned short-circuit current interrupting capability will function at any voltage level without reducing the assigned shortcircuit interrupting rating. This allows the user to be more flexible concerning interchangeability of the new circuit breakers.

Improved Reliability – Aging materials reduce equipment

reliability due to the dielectric breakdown of insulating components and the degradation of aging mechanical parts. Electromechanical trip devices on existing circuit breakers may not trip at all. Those that do trip are not repeatable and may be well outside the time-current coordination parameters.

Reduced Maintenance Costs – By using upgraded vacuum circuit breakers as retrofits, the circuit breaker maintenance cycle can be extended to five years or more. There are state of the art circuit breaker designs that utilizes a virtually maintenance free operating system. Compare this with these facts: • Older power circuit breakers require extensive periodic maintenance and overhaul which is expensive and time consuming: ○ Lengthens outages. ○ May require extensive outside support. • Many components for existing and older circuit breakers are no longer available: ○ The quantity and quality of used or reconditioned parts is decreasing and unreliable. ○ Prices of replacement parts are increasing. Upgrades Reduce Size and Weight of the Circuit Breaker – Typically a 30 percent to 60 percent weight reduction can be achieved by using the new vacuum technology. This can improve access for maintenance and transportability. Upgrade/Retrofit Cost Considerations – There are several factors influencing the cost when considering upgrades, repairs, or retrofit solutions, compared to acquiring new equipment as follows: • Cost of new equipment compared with cost to retrofit/upgraded equipment • Plant maintenance cost analysis

68 • Additional space requirements • Construction and installation costs • Removal and disposal of existing equipment • Labor cost of training maintenance personnel • Downtime cost (loss of production)

Circuit Breakers Vol.1 CHOOSING THE CIRCUIT BREAKER / SWITCHGEAR SOLUTION Retrofitting is a general term that is used to define any process which allows for modernization and life extension of electrical equipment. Direct replacement and retrofill solutions are two different retrofit strategies to adapt modern circuit breakers into existing low-voltage or medium-voltage switchgear. The switchgear structure, conduits, cabling, and footprint are left intact which saves time and money. ●● Direct Replacement: A new circuit breaker fits into the existing cubicle with little-to-no modification to the switchgear cell. This option reduces downtime since there is minimal (if any) outage on the equipment bus. ●● Retrofill: The existing switchgear cell and bus are modified to accept the new circuit breaker. This process usually requires a longer bus outage, during which time the internal circuit breaker cell is modified to accept the new circuit breaker.

CASE STUDY: Medium-Voltage Retrofill An automotive facility’s personnel were concerned about a lengthy and costly downtime because of outdated switchgear operating in this automotive manufacturing plant. The facility’s two primary switchgear lineups were installed in the early 1950s. Though they were still operational, the age of the circuit breakers connected to the 2,000 ampere bus in both lineups, along with the elevator-like system used to remove them from the switchgear for maintenance, made for an outdated system that raised concerns of reliability and posed an increased risk of hazard for the plant’s electricians. After much investigation, facility management selected a retrofill solution to upgrade all 19 circuit breakers with new mediumvoltage circuit breakers. Existing switchgear cubicles were reconfigured to accept the new circuit breakers, leaving the switchgear structure and footprint intact. The retrofill solution also included installation of solid-stage digital relays, a new exterior door (where the relays resided) and an interior sub-plate positioned beyond the circuit breaker to minimize possible exposure to the energized bus. The elevator racking system was also replaced with a new cradle assembly for each cubicle. As a result, the physical action of racking out a breaker would be accomplished with the exterior door closed.

Fig. 1: The original air magnetic circuit breaker with asbestos-based arc chutes shown on the top and the direct replacement modern vacuum circuit breaker shown beneath.

With the circuit breakers and relays installed, the plant has a more reliable electrical distribution system. This solution met the facility management’s goal of upgrading the equipment extending its useful life, minimizing downtime, and enhancing workplace safety for the plant’s electricians. Though direct replacement and retrofill solutions have different processes, both have the same end result: improved power system reliability and lower lifecycle costs.

Circuit Breakers Vol.1 CONCLUSION Electrical equipment and power distribution systems have never been designed to be or intended to remain perpetually energized without interaction by the owner. If maintenance has not been regularly performed, this less-than-satisfactory condition may be entered prematurely and a shortened useful life of the components may be the result. Modernization solutions present a viable alternative to purchasing new equipment. The most obvious benefit of upgrading existing electrical switchgear is the significant savings on costs that would have been dedicated to buying new equipment — and not just the physical equipment, but the time and labor involved in specification, procurement, installation, testing, recabling and commissioning. With careful consideration and proper implementation of the points covered in this article, the life and reliability of switchgear can be maximized. Mike Orosz, Sr. Staff Mechanical Engineer at Schneider Electric Company has 40 years industry experience (36 years with Schneider Electric). His areas of expertise include: medium-voltage switchgear and circuit breaker design, medium-voltage motor starter design, field problem investigation and work, SF6 interrupter, vacuum interrupter, ANSI IEC testing, mechanism design, materials, plastic moldings, heat treating and finishing and sheet metal design. Mike is a member of IEEE, PES, ASM and IEC TAG.

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MODERN PROTECTION SCHEMES FOR LOW-VOLTAGE CIRCUIT BREAKERS NETA World, Winter 2013 Issue Dan Hook, Western Electrical Services, Inc. This article will be the first of a two-part series covering many of the protection schemes available in low-voltage switchgear. This first part will be a simplified description of the schemes and some of the basic theories applied to accomplish the intended goals. Manufacturers frequently change the protection schemes available in low-voltage power, insulated-case, and molded-case circuit breakers. Some of these changes are in response to new requirements in standards such as NFPA 70, NFPA 70E, UL, and others. Other changes are simply improved methods to help a manufacturer garner a larger market share. Different manufacturers identify many similar functions and features with different names. Where possible, the known terminology for the same or similar features is presented. This article does not attempt to cover all the options available from the major manufacturers but rather be an overview of some of the more common and misunderstood schemes available today. No matter whether you are an engineer, technician, contractor, or facility owner, this article should reinforce the importance of reviewing and understanding the manufacturers specific instructions. ●● I2t/I4t Response ○○ Motivation: Allow for better coordination with devices having inherent characteristics that present coordination and protection challenges. ○○ Simple description: By default digital electronic devices have an on/off type nature. For example, in a low-voltage breaker trip unit when a short-time set point is reached, the trip unit goes into pickup, and the timing circuit starts the countdown to the trip time based on the short-time delay setting. The result is a very discrete and square time-current curve across all protective functions. In the case of a power system engineer coordinating the protective device settings of multiple devices with digital electronic protection features, the work is fairly straight forward as all of the characteristic curves will have the same discrete shape and relatively narrow tolerance bands. If, however, a protective device or power system component is present which has another shape of characteristic curve, the challenge is increased. By nature a thermal magnetic trip device in a molded case breaker, for instance, has a smoother shaped inverse time current characteristic curve. The curve represents the physical properties of perhaps a bimetallic strip, in which an increase in current flow will increase the heating rate in an analog fashion. ○○ Theory: The challenge lies in fitting a discrete digital device to an analog device curve. This challenge has been met by most, if not all, major manufacturers of low-voltage trip units by providing an option for inserting an algorithm into the long time, short-

time, and ground fault protective functions to shape the time current characteristic curve to more closely match an analog device or piece of equipment, especially in the areas of the coordination plots where conflicts are common. Two common algorithms are the I2t and I4t functions, referring to a shape that mimics the product of current squared and time, and another that mimics the products of current to the fourth power and time. Thermal magnetic trip devices were mentioned as one device characterizing these smooth curve shapes. A fuse is another example of a protective device that has these characteristics by the nature of its physical properties. Likewise, the thermal damage curves of power system equipment can also have these characteristics. This stands to reason in the case of cables and transformers as they are heated as a result of current flow in a manner similar to that of a thermal magnetic trip unit or fuse. The actual curve shape can change based on cooling capability and other design characteristics; however, in most cases the I2t function is designed to allow easier coordination with thermal magnetic trip units and fuses, while the I4t function is designed to accommodate coordination with upstream transformers and fuses. These algorithms are applied in a variety of ways. – Two hemisphere dial adjustments, one half with the function(s) inserted, one half without – Dip switches to select between I2t or I4t in or out – LCD screen toggling and selection during setup

Fig. 1: TCC showing curve shape difference in a short-time function

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●● Zone selective interlocking

○○ Simple Description: Recall the earlier discussion covering the discrete nature of digital electronic devices. When applied again to the long time trip function designed to protect equipment from overload conditions, the trip unit will go into pickup and begin timing as soon as the sensed current exceeds the long time pickup value. In the instant the sensed current drops below the pickup value the timing circuit stops the timeout as desired. However, if the current increases again above the pickup value in a short period of time, the trip unit starts its timeout to trip again, but doesn’t remember that the circuit was just subjected to a brief overload and the resulting heating. In this fashion a series of brief overloads that do not reach the timeout setting can cause damage to circuit parts without tripping the circuit breaker responsible for protection of that circuit. The thermal memory feature was developed to allow a digital electronic trip unit to mimic the performance of a thermal magnetic circuit breaker. It is important to note that a thermal magnetic trip unit has an integral thermal memory feature as part of it physical characteristics. It actually heats up and cools down in a manner similar to the devices that it protects. Just as a cable would not instantly cool off, a thermal magnetic circuit breaker will not as well. Only an electronic trip unit needs to be taught to remember to what the circuit was recently subjected. In cases where loads are cyclical and near the overcurrent setting, a standard thermal memory function can result in nuisance tripping. Attempts have been made to improve the algorithm through the use of more accurate input parameters to allow use of the thermal memory function in these specific circuit applications. Thermal imaging is a term used by one manufacturer to describe this advancement on the same thermal memory concept.

○○ Motivation: Limit the time to trip to the absolute minimum to protect equipment and personnel without sacrificing selective coordination. This method is recognized in NEC article 240.87 as an acceptable alternative to instantaneous tripping. ○○ Simple Description: Zone interlocking is designed to segregate an electrical system into zones, and through use of communication between low-voltage breakers, ensure that the breaker responsible for that zone of protection is the device used to interrupt a fault. With the added information available to the system, circuit breaker tripping times can be reduced to less than programmed settings without fear of a nuisance trip resulting in de-energizing more of the system than necessary. Communication is accomplished from feeder breakers to main breaker through secondary disconnect connections into the trip units themselves or through an intermediate zone interlock module taking inputs from all circuit breakers and outputting the restraint commands as necessary. ○○ Theory: In a simple system with one main circuit breaker and several feeders configured with zone interlocking, the feeder breakers communicate with the main circuit breaker through a dedicated hard-wired connection. In the case of a fault downstream of one of the feeders, that feeder will detect the fault and send a restraint signal to the main breaker to prevent a trip while the feeder breaker clears the fault. In the other case where a fault occurs between the main and feeder breakers, the main will sense the fault and receive no restraint signals from the feeders, as they do not sense the fault. In this case the main breaker can trip without delay, as it knows the fault is in zone 1 or, put another way, it is the device responsible for clearing the fault.

Fig. 2: Zone 1 fault and Zone 2 fault diagram ●● Thermal Memory and Thermal Imaging ○○ Motivation: Protects distribution system components from damage due to repeated intermittent overload events and periodic ground fault events. Advanced thermal memory functionality requires more accurate input parameters and algorithms to model the thermal condition of conductors. The latter may be required in situations where cyclical loads dictated the disabling of standard thermal memory to eliminate nuisance tripping.

Fig. 3: Intermittent overloads with and without thermal memory ●● Reduced Energy Let-Through, Quick-Trip, Arc-Flash Reduction Maintenance System, Dynamic Arc-Flash Reduction System, Alternate Maintenance Setting ○○ Motivation: Reduce the arc-flash hazard severity that a worker downstream may be exposed to in the event of a fault. This method is described as one of the acceptable methods per NEC 240.87 to accomplish an increased level of worker safety specifically on circuit breakers that do not have instantaneous trip functionality.

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Circuit Breakers Vol.1 ○○ Simple Description: The four major contributing factors to the severity of an arc-flash event are: – Fault current level – Clearing time for the upstream protective device, or how long the fault persists before being extinguished – Distance from the fault to a subject worker – Physical characteristics of the equipment subjected to the arc-flash event. ○○ This feature shortens the time that an arc-flash event persists by adjusting the time delay to trip and/or overcurrent pickup set points. These changes to the settings are applied temporarily while activities are performed on an energized system downstream of the subject circuit breaker. It is commonly activated with a toggle switch or button. The settings must be predetermined by an engineering study and preprogrammed into the trip device for selection when desired.

differing design and construction of various circuit breaker models and sizes results in clearing times that vary as well. Further the tolerance region on instantaneous trip events can be much greater than other trip functions. Some manufacturers provide tables showing instantaneous selectivity at higher fault current levels based on their own testing data. ●● Instantaneous Fault Discrimination or Making Current Release ○○ Motivation: Increase personnel protection by enabling an instantaneous trip in the case of closing in on a faulted circuit. ○○ Description: If high current levels are generated immediately upon closing a circuit breaker, it is possibly indicative of faulty conductor installation or a downstream fault of relatively low impedance. Manufacturers can apply an instantaneous trip feature upon closing, on the order of 12x-25x of the circuit breaker sensor/plug rating, to immediately reopen if necessary. The intent is to limit equipment damage and the severity of any downstream arc-flash event that may be generated by these elevated currents. The making current release functionality is active for only a short period of time after the circuit breaker is closed. After this short preset time, the normal fault protection set points applied to the trip unit are restored. ●● In the age of proliferation of microprocessor-based trip units on low-voltage circuit breakers, the number of protective features available to be implemented is really only limited by the number and nature of inputs that can be provided. There are protection options for undervoltage, overvoltage, imbalance in current and voltage values, underfrequency, overfrequency, and reverse power. Additionally there are alarms, indications and diagnostics available certainly numbering in the tens and perhaps approaching the hundreds. ●● The second installment will dive deeper into the theory as it applies to testing and certifying of these systems to ensure they will operate as designed and installed. Stay tuned.

Fig. 4: URC QuickTrip TCC comparison ●● Instantaneous Selectivity ○○ Motivation: Selective coordination is a not a protection scheme per se but rather a term that describes “localization of an overcurrent condition to restrict outages to the circuit or equipment affected, accomplished by the choice of overcurrent protective devices and their ratings or settings” per the NEC. The coordination of protective devices has unique challenges as it applies in the instantaneous region. ○○ Simple description: By definition an instantaneous trip is a trip of a circuit breaker with no intentional time delay. The

Dan Hook is the Chief Operating Officer of Western Electrical Services Inc. He joined the group in 2004 and has been in the electrical industry for over 18 years with the US Navy and civilian experience. Daniel holds a Bachelors Degree in Nuclear Engineering and a Masters degree in Electric Power Engineering from Rensselaer Polytechnic Institute in Troy, New York, and he maintains his professional engineer’s license in Washington State and Arizona. He is a Certified Journeyman Electric Motor/Generator Repairman (US Department of Labor, US Department of the Navy). The Inter-National Electrical Testing Association (NETA) certifies him to Level III Technician. The National Institute for Certification in Engineering Technologies (NICET) certifies him to Level III in the area of Electrical Testing Engineering Technology. Dan spent over a decade in the US Navy as an Electrician’s Mate maintaining and testing all aspects of generation, distribution, control equipment, and system protection as it applied to nuclear submarines.

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TESTING AND CERTIFYING MODERN PROTECTION SCHEMES FOR LOW-VOLTAGE CIRCUIT BREAKERS NETA World, Spring 2014 Issue Dan Hook, Western Electrical Services, Inc. This article is the second installment of a two-part commentary covering many of the protection schemes available in low-voltage switchgear. This first part, which can be read in the Winter 2013 Edition of NETA World, covered the basic theories and motivations for a handful of the capabilities of modern, low-voltage circuit breaker trip units. This second part will attempt to suggest a methodology for testing and certifying these increasingly complex systems. Every capability of the many trip units available will not be covered, but some specific examples will be addressed. Most readers will recognize the difference and importance of three distinct levels of electrical testing as it applies to electrical systems. Component testing, functional testing, and commissioning are recognized as three levels, increasing in complexity and documentation, in readying a system for turnover to an owner. ANSI/NETA Maintenance and Acceptance Testing Specifications are the industry recognized requirements for component testing and functional testing. Low-voltage trip units have progressed with microprocessor technology and capabilities to a point where the line of demarcation between them and complex medium- and high-voltage protective relays has all but disappeared. Many of the features available are present on both types of equipment. Commensurate with that fact, the technician responsible for certifying these systems must increasingly have a similar frame of mind with respect to the methodology used to prove these devices. Some of the features addressed in part one of this article in the last edition of NETA World can be adequately addressed with component testing. Some will require functional testing with varying levels of complexity to confidently conclude that the system will operate as designed and installed. And finally some protection schemes and other features involve a multitude of components, installation techniques, communications, and perhaps programming such that integrated system testing, included as a component of overall commissioning, is the only way to certify the system is free from discrepancies. Even when a component test is an adequate way to correctly evaluate a protective feature, there are commonly pitfalls or nuances of the testing process that must be considered to ensure correct evaluation in determining suitability for initial energization or continued service. Listed below are some examples of different features that may be considered for the different levels

of certification, as well as some that may in fact be a feature of a low-voltage breaker, not necessarily subjected to a test routine, but lie more in the design certification arena. Component Testing: Most of the ANSI/NETA ATS and MTS Sections 7.6.1.1 and 7.6.1.2 address component type testing requirements for low-voltage circuit breakers. Primary injection testing is called for specifically by trip function: long time, short time, instantaneous, and ground fault. The manifold of other protective features available are not as specifically addressed, but may present real challenges to the technician. I2t/I4t Functionality: In my experience and with consideration to executing a valid repeatable test these functions are often disabled during testing by selecting “OFF” or “OUT” on the applicable trip function. This allows a more easily decipherable trip-time range as read on the time-current characteristic curve and can curb the effects of test-current ramp-up time on the time value observed. Increasingly, I have experienced customer specifications and expectations that low-voltage circuit breakers be tested at the settings provided in the protective device coordination curve. Zone Selective Interlocking: A single circuit breaker can be tested and verified to operate correctly with respect to a zone interlocking feature by simulating a restraint signal and documenting the performance and then removing the restraint signal and documenting the performance. Often this restraint signal can be achieved with a simple jumper on the secondary disconnect contacts to feed the breaker’s own restraint signal into its restraint input. Thermal Memory: Many technicians will have not so fond memories of their first experience testing a circuit breaker with thermal memory functionality. Often the first phase of testing goes well, and during the next phase of testing the results appear to change perhaps just in or out of the specified range. By the last phase of testing it is clear that something may be awry. It is often at this point when a technician will refer to the manufacturer’s instructions or seek help from another technician and learn that a thermal memory function may be the culprit. If this is the case, the trip unit is working exactly as designed, and the overload conditions experienced during the first two phases of testing have dictated the next overload event to trip the breaker in a shorter period of time. Some manufacturers allow for defeating of the thermal memory with a dial or dip switch, others use a jumper inside the

74 trip unit, and still others may require the use of the manufacturer’s test device to override or defeat this function to allow for efficient testing. Depending on the manufacturer, the time to fully reset the thermal memory algorithm can be 5-15 minutes. Under/overvoltage: Voltage element testing can be very straightforward and efficient; however, care must be taken when determining where to inject test signals. Also remember that in many cases a variable voltage source may not be on the standard list of test equipment necessary when a technician is assigned low-voltage circuit breaker testing. Insulation resistance testing is worth mentioning as well. As new trip unit designs are released and voltage sensing, display, and protection capability are becoming more commonplace, extreme care must be taken to ensure that dielectric testing performed does not damage the trip unit components. Often removing a rating plug or removing voltage sensing leads or fuses will be required. Under/overfrequency: As was mentioned with voltage testing above, the actual testing of frequency elements may not present a large challenge technically or even time wise, however a variable frequency source again may not be in the technician’s mind when preparing for low-voltage circuit breaker testing. Reverse Power: Simultaneous injection of voltage and current either primary or secondary to the current transformers will be required. Depending on the manufacturer one may be able to be accomplish this in a single-phase test; however, three-phase capabilities for both current and voltage sources may be required if the feature is being used by the trip unit.

Circuit Breakers Vol.1 Functional Testing: Specifically parts 7.6.1.1.2.11 and 7.6.1.2.2.11 of the ANSI/NETA ATS and MTS mention verifying the functionality of various features or schemes. Section 8 addresses the development and execution of a functional testing plan to prove the aspects of the system installed. Reduced Energy Let-Through, Quick-Trip, Arc-Flash Reduction Maintenance System, Dynamic Arc-Flash Reduction System, Alternate Maintenance Setting: These features, with all their varied nomenclature, endeavor to accomplish the same goal of reduced arc-flash hazard energy downstream of the subject low-voltage circuit breaker. Some manufacturers utilize a simple switch providing a dry contact type input to the trip unit to assert the alternate protective settings, while others use more complex methods. One manufacturer utilizes a separate 24 Vdc power supply and associated wiring to insert a signal into the low voltage trip unit and apply the alternate set points. For trip units with complex communication capability in facilities with a direct digital control system, the feature can be activated over that communications network. One may be able to perform the actual trip verification during the component testing via primary injection, but the functional testing steps will likely focus on verifying the input used to cause the change in state in the trip unit. At this time ANSI/NETA testing specifications do not call for primary injection testing to prove these substitute set points. The manufacturer’s method of triggering of the system installed will dictate how to develop the functional test plan to alternately activate and deactivate the scheme as desired.

Alarms: There are many trip functions that can be accompanied with a corresponding alarm type condition at a threshold level set in such a way that the alarm will actuate prior to a trip event. Some examples may be overcurrent, undervoltage, imbalance, and underfrequency. Expectations for testing each of these alarms must be clearly communicated prior to the testing session. Metering Indications: Many microprocessor based trip units have consolidated metering capabilities that may have been present elsewhere on the switchgear or cubicle to the trip unit itself. This is an efficiency gain in that duplicate instrument transformers and indicating devices are not required. However these capabilities require testing and certification no matter where they are contained and are an example of another case in which the traditional short list of test equipment required for low voltage circuit breaker testing must grow when dealing with microprocessor trip units onboard. Event Recording and Diagnostics: This type of capability of a low voltage trip unit may be used for a wide variety of functions. Simple trip current level indication may be provided; the phase of the sensed condition may also be presented. Full waveform type event recording is available on at least one manufacturer’s lowvoltage trip unit line of products. Self check circuitry is commonly a part of microprocessor devices and may output an error signal as well.

Fig.1: Trip Unit

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75 complex metering including power quality and power flow calculations. Often component testing, and in some cases simple functional testing, fails to reveal a polarity reversal on a current transformer, or a potential transformer design or installation error in which delta-wye configuration is not correct. Interconnecting wiring configurations can be used to physically accomplish a phasor addition or cancellation. A common method used as a final proofing step covering all of the sources and loads in an electrical system involves a temporary load bank configuration, available with unity and capacitive or inductive power factors, connected to the equipment followed by a systematic manipulation of the sources and power flow arrangements to prove all components of the system and their interrelation. Design features not necessarily practical or expected as a part of a field-testing routine.:

Fig. 2: Trip Unit with no dials and instead LCD screen display Zone Selective Interlocking: Different test methods are available depending on the specific manufacturer of the system installed. In general the direct-wired connections, polarity sensitive in most cases, must be fully verified to ensure the proper operation of the feature as designed. This verification can be accomplished with an integrated test feature, if installed, by following the manufacturer’s instructions. If no integrated test feature is installed the best way to certify this system is to fully install all applicable circuit breakers in the system that are part of the scheme and primary inject current levels to simulate faults in the different zones of protection to verify correct operation of the responsible circuit breaker. This method is certainly more time consuming and may require a written method of procedure; however, it may be the only way to fully validate the installation.

COMMISSIONING (Integrated System Testing) Communications/Alarms and Indications: As mentioned above, modern low-voltage devices have communication capabilities not limited to just local alarms and indications. They can be controlled over a facility’s direct digital control system, and the level of control can include operation as well as safety devices. The correct programming, testing, and verification of these features can best be accomplished by an integrated system test. Multiple devices are necessarily involved, as well as interconnecting wiring, possibly even wireless devices, and the complex addressing and communication device programming required, dictate that a comprehensive commissioning plan be developed, approved, and executed. Metering/Power Quality/Load Power Flow: The instrument transformer inputs for modern low-voltage trip units allow for

Instantaneous Selectivity: As covered in the first part of this article in the previous edition of NETA World Journal, this characteristic is a result of manufacturer’s design testing of certain breakers arranged in a series configuration. If questions arise concerning a specific application related to instantaneous selectivity of the installed system, the manufacturer’s provided tables should be referenced, or in their absence the manufacturer consulted. Instantaneous Fault Discrimination/Making Current Release: This feature of most low-voltage circuit breakers involves very high current associated with short circuit currents. Personally I have never encountered a situation where the testing of this feature was even discussed, nor can I foresee a reason in the future, outside of forensic testing or other specific data gathering routine that is outside the scope of acceptance or maintenance testing. During the course of writing this article I discovered or was reminded of some other interesting items that in some way apply to the subject matter. These are worth mentioning as potential products, techniques, or methods that may assist the reader in the future by answering some of the questions that arise. Small molded-case breakers that traditionally had thermal magnetic or simpler solid-state trip devices are commonly being equipped with mini-microprocessor based trip units with many, if not all, of the features of the larger power circuit breaker trip units. No longer can the smaller panel boards filled with molded-case breakers be expected to be a quick long time and instantaneous primary injection test with a contact resistance test and insulation resistance test. Programming and feature testing may dictate much more effort in the future. At least one manufacturer offers a medium-voltage circuit breaker with an onboard trip unit. To my knowledge there is still a difference in that the current transformers are not contained onboard the breaker as in the low-voltage application; however, insulating material advancements may allow for them to be located on the breaker themselves. With remote current transformers and

76 onboard medium-voltage trip units, is primary injection still the preferred method for testing, and what challenges will that cause in test setups? The vast range of features, and their associated required settings, onboard modern low-voltage trip units when combined with the communication capabilities for connection to the modern test technician’s laptop with appropriate software could add another level of complexity to the testing of low-voltage circuit breakers. If the day has not come yet, it may not be far off where a list of required set points for the circuit breakers listed on a settings sheet will not be sufficient. Trip logic and interlocks between devices may require comprehensive set point files to be generated and uploaded as is the case for many microprocessor-based, medium-voltage protective relays. Increasingly, project specifications require the protective device acceptance testing to be performed at the specified set points as dictated in the protective device coordination study. It is imperative to be able to meet this requirement that the study be performed and approved well in advance such that the testing agency can plan for the methods, procedures, and test equipment necessary. As I said in the first article, worthy of stating again, no matter whether you are an engineer, technician, contractor, or facility owner, this article should reinforce the importance of reviewing and understanding the manufacturer’s specific instructions. I would add to the list, the protective device coordination study, the owner’s project requirements, and a test plan that may be complex enough to be written and approved prior to the testing mobilization. Dan Hook is the Chief Operating Officer of Western Electrical Services Inc. He joined the group in 2004 and has been in the electrical industry for over 18 years with the US Navy and civilian experience. Daniel holds a Bachelors Degree in Nuclear Engineering and a Masters degree in Electric Power Engineering from Rensselaer Polytechnic Institute in Troy, New York, and he maintains his professional engineer’s license in Washington State and Arizona. He is a Certified Journeyman Electric Motor/Generator Repairman (US Department of Labor, US Department of the Navy). The Inter-National Electrical Testing Association (NETA) certifies him to Level III Technician. The National Institute for Certification in Engineering Technologies (NICET) certifies him to Level III in the area of Electrical Testing Engineering Technology. Dan spent over a decade in the US Navy as an Electrician’s Mate maintaining and testing all aspects of generation, distribution, control equipment, and system protection as it applied to nuclear submarines.

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FIELD TESTING TECHNIQUES FOR LOW-VOLTAGE CIRCUIT BREAKERS NETA World, Spring 2014 Issue Bruce M. Rockwell, P.E., American Electrical Testing Co. Modern technology continues to rapidly drive advancement of lowvoltage circuit breaker design. While application of new technology to reduce cost is always a product manufacturing consideration, the goal of achieving faster fault clearing times is producing frequent design change of low-voltage circuit breakers. The frequency of change represents a persistent challenge for technicians and engineers who have to keep up with new field test techniques and to maintain an accurate library of trip curve characteristics. This article identifies and illustrates emerging circuit breaker technology enhancements that require new knowledge and new field test techniques. A primary driver of change is development of many new products and their subsequent rapid refinement to address arc-flash hazard reduction. In comparison, ground fault circuit interrupters were developed and have become commonplace for safeguarding against electric shock hazard. These devices have evolved and continue to evolve facilitating widespread application. Ground fault detection and trip schemes are just one subset of the many techniques employed to address arc-flash hazard reduction. When considering low-voltage circuit breakers, one must understand the type of circuit breaker to be tested. Identifying the circuit breaker type is a first step in confirming the appropriate maintenance and test procedures as well as the appropriate test equipment. Reviewing and considering the breaker’s use and application is helpful in determining expected test results. The variety of low-voltage circuit breakers is constantly expanding due to technological innovations. Keeping things simple helps when testing, so first a breaker under test should be identified by classification such as molded-case, insulated-case, or low-voltage power.

●● Insulated-Case (Rated And Tested To Ul 489) “Fast in interruption, but normally not fast enough to qualify as current-limiting circuit breakers. They are partially field maintainable.” ●● Low-Voltage Power (Rated And Tested To ANSI C37) “Used primarily in drawout switchgear, they are not fast enough in interruption to qualify as current-limiting. LVCBs are designed to be field maintainable in the field.” Table 1 is a partial excerpt from IEEE 1584 (2002). This table implies that no low voltage circuit breaker can operate in less than one-half cycle. However, IEEE 1015 and UL 489 speak to the fact that there are special-purpose, molded-case circuit breakers that are defined as current-limiting circuit breakers. Circuit Breaker Rating and Type

Opening Time at 60 Hz (cycles)

Low-voltage (molded case) (< 1000 V) (integral trip)

1.5

0.025

Low-voltage (insulated case) (< 1000 V) power circuit breaker (integral trip or relay operated)

3.0

0.050

This table does not include the external relay trip times

Table 1: Power Circuit Breaker Operating Times

An often misunderstood aspect of low-voltage circuit breakers is the clearing time. This is sometimes referred to as fault clearing time, total clearing time, or breaker operating time. Since technology is driving faster clearing times, having a good understanding of operating time is important. Low-voltage circuit breakers may use direct acting, integral electronic, or relay tripping. IEEE standard 1015 provides some insight into expected breaker operating times and maintainability for the three types of low-voltage circuit breakers: ●● Molded-Case (Rated And Tested To Ul 489) “Virtually all MCCBs are interrupt fast enough to limit the amount of prospective fault current let-through, and some are fast enough and limiting enough to be identified as current-limiting circuit breakers. MCCBs are not designed to be field maintainable.”

Opening Time (seconds)

Fig. 1: Current-Limiting

78 A circuit-breaker that does not employ a fusible element and that when operating within its current limiting range, limits the let-through (I2t) to a value less than the I2t of a half cycle wave of the symmetrical prospective current within the first half-cycle is by definition current-limiting. Current-limiting circuit breakers are generally available from 15 - 1200 amperes, rated to 600 volts, have interrupting ratings up to 200 kA, and can clear a fault within the first half cycle (Figure 1). Applying current-limiting devices (fuses, fused circuit breakers or current-limiting circuit breakers) is one method to dramatically reduce arc-flash hazard. While low-voltage power circuit breaker themselves are not current-limiting, they are routinely applied with integral fusing as a current-limiting protective device assembly. The use of a fault clearing time of two seconds is suggested in “Annex B” (informative) of IEEE 1584 and also in “Annex D” (informative) of NFPA 70E, when favorable conditions of egress exist. It is important to note that this statement is offered up with a clear warning that this two second clearing time is not applicable to all cases and should not be used arbitrarily for determining arcflash hazards. However, it can be implied to represent a desired upper limit for clearing time durations. Field testing accuracy of circuit breakers with trip functions set to clear in two seconds (or less) is critical with regard to verifying and validating arc-flash hazard calculations. When testing current-limiting circuit breakers, the timing range precision and accuracy of the test set in the fractional cycle range is even more crucial. The total clearing time of a circuit breaker is the time for the circuit breaker to sense a fault, actuate tripping, and break the current arc. The operating time for low-voltage circuit breakers will range from less than one-half cycle to three cycles. The operating time for the tripping device needs to be added to this time to arrive at the total fault clearing time. Note that, for low-voltage circuit breakers, the manufacture’s time-current-curves include both the trip device delay time and the circuit breaker clearing time. Modern technology has not only focused on means to achieve current-limiting circuit breakers it is also focused on reducing the initiate trip time for the sensing and actuation device. Circuit breakers that are not direct acting have conventionally relied on fault sensing using current transformers in the phase to sense a short circuit. This can work well for high level bolted faults, especially when applied with current-limiting breakers. However, when arcing faults occur, the resultant fault current can be of such a reduced level that phase current sensing will not respond or will have a delayed response until the fault morphs into a bolted fault due to local ionization of the air. A ground fault sensing scheme has traditionally been applied to fill the gap to avoid delayed fault clearing response, or no response, to a line-to-ground fault. These faults tend to be arcing faults, and due to the high impedance of the fault the current drawn may be closer to a load or overload current than a short circuit current value. This delays clearing and results in high arc-flash incident energy hazards.

Circuit Breakers Vol.1 Application of ground fault tripping schemes and/or high resistance grounding can be very effective at reducing arc-flash hazards. Again, the importance of correct installation and testing of the ground fault protection is crucial for safety. Manufacturer’s drawings and literature should be thoroughly examined to confirm the available and as-installed schemes and the test procedure. The manufacturer will provide detailed test procedures for testing these ground fault protection schemes. These schemes may require disabling the ground fault protection while performing phase fault trip testing. Following are some test techniques that can be applied to verify ground fault tripping integrity. When nuisance tripping occurs or needs to be investigated for a ground fault scheme, a likely cause is existence of a false ground trip signal. This can result if the scheme is using three summing CTs and the CTs do not have identical electrical characteristics, the same ratings, and/or the same tap settings. Another condition that may cause a false trip is a disconnection between a sensor and the trip unit. Point-to-point wiring checks should be made using the manufacturer’s wiring drawings. The sensors can also be verified by measuring and comparing their resistance values. Typical sensor resistance ranges are generally provided in the manufacturer’s literature; however, all sensors of the same rating should have similar resistance. Modern technology is now reaching beyond improved circuit breaker operating speeds and improved current tripping methods (ground fault and adjustable instantaneous trip functions) seeking alternate protection schemes or sensors. Solid-state trip circuit breakers can be tested by secondary current injection or primary current injection. Secondary current injection testing only tests the solid-state trip unit. In order to test and verify the integrity of the entire protective device, primary injection should be used. This verifies integrity of current sensors, wiring, and breaker current interrupting components. Where critical systems are concerned, review of the design, application, and test methods applied should be comprehensive and uncompromised. When using secondary injection test methods, it is important to verify the manufacturer’s procedures. Many times settings need to be adjusted to specific values for testing. In some cases, specific separation is required between trip function settings in order to achieve valid test results. Always record as found settings and trip flags prior to testing and reconfirm that settings and trip devices have been correctly reset. In the case of relays, reading the initial as-found setting file and reading the as-left setting file should be performed and printouts or file comparison utilities used to confirm the settings have been left in the proper condition and to be able to provide a documented record. Modern technology has spawned protective devices with an ever increasing list of settings and configuration parameters that need to be set or documented as not used. Not long after the codification of arc-fault hazard protection requirements appearing in the National Electrical Code, a new term, reduced energy let-through was coined. This is characterized with two independent instantaneous settings being installed,

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Circuit Breakers Vol.1 the normal condition setting and the maintenance condition setting. Thus, testing techniques need to address verifying this new scheme applied as another means to reduce arc-flash hazards. In this case, the alternate setting may be initiated and disabled by a local switch, via communication using an output contact, or by a remote switch. This is sometimes referred to as an arc-flash switch or a maintenance switch. In some cases a flashing indicator is used to signal that the alternate setting is engaged, and this indication becomes part of the scheme verification requirement. Either way, the alternate setting should be disabled after testing and the system placed into normal protection mode. Verification of this reinstatement should be part of the test documentation. Instantaneous zone selective interlocking is another new protection scheme that is gaining more application momentum due to its ability to address arc-flash hazard. There are various zone interlocking schemes. However, they generally interlock upstream and downstream circuit breakers via a communication link. This allows overlapping of instantaneous trip functions while not sacrificing selectivity. Thus, this is a win-win as it allows lower instantaneous settings to be applied to reduce arc flash hazard while also improving selective coordination via a communication link. Test techniques need to simulate faults simultaneously for the upstream and downstream device in order to prove the desired selectivity is achieved. These schemes typically utilize a three- or five-wire system to communicate phase and ground fault conditions in the zones. If a fault is seen by the downstream device and if it exceeds the short time pickup, it signals the upstream device to block high speed tripping that may occur from the instantaneous setting. If the downstream device fails to trip for a fault, the upstream device will override the blocking signal and trip instantaneously applying a slight (3-cycle) delay. One of the most recent technological advances is the application of an arc fault sensor to initiate tripping to compliment the current sensing / tripping devices. This sensor operates by detecting an arc-flash light signal when an arc flash occurs and then initiates a fast trip using fiber optic communications. Several relay and circuit breaker manufacturers have systems on the market. Testing of this protection scheme can be performed using a standard relay test set to initiate a trip. It is necessary to secure an optical fault sensor that can be used with the relay test set as the pickup device to detect the arc-flash event. A flash device is used to simulate the arc-light so that the pickup device can actuate and send a trip signal. Where practical, the arc light simulator should be used to signal the actual installed arc-flash pickup devices to verify system integrity. These systems are easily deployed using multiple arc sensors.The advantage of this new arc-flash detection technology is that an arc-flash event can be detected and a trip can be initiated in as fast as two ms (1/8 of a cycle).

Fig. 2: Arc-Flash Protection Device Test Setup It is important to keep in mind that current-limiting is desirable. However, this requires use and application of a verified UL 489 current-limiting circuit breaker (or a fused low-voltage power circuit breaker). In this case it is imperative to maintain the circuit breaker in order to maintain operating times and validate arc-flash hazard calculations. Although many times circuit breakers are applied that are not current limiting, endeavoring to reduce fault clearing time is desirable. This can be achieved by conducting periodic testing and maintenance and application of new technology. Achieving faster operating times of the trip devices and the circuit breakers will result in safer installations by reducing the arc-flash hazard. As technology continues to drive rapid change, it is increasingly difficult, and yet vitally important, to keep up with the latest test methods and equipment characteristics. Bruce Rockwell holds an MBA from Monmouth University, West Long Beach, New Jersey, and a BSEE from New Jersey Institute of Technology. Bruce has 30 years of engineering experience working for electrical equipment manufacturers and electric utility companies and operating CTI Power Systems. He has extensive experience in the design of T&D substations, industry, utility, and commercial power systems. Bruce routinely performs engineering studies and forensic engineering investigations of failed equipment. Bruce is also a New Jersey State certified continuing education instructor for electrical contractors, having developed over forty topic-specific training courses. Currently Bruce is the Director of Engineering at American Electrical Testing Company, Inc. and is a member of IAEI, IEEE, NFPA, NJECA, and NSPE.

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VACUUM INTERRUPTERS: PRESSURE VS. AGE A STUDY OF VACUUM LEVELS IN 322 SERVICE AGE VACUUM BREAKERS PowerTest 2016 John Cadick, P. E., and Gabrielle Garonzik, Cadick Corporation John Toney, Jerod Day, and Finley Ledbetter III, CBS ArcSafe, Inc.

INTRODUCTION Since the first large influx of equipment and breakers into the market based upon vacuum interruption in the early 1970s, the technology has become the most widely applied power interruption technique in the medium-voltage range (2.4kV - 38kV). Vacuum technology now dominates the interrupter market throughout the world. There are millions of vacuum circuit breakers installed and probably on the order of 10 million vacuum contactors. There are hundreds of thousands of vacuum breakers and contactors in the field that were manufactured twenty or more years ago. The question arises as to how long these VIs manufactured many years ago will maintain the vacuum level required for proper operation. All vacuum interrupters (VIs) increase in internal pressure over time. [Authors’ note: In this paper the modern term vacuum interrupter will be used in lieu of the now obsolete vacuum bottle.] The pressure increase may be due to small, long-path leaks from outside to inside, diffusion through the container materials and/or virtual leaks from materials within the internal volume. VI manufacturers design and test their vacuum interrupters for a minimum lifetime of twenty to thirty years. VIs may successfully operate beyond this period but it is beyond their design life. With the large number of VIs in the field which were manufactured over 20 or 30 years ago it seems likely that in-service VI failures caused by vacuum loss have greatly increased over the last 10 years. As part of their vacuum breaker maintenance routine manufacturers recommend a vacuum integrity test. This test consists of applying an AC power frequency rated voltage across the terminals of a VI at its rated gap. If the VI is able to withstand the voltage for the manufacturer specified length of time the VI is deemed to have good vacuum. Passing this test indicates that the VI vacuum is sufficient to successfully interrupt a fault but gives no indication of how close the VI is to having a vacuum level which would cause it to lose its capability for clearing a fault. Until recently there was no technology that allowed field testing vacuum levels in VIs. Using a field portable magnetron, test technicians can now test vacuum level and thereby evaluate the VI condition based on that parameter. The vacuum level test is called the Magnetron Atmospheric Condition (MAC) test. To further study the effect of VI age on its vacuum level, the authors performed vacuum level, as well as other, tests on 815 VI’s

installed in over 300 same type and manufacturer vacuum circuit breakers, covering a range of ratings, service histories manufacturing dates, etc. The breakers had nameplate manufacturing dates ranging from 1978 through 2014. It was assumed that the VI manufacturing dates were the same as the breakers in which they were installed due to sequential serial numbers. This paper describes the data gathering and analysis methodology, summarizes the results of the analysis, and discusses an interpretation of those results. Before describing our measurements and analyses, brief descriptions of vacuum insulation, methods of evacuating and sealing VIs, sources of leaks in VIs and how a magnetron tester determines the vacuum level in a VI are given below.

VACUUM LEVEL VS. INTERRUPTING RATING From Paschen’s Law (Louis Karl Heinrich Friedrich Paschen 1865-1947) we know that the dielectric strength between two electrodes is a function of the pressure of the gas between them.



Fig. 1: Paschen Curve for Dry Air

Figure 1 shows Paschen’s Law applied to dry air in a volume containing electrodes at spacing typical of those in a vacuum interrupter. The horizontal axis is the air pressure in Pascal’s (Pa), and the vertical axis is the dielectric strength in kilovolts per centimeter of electrode separation. As the pressure in the interrupter is decreased from one atmosphere (≈1x105 Pa) the dielectric strength first drops to a very low level. Then, at around 10 Pa the dielectric strength starts to rise. At 10-2 Pa the dielectric strength has reached slightly less than 400 kV/cm and remains constant for all lower pressures.

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Circuit Breakers Vol.1 Although manufacturer design specifications vary slightly, most newly made VIs have internal pressures in the range of 10-4 Pa to 10-7 Pa; however, all VIs leak to some degree, and as the pressure rises, the dielectric strength will start to decrease when the pressure exceeds approximately 10-2 Pa. At 10-1 Pa, the dielectric strength decreases rapidly.

METHODS OF EVACUATION AND SEALING OF VIS The construction and sealing of the enclosure which provides the high vacuum environment for the inner workings of the VI is achieved in one of 2 ways depending on the materials of which it is constructed. VIs constructed of glass cylinders generally have metal flanges embedded on either end which permits their TIG welding to each other and to metal endplates to which the contact support structures and a copper tubulation has previously been brazed. In order to evacuate the VI, the tubulation is connected to a multistage vacuum system and pumped while baking the assembly at several hundred degrees. After achieving the required level of vacuum the VI tubulation is “pinched off” leaving a stub denoted as the pinch off tube.

“gas evolved from the bulk of the material was the major contributor to pressure buildup.” 3 Improved manufacturing techniques have significantly reduced this type of leak by selecting well-refined, low gas content materials and by fully degassing parts in the production process of the vacuum interrupter. 4 Real leaks are gases penetrating the interior of the vacuum interrupter through microscopic paths caused by manufacturing defects, mechanical damage, corrosion, and/or external flashover. With the exception of corrosion, the rate of internal pressure increase caused by real leaks is much greater than leaks caused by gas permeation and virtual leaks. Most real leaks cause failure due to inadequate vacuum in a short period of time. Corrosion can result in a slower leak which can take as long as a year to compromise the integrity of the vacuum.1 As vacuum interrupters age, a combination of the described factors cause an increase in internal pressure and, depending on the environmental, circuit, and mechanical conditions, may increase faster or slower for a given vacuum interrupter.

TESTING VACUUM LEVEL

VIs constructed of ceramic cylinders do not have metal embedment’s; rather, the ends are ground flat and metallized such that properly designed metal endplates (to which contact support structures have been previously brazed) can be brazed to their surfaces. In this type of construction the VI is evacuated and sealed in the same furnace and the same time that the ceramic cylinder(s) is brazed to the endplates. In this type of design there is no pinch off tube.

LEAKS IN A VACUUM INTERRUPTER The internal pressure of a vacuum interrupter can be increased by three main causes: gas permeation, virtual leaks, and real leaks. Gas permeation is the infiltration of gases into the vacuum interrupter volume through the insulation material and metallic surfaces by diffusion. Only very small molecules, such as hydrogen (H2) or helium (He), can diffuse through these materials. The upper limit of the internal pressure that can be attained by diffusion is in the range of 10-2 Pa.1 To help control the pressure increase from these leaks, a getter material is normally mounted inside the vacuum interrupter which provides a continuous pumping for low levels of H2, N2, O2, and other various residual gases. 2 This getter material is activated by high temperatures during the final stages of the vacuum interrupter manufacturing process and will function until the getter surface has been saturated with gas molecules. Note that the getter is ineffective at pumping inert gases such as helium or argon. Virtual leaks are the results of outgassing from internal surfaces and parts as well as diffusion of gases from “trapped” volumes (from poor brazes or welds) to the main VI volume. Research performed on one type of vacuum interrupter in 1978 showed that

Fig. 2: Penning Discharge Principle Determining the pressure in an enclosed, sealed chamber is done using a test based on the Penning Discharge Principle. (Frans Michel Penning 1894-1953) Penning showed that when a high voltage is applied to open contacts in a gas and the contact structure is surrounded with a magnetic field, the amount of current flow between the plates is a function of the gas pressure, the applied voltage, and the magnetic field strength. Figure 2 is a diagram of the test.

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A magnetic field is set up by placing the VI into a field coil. The field is created by a direct current and remains constant during the test. A constant DC voltage, usually 10 kV or greater, is applied to the open contacts and the current flow through the VI is measured. Since the magnetic field and the applied voltage (DC) are both known, the only variable remaining is the pressure of the gas. If the relationship between the gas pressure and the current flow is known, the internal pressure can be calculated based on the amount of current flow. The test equipment used to perform this procedure is called a magnetron. Until recently, the magnetron was very bulky and difficult to use in the field. It was, therefore, relegated to manufacturer laboratory testing. In recent years, more portable equipment has become available and the vacuum level can be readily tested in the field. Figure 3 shows such a test set up. Note that this configuration does not require removal of the pole assembly from the breaker.

EXPERIMENTAL METHODOLOGY Test Population The 322 circuit breakers were all the same model and from the same manufacturer but included a range of ratings and VI types. All of the breakers had been in actual service. None of the breakers or interrupters had been modified from the manufacturer’s original specifications with the exception that some of the breakers had 1 or 2 VIs missing. The total number of VIs tested was 815. One manufacturer was used to eliminate any statistical differences that might occur due to different manufacturing methods. Future tests will be performed on other manufacturers and the differences, if any, will be noted.

Test Procedure 1. Document the condition of the breakers and all components visually using digital photography. Note any differences and classify pinch tubes if present. 2. Record all nameplate information. Take high resolution digital photos. 3. Thoroughly clean all dust and contaminants from the breaker 4. Check primary contact erosion 5. Perform contact resistance tests 6. Perform MAC Test 7. Perform AC High Potential Test and measure/record leakage current at the recommended test voltage.

COLLECTED DATA

Fig. 3: VI Vacuum Test (MAC Test)

OBJECTIVES As the data collection and testing progressed it became clear that we had five basic objectives in mind: 1. What, if any, correlation exists between the VI age and its internal pressure. 2. What, if any, correlation exists between the VI age and its AC HiPot test results. 3. What, if any, correlation exists between the VI age and its contact resistance. 4. What, if any, correlation exists between the VI vacuum level and the AC HiPot results. 5. Do the AC HiPot test results have any predictive value as far as the VI serviceability is concerned or is the AC HiPot strictly a go no-go test?

Nameplate data collected for all circuit breakers includes manufacturer, breaker type, serial number, rated max voltage, impulse voltage, rated amps, cycles, hertz, rated voltage range, close and latch compatibility, date of manufacture, close coil details, trip coil details, connection diagram, mechanism type, vacuum interrupter type, phase serial numbers, phase pinch tube details, and weight. Inspection data collected includes the breaker mechanical operations before and after testing, ambient temperature, humidity, and the technician ID. Test data collected for each of the three phases includes the MAC Ion Current, Contact Gap, Contact Resistance, AC HiPot Test (pass/not pass and the leakage current), and Contact Time Open and Close results. Approximately ten percent of the tested population (84 out of 815) exceeded the maximum pressure measurable with the MAC tester (~5 x 10E-1 Pa – high pressure). These units were not included in the analysis since our analysis method requires continuously variable data. The percentage of VIs with high pressure increases with VI age as illustrated below:

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Age (Years)

High Pressure

Measurable Pressure

1 – 10

4%

96%

11 – 20

3%

97%

21 – 30

7%

93%

> 30

20%

80%

Table 1: VI Percentage of High Pressure Increases by Age

the internal pressure. The MAC test measures the current generated by ionized gas molecules inside the vacuum interrupter and converts this value to a pressure using formulas (curves) based on experimental data. A set of curves was produced to maintain a high degree of accuracy when testing VI’s of different diameters. Vacuum interrupter manufacturers use the same procedure when performing quality control tests on new vacuum interrupters. For the calculations, a normalized MAC Pressure result in Pascals was used. Of those 815 vacuum interrupters, 772 were also given a High Potential test for comparison.

DATA ANALYSIS

Data Distributions

Correlation of Data Sets

Figures 4 through 7 are scatter plots of the various comparisons performed in the analysis of the VI data. Correlation coefficients were calculated for each of the data sets that are shown with the curve fits most commonly found in nature, including linear, logarithmic, exponential, square, and square root distributions. Each graph has a note indicating the best fit distribution.

The correlation coefficient (r) measures the direction and strength of the linear relationship between two quantitative variables. It is computed as follows:

Where: r is the correlation coefficient n is the sample size x and y are the independent and dependent variables respectively x and y are the means of x and y Sx and Sy are the standard deviations of x and y Due to the small sample size, we performed an additional calculation to offset any bias, seen here:

Where: radj is an unbiased estimator or r. Note that for large values of n, radj = r.5

PROPERTIES ●● For r > 0, there is a positive relationship between x and y; that is, when x increases, y increases. For r < 0 there is a negative relationship between x and y; that is, when x increases, y decreases. ●● Correlation is always a number between -1 and 1. Values near -1 or 1 indicate a strong relationship and values near 0 indicate a weak relationship. ●● The square of the correlation coefficient, r2, is the fraction of the y values whose variance can be explained by a change in x. ●● As with mean and standard deviation, r is heavily influenced by outliers.

DISCUSSION OF RESULTS A Magnetron Atmospheric Condition test (MAC) was performed on 815 vacuum interrupters of varying age to determine

Table 2: Correlation Coefficient Calculations

Divisions within Data

To ensure a homogeneous data set, the correlation coefficients of MAC Pressure values and the age of the vacuum interrupters for the entire sample and for subgroups designated by VI Type, MVA, Mechanism Type, and Pinch Tubes were computed. None of these divisions had a significant impact on the strength of the relationships. All results are for the VI sample as a whole.

Relationships In addition to the MAC Pressure and VI age relationship, correlation coefficients were calculated for AC HiPot results versus VI age, Contact Resistance versus VI age, and MAC Pressure versus AC HiPot results. The strongest relationship was found to be age of the VI versus the MAC Pressure values, with an unbiased exponential correlation coefficient (radj) of 0.4107. This is a much stronger relationship than the 0.1195 radj value for AC HiPot test results versus VI age. As more time-related data becomes available we expect the individual VI curves will more closely follow the exponential change. This will lead to larger correlation coefficients.

MAC Pressure and Age In Figure 4, there is an exponential rise in pressure values over time. The increased spread in pressure values for the older VIs is expected. We believe additional tests over time of the same sample VIs will reinforce the relationship between MAC Pressure results and age. This would remove much of the variance caused by both environmental and internal variables.

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Circuit Breakers Vol.1 SUMMARY Tests were performed on 815 service-aged vacuum interrupters from the same manufacturer, of similar design, and of similar type with a range of manufacture dates from 1978 to 2012. The tests performed were the contact resistance, ac high-potential test, and MAC tests. After the data was compiled correlation calculations were made for the following: ●● VI pressure (Pa) versus VI age Fig. 4: Exponential Distribution of Internal Pressure vs. VI Age where radj = 0.4107 and r2 = 16.87%

AC HiPot and Age

●● AC leakage (mA) (HiPot) versus VI age ●● Contact resistance (μΩ) versus VI age ●● AC leakage(mA) (HiPot) versus VI pressure (Pa) Figure 8 shows a bar graph of the VI pressures grouped by age. Three variables were not factored into the final calculations. Numbers of Operations: The numbers of operations were captured in the dataset and preliminary correlation calculations were made against the other variables. Based on these results it was decided not to factor numbers of operations into this study.

Fig. 5: Exponential Distribution of AC HiPot vs. VI Age where radj = 0.1195 and r2 = 1.43%

Contact Resistance and Age

In-Service Ambient Conditions: There was no way to qualitatively or quantitatively include variations of in-service ambient conditions. It is possible, though by no means certain, that wide in-service temperature extremes could increase the VI leakage rate. This is being looked at and considered for a future iteration of this research. Time-Related Data for Individual VIs: No data was available for individual VIs with respect to time prior to the present study. Our Condition Based Maintenance research has shown that inclusion of individual time-based data greatly improves the quality of the statistical analysis. We have isolated ten of the breakers from the present study to be fully reevaluated in a five year period. This will help to establish important leak rate information for the VIs being tested and provide a means for projecting failure due to internal pressure rise.

Fig. 6: Exponential Distribution of Contact Resistance vs. VI Age where radj = 0.3173 and r2 = 10.07%

MAC Pressure and AC HiPot

Fig. 7: Linear Distribution of Internal Pressure vs. AC HiPot where radj = - 0.0362 and r2= 0.13%

Fig. 8: VI Pressures by Age Group

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Circuit Breakers Vol.1 CONCLUSIONS We have drawn the following conclusions from our research: 1. There is a relatively close, exponential correlation between VI age and internal pressure. We believe that this correlation will be strengthened by an increase in the size of the database and inclusion of time-related data for individual breakers. 2. There is a small to moderate correlation between the contact resistance and VI age. 3. There is a minimal correlation between AC HiPot test and VI age. 4. There is very little correlation between AC HiPot leakage current results and internal pressure. Given the proven relationship between dielectric strength (interrupting ability) and vacuum level, we are confident in offering the following: 1. The MAC test (VI internal pressure) provides excellent predictive data for determining VI continuing serviceability. The MAC test should be considered as an important tool in the breaker maintenance tool bag. 2. Contact resistance testing may provide some value as a predictive tool; however, there are two significant issues that must be accounted for. • Frequent contact erosion adjustments must be accounted for. For example, the interrupter contact pressure can change with wear/interruption history. • The significant differences in contact area (a 400 ampere VI versus a 3000 ampere VI) must be accounted for. 3. Since there is very little correlation between AC HiPot leakage current and VI age or vacuum level, the high-potential test is of no value in any predictive maintenance program for the VI. We recommend using the AC HiPot test for evaluating the current functioning of the VI as well as the other insulation systems in the breaker. However, the addition of the MAC test will provide a means of actually estimating the remaining vacuum life of the VI and is a valuable tool in selecting which VIs are due for replacement.

APPENDIX Glossary Correlation Coefficient (r): a number between −1 and +1 calculated so as to represent the linear dependence of two variables or sets of data. Correlation Coefficient squared (r2): a value which represents the fraction of the variation in one variable that may be explained by the other variable. Getter: A deposit of reactive material that is placed inside a vacuum system for the purpose of achieving and maintaining operating vacuum levels. Vacuum Interrupter: A current interruption device in which the interrupting contacts are enclosed in a vacuum.

REFERENCES R. Renz, D. Gentsch, P. Slade, et al. “Vacuum Interrupters – Sealed for Life,” Paper 0156, 19th Int. Conf. of Electr. Distr. (CIRED), May 21-24, 2007. 1

Paul G. Slade, The Vacuum Interrupter: Theory, Design, and Application. (Boca Raton: CRC Press, 2008).

2

M. E. Arthur, M. J. Zunick, “Useful Life of Vacuum Interrupters,” Power Apparatus and Systems, IEEE Transactions on, Vol. PAS-97, No. 1 (Jan. 1978):1, 7. 3

M. Okawa, T. Tsutsumi, T. Aiyoshi, “Reliability and Field Experience of Vacuum Interrupters,” Power Delivery, IEEE Transactions on, Vol 2, No.3, (July 1987):799, 804.

4

David S. Moore, George P. McCabe, Introduction to the Practice of Statistics, 4th ed., (New York: W.H. Freeman and Company, 2003).

5

John Cadick is a registered professional engineer and the founder and president of the Cadick Corporation. He has specialized for over four decades in electrical engineering, maintenance, training, and management. Prior to creating the Cadick Corporation, he held a number of technical and managerial positions with electric utilities, electrical testing companies, and consulting firms. In addition to his consultation work in the electrical power industry, Mr. Cadick is the author of Cables and Wiring, DC Testing, AC Testing, and Semiconductors published by Delmar. He is also principal author of The Electrical Safety Handbook (published by McGraw Hill) and numerous professional articles and technical papers. Mr. Cadick has a BSEE from Rose-Hulman Institute of Technology and an MSE from Purdue University. John Toney, trained as an electrical engineer, has specialized for over thirty years in the design, development, testing and manufacture of vacuum interrupters for vacuum circuit breakers. He spent the majority of his career in the vacuum interrupter design department for the General Electric Corporation and is currently a design engineer for Vacuum Interrupters Inc. His undergraduate degrees are from University of Michigan—Ann Arbor (BS in Astronomy and BSEE) and his master’s degree is from Drexel University—Philadelphia (MSEE). Finley Ledbetter is the Chief Scientist for Group CBS Inc. with over 35 years of power systems engineering experience, a member of the IEEE, and past president of PEARL.

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THE CRITICALITY OF CIRCUIT BREAKER: TESTING MILLISECOND PERFORMANCE MATTERS – A LOT NETA World, Winter 2013 Issue Elsa Cantu, Megger

Unequivocally, one of the most important components of a substation is the circuit breaker. The circuit breaker is critical to saving the life of expensive equipment as well as the lives of workers operating on or around that equipment. The circuit breaker is normally idle, allowing for continuous current flow. But when the circuit breaker is called upon to operate, as in the case of a power surge, it must trip or open the circuit within milliseconds. This criticality demands meticulous testing and maintenance.

CIRCUIT BREAKER TYPES There are many types of circuit breaker designs. These are usually classified by the insulation media used to extinguish the arcing during open/close operation: vacuum, sulfur hexafluoride (SF6), oil, and air blast. Vacuum circuit breakers can be used for up to 70 kV. They utilize a vacuum as insulation between the main contacts when the circuit breaker is opened. These breakers have two contact plates inside a vacuum bottle that are separated by a very small distance, usually between 11-17 mm. SF6 circuit breakers are used for medium voltages up to 1100 kV. There are two main types of SF6 circuit breakers, self-blast and puffer. Both types use SF6 gas to blow over the arc, cooling and extinguishing it. Self-blast circuit breakers use the energy of the arc to generate pressure to blow out the arc. The puffer type generates its own pressure to blow out the arc, thus requiring a larger mechanism. SF6 circuit breakers can be of either live tank or dead tank design. In live tank circuit breakers, the interrupter is housed in a tank that is at line voltage. One of the advantages of live tank circuit breakers is that only a small amount of SF6 gas is used because there is no need to insulate from high voltage to a grounded tank.

Fig.1: Live tank SF6 circuit breaker In contrast, dead tank circuit breakers house the interrupter in a grounded or dead tank. Because these require insulating from the high voltage to ground, they use much more SF6 gas than live tank circuit breakers. Since the interrupters and the bulk of the weight are closer to the ground than live tank circuit breakers, dead tank circuit breakers are commonly used in high seismic areas. Live tank breakers require standalone circuit breakers while dead tank breakers have the circuit breakers mounted directly on the breaker over the bushings. In the U.S. the majority of SF6 circuit breakers are dead tank although live tank is becoming more common. In Europe only live tank style breakers are used for high voltage applications.

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should be performed at various intervals. Consult the manual or manufacturer specifications for the proper testing intervals. Generally, the maintenance tests should be performed every three to five years for routine maintenance. Circuit breakers manufactured within the past five years require less maintenance. As a result the manufacturer recommends testing and maintenance based on the number of operations rather than time intervals. It is very important that the circuit breaker be tested after it has seen a severe fault or if it is suspected of faulty operation.

COMPONENTS THAT REQUIRE TESTING Although there are a variety of tests that can be performed on a circuit breaker, the focus should be on three main components: insulation, conduction, and operation of the breaker. Fig. 2: Dead tank circuit breaker Oil circuit breakers use oil to quench the arc and extinguish it. Oil circuit breakers are slowly being phased out and replaced by SF6 circuit breakers. Although they are no longer manufactured, there are still a large number in the field that require testing and maintenance.

SAFETY Safety is always the number one priority at a substation. The circuit breaker should be isolated and grounded before testing begins. When possible, take advantage of equipment that allows testing of the circuit breaker while it is grounded on both sides to minimize risk of electrical shock. The operating mechanism can store energy and voltage levels up to 480 V in the control cabinet, so caution must be used when working inside the control cabinet or mechanism housing. When testing with high voltages, all personnel must stay clear of the circuit breaker. National, state, and local safety practices must always be observed when working in a substation.

TESTING INSULATION

Fig.3: Oil circuit breaker Air blast circuit breakers are older and another once common design that is longer manufactured. Air blast circuit breakers used air to blow over the arc and extinguish it, requiring many very noisy breaks-per-phase.

THE IMPORTANCE OF TESTING CIRCUIT BREAKERS A circuit breaker should be tested many times throughout its life. The benchmark tests are performed at the factory before the customer receives the circuit breaker. Once the circuit breaker is delivered, it should be tested before being put into service. This is known as a commissioning test. After the circuit breaker is commissioned and put into service, there are additional tests that

Insulation can be tested using a variety of methods. A common practice is to perform a dc insulation-resistance test. When performing this test, close the circuit breaker and test from one phase to the other and also from each phase to ground. Open the circuit breaker; test from one pole to the other on the same phase; and repeat for the other two phases. In addition to the dc resistance test, a power-factor test can be performed. When performing this test, one should obtain the same nine measurements that were taken with the dc insulationresistance test. A high potential test can also be performed, but this is more commonly performed in a factory rather than in the field. Although these tests can be performed on all circuit breakers, additional tests can also be performed depending on the type of circuit breaker. For vacuum bottles, check the vacuum integrity with a high potential tester. This is a go/no-go (pass or fail) test. For oil circuit breakers, take an oil sample to test the quality of the oil. For SF6 circuit breakers, take a gas sample to test for purity and moisture in the gas.

TESTING CONDUCTION The circuit breaker spends most of its life in the closed position letting current flow through its contacts. In order to efficiently transmit electricity, it needs to have very little contact resistance, typically in the low hundreds of microhms to under a hundred microhms. To test the resistance, a microhm meter should be used.

88 This test may also be referred to as a digital low resistance ohm meter (DLRO) or DuctorTM test. The basic principle is to inject a dc current, measure the voltage drop, and then calculate the resistance. IEEE standard C37.09 states that the resistance should be measured with at least 100 A, but should not exceed the current rating of the circuit breaker. The test should be performed on each phase individually with the circuit breaker in the closed position. The values should meet the specifications indicated by the manufacturer. If the manufacturer’s specifications are not available, compare the values from phase to phase and look for a deviation.

TESTING OPERATION To ensure the breaker is opening and closing correctly, a time and travel analyzer should be used. Important parameters to measure are the contact opening and closing times of the circuit breaker, the travel length or stroke of the circuit breaker, and the velocity of the interrupter. A few things to consider for time and travel analysis are the number of breaks per phase of the circuit breaker, the number of operating mechanisms, and the type of transducer(s) needed.

MEASURING TIMES There are five different times that should be measured with the analyzer: close, open, close-open, open-close and open-close-open. The close time is the elapsed time between the close coil seeing voltage and the first metal-on-metal contact of the circuit breaker. When measuring the close time of the circuit breaker, be aware of the X-Y relay scheme in the control circuit. Since the closing time is measured from the instance when the close coil sees voltage, subtract the pickup time of the X relay from the total elapsed time to ensure just the closing time is being determined. The open or trip time is the elapsed time between the open coil seeing voltage and the last metal contacts of the circuit breaker separate. The close-open time, also known as the dwell time, is the duration that the metallic contacts are touching when performing a close operation followed immediately by an open operation. Note: the open operation should be initiated during the close operation. A common practice is to send the open pulse 10 ms after the close pulse has been initiated at time zero. The purpose of the close-open test is to make sure the circuit breaker will still be able to open and interrupt current after it closes in on a fault. The open-close or reclose test records the time it takes for the contacts to separate and touch again on an open operation, followed by a close operation after a short delay of 300 ms. It should be noted that the 300 ms delay is the minimum and that this can be set for a longer interval if desired. During normal operation of the circuit breaker, a reclose may be utilized when the circuit breaker sees a temporary fault such as a lightning strike. The fault will occur, and the circuit breaker will trip to clear it. Shortly afterwards, the circuit breaker will ”reclose”. If the fault is gone, then the circuit breaker will stay closed. If the above scenario occurs, but the fault is still on when the circuit breaker recloses, then the circuit breaker will need to trip one more time and stay in the open position. This function is checked by the open-close-open test.

Circuit Breakers Vol.1 X-Y RELAY SCHEME The X-Y relay scheme, also known as the antipump circuit, is in the control circuitry for the close operation to prevent the circuit breaker from closing immediately after it opens. When this occurs, it is referred to as pumping the breaker and, depending on the design, this can cause severe damage. When the X-Y scheme is in the circuit, the X relay must pick up before the close coil can be energized. Once the circuit breaker is closed, the Y relay picks up and cuts off power to the X relay. The Y relay is then continuously energized until the close pulse is removed. This is known as a selfsealing contact. In order to close the circuit breaker again, power must be removed from the Y relay. A typical X relay will add 10-20 ms to the close time of the circuit breaker.

TRANSDUCERS The type of transducer is dependent on the design of the circuit breaker. The two common types of transducers are linear and rotary. Although the manufacturer of the circuit breaker should always be consulted, there are a few generalities that often apply. For live tank circuit breakers, it is common to use a rotary transducer. For dead tank circuit breakers and bulk oil circuit breakers, it is more common to use a linear transducer. For vacuum circuit breakers, try to hook up a small linear transducer to the bottom of the vacuum bottle. Please note that these are general guidelines and each circuit breaker should be evaluated for the best transducer connection. There are also circuit breakers for which either a linear or a rotary transducer can be used. When a rotary transducer is used, the stroke is measured in degrees, so a conversion table is needed to determine the linear measurement of the stroke. Contact the circuit breaker manufacturer to obtain the appropriate conversion table for the circuit breaker. If no conversion table is available, make a measurement with a transducer and use this as a footprint from which to compare future measurements. Record stroke values in degrees and speed values in degrees per second.

Fig. 4: Motion transducer

89

Circuit Breakers Vol.1 TRAVEL CURVE PARAMETERS There are multiple parameters that can be obtained from the travel curve. Some of the most common to analyze are stroke, overtravel, rebound, penetration and undertravel. The interrupter velocity is also calculated from the motion trace. The stroke is the distance that the interrupter travels from its initial resting position before the operation to its final resting position after the operation. Overtravel is measured on the close operation and is the maximum distance that the interrupter travels past the closed position. Rebound is the distance that the interrupter returns past the closed position after an overtravel. Penetration or wipe is the distance from the point at which the contacts first touch until the final closed position. Undertravel is measured on the open operation and is the maximum distance that the interrupter travels past the open position. Some circuit breakers are equipped with a dashpot that can be adjusted if the overtravel or undertravel is too large.

CALCULATION POINT SPEED There are several different references that can be used to determine the speed of the contacts. A few examples are percentage of stroke, distance below closed or above open, contact touch or separation, and time before or after the reference point. Always refer to the manufacturer’s guidelines for the proper reference points. If no information is given, the points will have to be chosen by the person carrying out the test. When choosing speed calculation points, one has a few things to consider. Make sure the reference points are on the linear portion of the travel curve and measure the speed in the arcing zone of the circuit breaker. Some standard reference points are contact touch for the upper point and 10 ms before upper point for the close operation; and for the open operation, contact separation for the upper point and 10 ms after upper point for the lower point.

RECOMMENDED ADVANCED TESTS For an SF6 circuit breaker, performing a dynamic resistance measurement (DRM) to evaluate the arcing contacts of the circuit breaker is recommended. To perform this test, make a microhm measurement while operating the circuit breaker. By evaluating the change in resistance values, obtain the start of main contact movement, main contact separation, and arcing contact separation. The distance between main contact separation and arcing contact separation is the length of the arcing contact. As the breaker ages and sees more interruptions, the arcing contacts can wear out. DRM analysis will allow evaluation of the arcing contact without dismantling the breaker for inspection. An increasingly popular test, the first trip test records the coil current trace of the trip coil when pulling the circuit breaker out of service. The coil trace is analyzed and compared to previous values to reveal the condition of the trip coil and trip latch. Special caution must be observed because the breaker is online during this test. Modern techniques can

also be applied to test a circuit breaker with both sides grounded. This can be very beneficial in gas insulated switchgear (GIS) with an integrated isolating and grounding switch. The adjacent breaker often needs to be deenergized to properly isolate it from line voltage when removing the ground on one side of a GIS breaker. With certain dual ground methods, the breaker can be left grounded on both sides while the test is performed. This allows faster and safer circuit breaker testing than possible using traditional techniques.

ANALYZING RESULTS The circuit breaker manufacturer should specify acceptable values for certain parameters such as timing and contact resistance in the manual. These values should also be trended, comparing the latest results to the previous values. A slower closing time but normal opening time can indicate that the closing latch system is binding and/or the spring is weakening. If the condition is reversed, the opening latch and/or spring should be investigated. Refer to several different standards depending on location and affiliation. For the U.S. IEEE/ANSI C37 and the ANSI/NETA Acceptance Testing Specifications can be used as a reference. Additionally, IEC 62271 can be used.

CONCLUSION Circuit breakers are critical assets in an electrical substation, as they help save the lives of expensive equipment and of workers. Circuit breakers must be maintained and tested to ensure their continued proper operation. Minimal testing involves the insulation, conduction, and operation. The recommended advanced test detailed above should be conducted when the circuit breaker is protecting critical assets or if the circuit breaker has experienced a major fault. National, state, and local safety procedures should always be followed to minimize risk to personnel and equipment. Elsa Cantu, Director of Marketing at Megger for North America in Dallas for the last six years, has more than fifteen years of experience in the electrical and electronic engineering sectors. In her present role, she is responsible for the development of efficient and effective marketing plans to support Megger’s extensive product range. This features some of the world’s most innovative test equipment for use in the power transmission and distribution sectors, including circuit-breaker analyzers, protection relay test sets, insulation diagnostic testers and cable fault locators. Before joining Megger, Elsa worked for a public utility that supplies electricity to over ten million consumers in North Texas, and for two of the USA’s largest telecommunications companies. Her educational achievements include a BA in political science, and an MBA from Our Lady of the Lake University in San Antonio, Texas. Elsa is bilingual in Spanish and English, and is a long-time member of the National Association of Hispanic MBAs.

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

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alabama 1

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

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9

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

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ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

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ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

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Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

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Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

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Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

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Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

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Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

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Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

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Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

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CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

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Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

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Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

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Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

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Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

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florida 50

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C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

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ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

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CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

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Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

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High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

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Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

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Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

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Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

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Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

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Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

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POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

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Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

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Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

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missouri 114

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Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

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new york 139

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141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

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HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

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148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

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Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

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176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

164

oklahoma

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

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189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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244

Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

ANDBOOK

VOLUME 2

SERIES lll

CIRCUIT BREAKERS

CIRCUIT BREAKERS Vol. 2 HANDBOOK

SERIES III

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CIRCUIT BREAKERS VOLUME 2

HANDBOOK

Published by

InterNational Electrical Testing Association

CIRCUIT BREAKERS–Vol. 2 SAFETY HANDBOOK TABLE OF CONTENTS Testing and Troubleshooting of Low to Medium Voltage Circuit Breakers......................5 Robert Foster and Bret Hammonds

Determining Circuit Breaker Health Using Vibration Analysis – A Field Study..............10 John Cadick and Finley Ledbetter

Diagnostic Testing Practices for SF6 Filled Dead Tank Circuit Breakers........................14 Charles Sweetser

Effects of Low Resistance Measurement Instruments on Protection and Control Devices............................................................................................20 Dinesh Chhajer and Daniel Carreno

Power Factor Testing of Gas Circuit Breakers..........................................................30 Rick Youngblood

Tank Loss Index, What is It?..................................................................................34 Rick Youngblood

A Case for Testing Medium-Voltage Breakers...........................................................37 Lynn Hamrick

Performance Testing of Ground Fault Protection Systems: Critical to Electrical Reliability and Safety for Industrial and Commercial Power Systems ................................................................................ 40 Ron Widup

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Powering Up the Latest HV Circuit Breaker Testing Technologies..........................43

Charles Sweetser

Combined Current and Voltage-Controlled Source in Arcing Contacts Condition Assessment....................................................................................45 Adnan Secic and Radenko Ostojic

The Evolution of Circuit Breakers..................................................................... 49 Paul H. Grein

Vacuum Interrupters: Pressure vs. Age...............................................................54 Finley Ledbetter

Remanufactured Low-Voltage Breakers..............................................................58 Lynn Hamrick

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Circuit Breakers Vol 2

TESTING AND TROUBLESHOOTING OF LOW TO MEDIUM VOLTAGE CIRCUIT BREAKERS PowerTest 2013 Robert Foster and Bret Hammonds, Megger

INTRODUCTION Circuit breakers are a large part of the “insurance” of an electrical system. It might even be said that they are the muscle behind the protection of an electrical system. Like an insurance policy, the purpose of a circuit breaker is to protect when needed. An insurance policy that fails to protect is of no value, just as a circuit breaker that does not serve its protective function. When something goes wrong, and an emergency condition occurs, is not the time to learn if a circuit breaker will provide the appropriate protection. At that point it is too late. The following paper presents a process by which to verify the proper operation of both low (LVCB) and medium (MVCB) voltage circuit breakers before an emergency or fault condition occurs. A perspective is given for both low and medium voltage classes of electrical apparatus based on the unique design and application of each. The definition of voltage classes can vary depending on utility and industry. However, for the purpose of this paper IEEE 100 The Authoritative Dictionary of IEEE Standard Terms, will be used to differentiate between the two voltage classes under consideration. ● Low Voltage “An electric system having a maximum root-mean-square alternating-current voltage of 1000 volts or less.” ● Medium Voltage “An electric system having a maximum root-mean-square alternating-current voltage above 1000 volts to 72,500 volts.”

CIRCUIT BREAKERS Circuit breakers range in current rating from less than one amp up to several thousand amps. Although circuit breakers are largely applied as over-current devices for the purpose of protecting the electrical system from abnormal current conditions, they can also function to isolate an electrical circuit for any number of conditions. There are two basic types of low voltage circuit breakers based on the insulating medium used in their construction: ● A molded case circuit breaker can be identified by the molded insulating material used to make its housing. This housing is used as mechanical support and to insulate energized components from the metal enclosure and personnel.

● An air frame circuit breaker will have a grounded metal frame. The conductors and contacts are electrically isolated from the frame by air and other solid insulating barriers. Similarly, medium voltage circuit breakers can also be classified in terms of their construction and insulating medium. Medium voltage switchgear that you may encounter can be Air, Oil, Vacuum, or Sulfur Hexafluoride (SF6) insulated. Most of the component parts of a low voltage circuit breaker are also common to medium voltage circuit breakers. Each of these component parts of a circuit breaker should be addressed in a periodic testing and maintenance program. The failure of any element will result in failure of the breaker. These component parts of a low voltage circuit breaker are: ● Conductive Path The path used to conduct current from the line side to the load side of the circuit breaker is the conducting path. This path will consist of load and line side connections, a conducting medium, stationary and moving contacts, and possibly current limiting fuses. A circuit breaker may have a single conducting path, or as many as three conducting paths, referred to as poles. Connections to the circuit breaker can be made with bolted connections, cables, or finger clusters. The use of bolted connections and cables is normal with molded case circuit breakers, while it is common for Modern air frame circuit breakers to use finger cluster/bus type connections. This allows the air frame circuit breaker to be removed and taken to a testing area. ● Operating Mechanism The operating mechanism of a breaker is the means by which a circuit breaker is closed and opened. The operating mechanism must be able to receive energy, store the energy and then release it to close or open the breaker contacts. ● Insulation In a molded case circuit breaker, the case forms the major portion of the insulation. This insulation forms the protective barrier between the conductors and ground and between the individual conductors. In an air frame circuit breaker, the insulation will consist of insulating arms between the mechanism and the moving contact, barriers between the phases, and insulated arc chutes.

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Circuit Breakers Vol 2

● Tripping Device (integral to LVCB’s but not MVCB’s) Besides voltage class, MVCB’s differ mainly in design from LVCB’s in that LVCB’s have an integrated tripping device, while medium voltage breakers are normally controlled through signals sent from an external tripping device that is not integral to the breaker. Therefore the circuit breaker does not rely on integrated decision making to determine when it needs to trip. MVCB’s must be told via an external relay or control signal that it is time for it to operate. While the LVCB’s have a tripping device that functions as the “brains” of the circuit breaker it can be said that MVCB’s are “dumb” devices, in that they are simply a mechanical switch that must be told what to do and when to act.

MAINTENANCE The frequency of maintenance depends on number of operations, environment and the manufacturer’s recommendations. Frequent and non-frequent operations can seriously affect a circuit breaker. Frequent operations may cause the contacts and the operation mechanism linkages to wear out. Non-frequent operations may cause the operating mechanism to become stiff and inoperable. Circuit breakers that operate in environments that are wet or dusty will need frequent maintenance. Moisture may cause the operating mechanism to corrode and freeze linkages. Moisture can also result in insulation failure. Dust increases wear on the operating mechanism, hardens lubrication, and can cause insulation to fail. Manufacturers will normally recommend a maintenance schedule in the instruction manuals for their circuit breakers.

Conducting Path The moving and stationary contacts are used for making and interrupting the circuit. The moving contact is the contact that is driven by the operating mechanism during close and open operations. The moving contact mates to the stationary contact to complete the conducting path. The condition of these contacts is important. Poor connections will result in the circuit breaker overheating or, in the worst case, contacts fusing together. If fusing should happen, the circuit breaker will be unable to respond to an open operation. The condition of the contacts is determined mainly by resistance. A low resistance ohmmeter is used to measure the resistance across the closed moving and stationary contacts. To test the conductive path of the CB the breaker must be in the closed position. A DC current is injected through the interrupter and a voltage drop is measured, from these two values, a resistance is calculated. For accurate measurements a four-wire technique is used, make sure that the voltage sensing leads are inside of the current leads. The measured value should be compared to the manufacturer’s specifications.

Insulation Insulation failure is the most serious problem that can happen to a circuit breaker. The result will be fire with loss of the circuit breaker and frequently major damage to the surrounding circuit

breakers and enclosures. It is very important that insulation be properly maintained. One measure of insulation quality is the insulation resistance test. A fixed voltage, usually DC, is applied to the circuit breaker. The leakage current is measured and a resistance value is determined by Ohm’s Law. An insulation tester will give a direct reading of the resistance value. There are up to three types of insulation tests to perform: 1. From conductor to ground 2. From conductor to conductor 3. Across the open conductor For single pole circuit breaker, the conductor to ground and the open conductor tests are performed. For two and three pole circuit breakers, all three tests are performed. For minimum test voltage recommendations see the NETA acceptance testing guidelines. For medium voltage switchgear, NETA also recommends that a Power Factor test be performed. While insulation resistance is a DC test, Power Factor is an AC test. A fixed AC voltage is now applied and the leakage current is measured. The ratio of the resistive component of the current to the total current will give you a Power Factor value. The three types of tests performed while measuring insulation resistance should also be measured while power factoring the breaker. In order to verify the integrity of the vacuum in vacuum bottle breakers an over-potential, or hi-pot, test should be performed. Either AC or DC can be applied but if DC is applied, a test set that is full wave rectified must be used in order to measure correct results. The capacitance in vacuum interrupters is very low; halfwave rectified circuits can generate a pulse up to three times the value of the applied voltage which can generate erroneous results as well as abnormal x-ray radiation.

Operating Mechanism The maintenance of the operating mechanism involves checking for loose or damaged parts, lubricating the mechanism in accordance with the manufacturer’s recommendations, “exercising” the mechanism to make sure it works, and checking tolerances. The mechanism will also checked during electrical operation and testing of the circuit breaker. As stated before LVCB’s have a tripping device whereas MVCB’s do not and thus rely on different methods to trip the circuit breaker.

Electrical Operational Testing of the Tripping Device (LVCB) Primary current injection testing is one of the methods of verifying the proper electrical operational features of a circuit breaker. In cases where a circuit breaker is not controlled by a solid state device, primary current injection may be the only way of verifying the proper operation of a circuit breaker.

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Circuit Breakers Vol 2 In cases where circuit breakers have solid state trip devices, either primary or secondary injection testing may be performed. However, primary current injection is preferable in the testing of low voltage circuit breakers because it utilizes all of the components of the primary conducting path, including CTs or transducers. Secondary signals, representative of primary currents can be used to see that the trip device is operating properly. This would be referred to as secondary injection testing. This method of operational testing is less indicative of the health of the overall operating system in the sense that it does not verify all of the integral components of the primary current path (i.e. connections, CT’s, contacts).

For example, when the pickup of a 1600 amp breaker is set to 0.75X, the overload condition starts when the current exceeds 1200 amps. The second setting is time delay. This determines how long a given overload is acceptable. For example, if a 3000 amp overload on the 1600 amp breaker will cause thermal damage to the electrical system after 200 seconds, the time delay will be set to trip the circuit breaker in less than 200 seconds. Overloads frequently occur on electrical systems. The systems are designed to withstand overloads. If the overload persists, the protecting circuit breaker must open or the system will be damaged.

The tripping device is the “brain” of the circuit breaker. It monitors the load current, compares this current to preset conditions, and if preset conditions are exceeded, sends a trip signal to the operating mechanism.

Instantaneous means that there is no intentional time delay for this function. When the current exceeds trip device settings, a trip signal is sent instantaneously to the trip actuator. This function will only have a pickup setting. Instantaneous trips are caused by faults within the protected system. Failure of the circuit breaker to clear this fault may result in severe damage to equipment. Failure also means that an upstream breaker had to trip to protect the system. This breaker tripping will result in more of the electrical system being de-energized that necessary.

All three methods are used in molded case circuit breakers. Magnetic and solid state are used in air frame circuit breakers. Thermal trip devices are used to provide overload protection. Thermal trip devices will pass a current through a heating element. As this element heats, it will deflect. When this deflection reaches a certain point, it will operate a tripping bar and the breaker will trip. The operating curve of current versus time for thermal element can be matched to the thermal characteristics for the electrical circuit being protected. The use of thermal elements is generally limited to circuit breakers in the lowest current ratings because of the heat generated. Magnetic trip devices can be used to provide overload and instantaneous protection. In a magnetic trip device, current is passed through a solenoid. If the current exceeds a preset value, the solenoid will pull a plunger. The moving action of the plunger will result in the circuit breaker tripping. The disadvantage of this method is that the solenoid is in the current path. For air frame circuit breakers with a high current this means using the current path to form a solenoid winding. This means that only a few windings could be used which results in a loss of sensitivity. Solid state trip devices have many advantages over thermal and magnetic trip devices. Among the advantages are reliability, repeatability, improved sensitivity and additional trip functions. These devices do not rely on heating or solenoids. Instead the load current is monitored though current transformers and compared to a time current curve that is stored in the memory of the device. When the time current limits are exceeded, the trip device sends a signal to a trip actuator that trips the circuit breaker. There are four trip functions commonly found in solid-state trip devices. 1. Long Time This is the overload function. There are two settings for this function. The first is pickup. Pickup determines the level of load current that is acceptable before and overload condition occurs.

2. Instantaneous

3. Short Time he difference between short time and instantaneous is that short time has an intentional time delay. This function has a pickup setting and a time delay setting. This allows the electrical system to have short duration, high current overloads. An example of this would be a motor start. 4. Ground Fault This function protects the system from insulation failures that allow higher than normal currents to flow in the ground path. In a balanced three phase system, such as, a motor, the sum of the three phase currents will equal to zero. If ground fault current is going into the ground path from one of the phases, the currents will not sum to zero. This value of current is compared to the ground fault pickup setting of the trip device. If the level is above the pickup point, the trip device will send a trip signal to the actuator after a pre-determined time setting. In a three phase system that has single phase loads, the three phase currents may not sum to zero. In this situation, the trip device won’t recognize the difference between ground fault current and normal current. To overcome this, a neutral is added to the system. Any imbalance between the three phase currents returns on the neutral. The trip device compares the sum of the three phase currents to the neutral current. A difference indicates the presence of a ground fault. Primary current injection testing involves injecting a current through the circuit breakers’ conducting path that is of sufficient magnitude and time duration to meet a trip point. If the breaker operates within the manufacturer’s specifications, it is considered to be in working condition. If it tails to meet specifications, the reason needs to be determined and corrective action taken.

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Circuit Breakers Vol 2

Time and travel analysis (MVCB) For medium voltage circuit breakers you must verify the correct operation of the mechanism; a time and travel recorder must be used. The standard timing tests of Close (C), Open (O), CloseOpen (CO), Open-Close (OC), and Open-Close-Open (OCO) should be performed. ● Close: The close time is defined as the time it takes from the initiation of the close operation to the instant when mechanical continuity is established. ● Open: The open time is defined as the time it takes from the initiation of the open operation to the instant when the primary arcing contacts have parted. ● Close-Open: The Close-Open time is defined as the time from the instant that mechanical continuity is established to the when the primary arcing contacts part. This is often referred to as the Trip-Free time or Dwell time. ● Open-Close: The Open-Close or Reclose time is defined as the time from initial parting of the primary arcing contacts to the time when mechanical continuity is once again established. An OCO operation is performed to make sure that the mechanism has enough energy to clear a fault and clear it again if it is still remaining on the reclose. Although all the standard tests should be performed, often only the Close, Open, and Trip Free times are measured. All timing values should be compared to the manufacturer’s specifications. In addition to the timing of the contacts, a transducer should be attached in order to measure the motion of the circuit breaker. Either a linear or rotary transducer may be used but the intention is to measure the stroke of the interrupter. The stroke is defined as the distance of the interrupter in the fully open position to the fully closed position. When the stroke is measured correctly, the velocities of the interrupters can be calculated in the arcing zone. The manufacturer should provide a set of speed calculation points for both the close and open curves. This is necessary in order to verify that the breaker will be able to extinguish an arc under fault conditions. Other parameters such as contact wipe, over travel and rebound can also be calculated. An illustration of the different parameters measured and calculated can be seen below in Figure 1.

Fig. 1

SPECIAL CONSIDERATIONS Current Limiting Fuses - Current limiting fuses are used where the interrupting rating of the circuit breaker is lower than the available fault current of the electrical circuit. This causes a problem during testing because these fuses must be removed and replaced with bus to avoid “blowing” the fuse during a test. Another problem with current limiting fuses is that the line and load side finger clusters of air frame circuit breakers may not be in the same vertical plane. The finger cluster arrangements vary between circuit breakers which make it difficult to use a standard configuration for connections to primary current injection test equipment. DC Offset – DC offset is a term that is used to describe an asymmetrical phenomenon resulting from a mismatch of phase angle relationships between voltage and current from both the perspective of the source versus the perspective of the load. In this case, the primary injection test equipment would represent the source, while the circuit breaker with all of its connections would represent the load. The load has a representative amount of reactance (X) and resistance (R). It is the ratio of these load components that will dictate the required phase angle relationship between voltage and current. tan-1 (X/R) = ØWhere Ø represents that phase angle between voltage and current DC offset occurs when the source and the load have differing ideas regarding what this phase angle relationship should be (Ø). The load always wins this battle, but it may take as much as 4 to 5 cycles for the source and load to settle their differences. The resultant waveform may look something like the illustration below (Figure 2).

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Circuit Breakers Vol 2

REFERENCES ANSI/NETA Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems, ANSI/NETA ATS2009 Bjork, K., Vacuum Breaker Testing With The Megger Programma Vidar, Megger - July 2011 Fig. 2 Since this phenomenon will typically only exist for a period of less than 5 cycles, it only applies to the instantaneous operations of circuit breakers. Ultimately this could cause a discrepancy between the factory and the field engineer regarding the instantaneous pickup setting of the breaker. Manufacturers of LVCB test equipment are now designing features into their products that will allow users to address this phenomenon of DC Offset. However, please keep in mind that not all manufactures address this issue, and if they do, it may not be addressed in a full range of product offering. There are two ways that this phenomenon can be addressed; 1) Allow the user the control to manually adjust the phase angle at which current is initiated from the test equipment to match that of the load, or 2) design test equipment that will output a low level, short duration, pre-test signal to determine the optimum angle of current initiation by evaluating the phase angle response of the load. These types of changes within the design of commercially available primary injection product offerings will help to negate such concerns in the future of electrical operational testing of LVCB’s.

SUMMARY Circuit breakers are critical to the protection and safe delivery of electricity. Although they might sit idle for months or even years, when called upon to act, they must operate in mere milliseconds. Therefore, the performance of circuit breaker testing and maintenance is of the utmost importance in providing reliable system protection. All circuit breakers share some common characteristics, whether they are rated for a few hundred volts or for thousands of volts. They must be able to conduct while closed, insulate while both closed and open, interrupt the current when tripping and efficiently change between the open and closed state. Each of these functions must be properly maintained and tested to ensure that the circuit breaker will protect the valuable assets within the electrical grid. One must consider the function being tested and the type and voltage class of circuit breaker to select the proper maintenance routine. Using the standards set forth by IEEE and NETA, as well as Manufacturer recommendations, you can help to insure the safe delivery of electricity.

Chapman, F.X.; Hammonds, B., “The effect of DC offset on instantaneous operating characteristics of low-voltage circuit breakers,” Industry Applications Conference, 1996. ThirtyFirst IAS Annual Meeting, IAS ‘96., Conference Record of the 1996 IEEE , vol.4, no., pp.2265-2268 vol.4, 6-10 Oct 1996 doi: 10.1109/IAS.1996.563889 IEEE The Authoritative Dictionary of IEEE Standard Terms, IEEE STD 100-2000 (Seventh Edition) IEEE Recommended Practice for Electric Power Distribution and Industrial Plants, IEEE STD 141-1986 (Red Book) IEEE Standard Test Procedure for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis, ANSI/IEEE Std C37.09-1979 , vol., no., pp.1-60, 1980 McWilliams J. M., Applications Guide, Circuit Breaker Test Sets, Multi-Amp Corporation- February 1990

Robert Foster is an Applications Engineer with Megger, specializing in high voltage circuit breaker and transformer testing. He graduated from California State University, Chico with a Bachelors of Science in Physics and Mechatronic Engineering. After graduation he worked as a Field Service Engineer for ABB in the high voltage dead tank circuit breaker division. He is i volved with customers and product development supporting products and applications throughout North America. Bret Hammonds is a Senior Technical Instructor for Shermco Industries. He supports coworkers in a number of areas related to workforce development as well as the health and safety of Shermco employees. He holds a BSEET from Texas Tech University as well as an MBA from the University of Phoenix. Bret spent close to 25 years working for an electrical test equipment manufacturer where he held various roles that included product management and technical support for a broad range of electrical test equipment. He has also directed operations for a test equipment rental company and managed an office for an electrical testing service company. Bret is a member of the IEEE Power Engineering Society and past member of ASTM D27 Committee for Insulating Liquids and Gases.

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Circuit Breakers Vol 2

DETERMINING CIRCUIT BREAKER HEALTH USING VIBRATION ANALYSIS – A FIELD STUDY PowerTest 2014 John Cadick, PE Cadick Corporation and Finley Ledbetter, Group CBS Inc.

I. INTRODUCTION Approximately fifty percent (50%) of low- and medium-voltage, distribution class circuit breakers that have not been properly maintained will fail to operate within their published specifications. This statistic has been determined in research studies performed within the last four decades. An excellent paper by Neitzel and Neesoni provides background on this. One commonality among the various studies that have been performed in the past is that before the breaker can be tested for operation, it must be taken out of service. This means that the breaker must be opened before any analysis can be performed; consequently, the all-important first-trip data1 will be lost. This paper discusses a new test method that is being used successfully for determining the mechanical condition (and thus the electrical performance) of circuit breakers – including the capture of first trip data. Using a marriage of compact and modern communications equipment, internet data transfer, and sophisticated condition based maintenance algorithms (CBMA) this new test offers a number of valuable features such as: 1) Extreme portability 2) Quick, easy mechanical condition assessment

a simple four letter contraction of Circuit Breaker Vibration Analyzer or Circuit Breaker Vibration Analysis. As an additional benefit, when the CBVA system is used safety is enhanced in at least two ways as follows: ● By using remote operating mechanisms, the test can be performed when the technician is well outside the arc-flash boundary. ● When a breaker is being racked, there is a high probably of failure. Such failures often result in major, arc-flash events. Since the CBVA system can perform a first trip test without removing the breaker, the possibility of accident is diminished

II. HOW DOES THE TEST WORK? A. Circuit Breaker Vibration A circuit breaker is a very complex mechanical mechanism. It has a huge variety of parts including springs, lever arms, sheet metal, pivots, rubber stops, contacts, and many other such items. This means that the vibration signature of a circuit breaker when it operates will be very complex. Figure 1 shows such a vibration signature.

3) Capture of first-trip data 4) Easy transmission of data to a central location 5) A basic comparison method of analysis based on a vibration envelope and/or a detailed mathematical analysis of results 6) Ability to perform testing during routine switching 7) First trip analysis does not require removal of the circuit breaker a) Reduces the risk of human error (and thus provides additional safety) since it requires no modification or removal of the circuit breaker. b) Removing, handling, and reinstalling presents the risk of damage. The new method employs the well-known method of vibration analysis in a new way. This method has shown excellent results in the field. For the remainder of this paper, this new method of vibration analysis will be referred to as CBVA. This acronym is

Fig. 1: Three axis vibration signature for a circuit breaker (Courtesy of Group CBS Inc.)

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Circuit Breakers Vol 2 There are three different waveforms – one each for the x, y, and z axes. Note that the trace on each of the axes is similar but not identical to the others. This is because the breaker will not vibrate in exactly the same way in each of the three directions.

The smart phone (Figure 2) contains a very good accelerometer and has been used successfully in field tests. The external accelerometer and PC (Figure 3) provide overall greater control and flexibility.

The Z axis is displaced by one G from the other two. This is because the G axis is the vertical axis and is always subjected to the force of gravity – 9.8 m/sec2 (32.2 ft/sec2). The other two axes are horizontal; therefore, gravity has no effect on them.

The smart phone and the PC each have a software package that captures the data and combines the three traces to form single profile by using an advanced, vector mathematics algorithm. The data is then sent electronically to the master web-site for comparative analysis. Figure 4 shows such a profile.

The basic concept of CBVA is that any properly maintained circuit breaker of the same type will have a vibration signature that varies very little from the norm. In this case the norm is developed by an advanced mathematical algorithm that merges the three single-axis traces into a single profile. This profile is then sent to a master web-site which compares to a Known Good Profile (KGP). The KGP is developed by performing a statistically significant analysis of multiple breakers of the same type.

B. Equipment Used The test equipment required for CBVA consists of only two devices – an accelerometer and a computer that can capture the data provided by the accelerometer. Figures 2 and 3 illustrate two systems that are being used successfully to perform this test.

Fig. 4: A vibration signature showing the calculated envelope (Courtesy of Group CBS Inc.)

C. Placement of the Accelerometer There are three key requirements for placement of the accelerometer. 1) It must be placed in the same location for every test. 2) It must be placed in the same orientation for every test 3) The location and orientation of the accelerometer must be the same as that used to develop the KGP. Correct placement of the Smartphone is shown in Figure 2, and correct placement for the external accelerometer is shown in Figure 3. Fig. 2: The smart phone used as a CBVA test set

D. Capturing the Vibration Signature The performance of the test is completed in six easy steps 1) Position and orient the accelerometer as previously described. 2) Initiate a ten second countdown in the software. 3) When the countdown reaches 0, the software goes into Record mode and waits for the first vibration to occur. 4) The technician initiates whatever test is being performed by actually operating the breaker. The technician has the option of performing a trip, charge, close, or any combination of the three. 5) The accelerometer senses the start of the test and begins recording the vibration signature.

Fig. 3: A laptop computer and an external accelerometer (Courtesy of Group CBS Inc.)

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6) After the test is finished, the tester presses the Stop button.2 Then the data is saved in a tabular format in the PC or smart phone software. (Figure 5)

be traced to a worn or missing tooth in a gear, bad or failing lubrication, or even misalignment of mechanism parts. Pass and Fail criteria for the analysis is developed as follows: ● For a given KGP, a set of ‘significant zones’ is identified. ● Each zone is given a ‘tolerance’ for allowed values, based on historical data collected on equipment of that type. This helps to account for normal mechanical variations. ● In order to pass, a test must match at least 65% of these ‘significant zones’ within the vibration envelope within the specified tolerances.

III. A CASE STUDY A. Overview During January 28 through February 10, 2013, field technicians from a qualified electrical testing firm performed field maintenance and testing on 64 air circuit breakers at a major petrochemical facility (facility) in Houston TX. This facility had recently established a corporate-wide directive to determine first trip times to ensure arc flash compliance for safety or operators and equipment. In direct response to this, they requested that the first trip time for these breakers be evaluated to determine if they needed to make changes to their maintenance cycle, and to see if the breakers would clear faults within spec. The company used the system described in this paper to perform the testing because they found it easier and just as reliable compared to other test methods. The same company has now done similar testing in three different plants. Fig. 5: Partial data capture table (Courtesy of GroupCBS, Inc.)

E. Analyzing the Signature After the data is stored in the test device, it is submitted to the master web-site via the internet.3 The software at the master website performs a mathematical analysis of the submitted trace. The trace is compared to the KGP and the degree to which the test trace matches the KGP is calculated.

F. Visual Inspection An experienced analyst can capture some information by simple inspection and comparison of current vibration signature graph versus a KGP. Such an inspection can identify obvious problems such as those caused by a major mechanical fault. However research shows that a more sophisticated method provides a much better analysis.

G. Pattern Recognition The master web-site software employs sophisticated pattern recognition software (PRS). The PRS captures the peaks and valleys of the data and compares it to a KGP. The PRS will identify differences from the KGP to such fine detail that a problem can even

The tested equipment included both low- and medium-voltage breakers which were 18-25 years old. The breakers tested were on a 5-year maintenance plan; however, they had been in service for approximately 7 years without maintenance. Some of the breakers may have been operated in that time, but there was not enough available information to indicate which, if any, had actually been operated.

B. Results A total of 64 breakers were tested for first-trip (open) operation. Twenty-six of the breakers passed the acceptance criteria, leaving thirty-eight breakers that failed. Of the failed breakers: ● Fifteen were found to have a trip time outside of manufacturer specifications (resolution of ±10ms.) ● One test inexplicably failed to capture any significant data ● Two other tests were unreliable due to operator error. ● The signatures on the majority of the failed breakers were related lubrication problems or worn components. ● In approximately 40% of the tests these issues also manifested as slow opening time. Statistics for the test results are shown in Table 1.

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Device

Average Calculated Trip Time (ms)

Standard Deviation (ms)

Percent Past

Overall

63

14

40%

Passed

51

6

N/A

Failed

71

11

N/A

CB.1

72

11

8.0%

CB.2

69

15

25.0%

CB.3

53

5

100.0%

CB.4

58

13

50.0%

CB.5

60

9

100.0%

CB.6

51

8

86.0%

CB.7

73

8

0.0%

Table 1: Field Case Study Results Data

IV. SUMMARY Conventional testing methods might have caught the slow-operating problems; however, it is likely that most if not all of the 23 borderline breakers would have been put back into service, creating a potential safety hazard. Additionally, due to the exercise during testing it is likely that some or all of the 15 slow breakers would have passed a traditional timing test thereby creating a potential safety hazard Overall, by performing these tests they were able to determine that their inspection and testing intervals need to be shortened, or they need to consider another lubricant that would better withstand the conditions they were experiencing. The application of vibration analysis for circuit breakers has proven to be an excellent addition to the tools of the test technician.

REFERENCES Dennis Neitzel and Dan Neeson, Preventive Maintenance and Reliability of Low-Voltage Overcurrent Protective Devices, Pulp and Paper Industry Technical Conference, 2007, Conference Record, PP 164-169

John Cadick, P.E. A registered professional engineer, John Cadick has specialized for over four decades in electrical engineering, electrical safety, training, and management. In 1986 he founded Cadick Professional Services (forerunner to the present-day Cadick Corporation), a consulting firm in Garland, Texas. His firm specializes in electrical engineering, marine services and training, working extensively in the areas of power system design and engineering studies, condition based maintenance programs, and electrical safety. Prior to the creation of Cadick Corporation, John held a number of technical and managerial positions with electric utilities, electrical testing firms, and consulting firms. Mr. Cadick is a widely published author of numerous articles and technical papers. He is the author of the Electrical Safety Handbook as well as Cables and Wiring. His expertise in electrical engineering as well as electrical maintenance and testing coupled with his extensive experience in the electrical power industry makes Mr. Cadick a highly respected and sought after consultant in the industry. Finley Ledbetter has worked in power engineering for 35 years, including serving as an Applications Engineer and Instructor for the Multi-Amp Institute. He was the founder of Shermco Engineering Services Division, a division of Shermco Industries – a NETA Accredited Company. Finley is also the founder of Group CBS, Inc., which owns 12 circuit breaker service shops. He is a member of IEEE, a NETA Corporate Alliance Partner, and a Charter Member and Past President of Professional Electrical Apparatus Recycler’s League (PEARL).

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DIAGNOSTIC TESTING PRACTICES FOR SF6 FILLED DEAD TANK CIRCUIT BREAKERS PowerTest 2016 Charles Sweetser, OMICRON electronics Corp. USA

I. ABSTRACT With the proliferation and growing population of Dead Tank SF6 Filled Circuit Breakers, it is important to understand the effectiveness of the diagnostic testing protocol that is applied. Some confusion has surfaced when comparing SF6 filled diagnostic testing principles to the older oil filled dead tank circuit breaker test practices. When diagnostic tests are performed on SF6 filled dead tank circuit breakers, valuable information can be extracted if the tests are preformed and analyzed properly. From a technical maintenance perspective, it is critical to correctly use the testing results to determine the condition of these circuit breakers. Standard field tests widely applied today in SF6 filled dead tank circuit breaker diagnostics include:

Table 1, shown below, lists several different types of circuit breakers, and defines the properties and subsystems, highlighted in BOLD, (such as mechanism type and insulation medium) related to Dead Tank SF6 Circuit Breakers. BREAKER TYPES

MECHANISM TYPES

Bulk Oil Circuit Breaker (OCB)

Mechanical (Spring)

Dead Tank SF6 Breaker

Hydraulic

Live Tank Air Blast

Pneumatic

Live Tank SF6

Magnetic Actuator

Vacuum Breakers

INSULATION SYSTEMS

Air Magnetic Low Voltage Air Blast

Oil

● Timing and Travel

Reclosers

SF6

● SF6 Gas Quality

Circuit Switchers

Air

● Power Factor

Sectionalizers

Vacuum

Table 1: Type, Properties, and Subsystems

● Contact Resistance These specific diagnostic tests have been selected as the primary focus for this paper and discussion. This easy-to-follow paper and presentation focuses on the diagnostic testing practices associated with SF6 filled dead tank circuit breakers. The audience will be provided with an understanding, application, and analysis of these tests, supported by case studies.

II. INTRODUCTION This paper focuses Dead Tank SF6 Filled Circuit Breakers. Dead Tank SF6 Filled Circuit Breakers are primarily preferred in North America in HV applications, while the rest of the world utilizes Live Tank Circuit Breaker technology. As with any circuit breaker type or technology used, Dead Tank SF6 Circuit Breakers are designed with the following three functions in mind: ● Direct current flow between desired sections of an electric power system ● Interrupt current flow under abnormal power system events and conditions, such as faults ● Carry load current under normal power system conditions with minimal losses

Diagnostic testing can be performed in either an on-line/inservice state or an off-line/de-energized state. The manufacturer’s recommendations, duty, number of operations, and past experience should be considered when justifying the test and maintenance requirements. Table 2 and Table 3 list recommended and commonly practiced on-line/in-service and off-line/de-energized tests, respectively. Visual and Mechanical Inspection

Inspect External Physical Condition, Structure, Grounding, Gauges, Annunciators, and On-line Monitoring Devices

SF6 Gas Analysis

SF6 Density, SF6 Moisture, and SF6 Decomposition

SF6 Leak Detection

Laser Imaging, Thermal Conductivity, Acoustic Emissions

Infrared (IR)

Thermal Imaging; Temperature Differential

Acoustic Emissions

Partial Discharge, Particles, Mechanical Defects

First Trip IED (Simple) Intelligent Electronic Device IED (Advanced) Intelligent Electronic Device

Acoustic Emissions (Partial Discharge, Particles, Mechanical Defects), SF6 Gas Analysis (Density, Moisture, Pressure, Decomposition), Heaters, and Charging System (Air and Motors).

Table 2: Online/In-Service Testing Methodologies

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Circuit Breakers Vol 2 CONTROL

MEASUREMENT

CALCULATIONS

Visual and Mechanical Inspection

Inspect Physical Condition, Structure, Grounding, Gauges, Annunciators, On-line Monitoring Devices

Trip (O)

Displacement

Main Contact Timing

Contact Condition

Static Resistance, Dynamic Resistance (DRM), and Contact Wipe

Close (C)

Main Contact State (O-R-C)

Resistor Switch Timing

Insulation Integrity

Power Factor/Capacitance, Partial Discharge (PD), Insulation Resistance, Withstand (AC/DC High Pot), and SF6 Quality

ReClose (O-C)

Command Coil Current

Pole Spread

Main Contact Timing

Control Circuit and Contacts, Verify TRIP, CLOSE, TRIP-FREE(DwellTime), and RECLOSE (Dead-Time)

TripFree (CO)

Auxiliary Contact State (OW-OD-C)

Velocity (Zone)

(O-CO)

Battery Voltage

Total Travel

Mechanism

Total Travel, Velocity, Over-Travel, Rebound, Contact Wipe, Stoke

(O-CO-CO)

Phase Currents (First Trip)

Over Travel

Control Circuit

Minimum Pickup, Minimum Voltage, Insulation Resistance, Operation of Protective, and Alarm Devices

Slow Close (C)

Dynamic Resistance (DRM)

Rebound

Instrument Transformers

First Trip (O)

CT Saturation, CT Polarity, CT Ratio, Burden, and Winding Resistance

Contact Wipe Dwell Time (TripFree C-O) Dead Time (ReClose O-C)

Table 3: Offline/De-Energized Testing Methodologie

III. INTRODUCTION TO DEAD TANK SF6 BREAKERS Dead Tank SF6 Circuit Breakers can utilize three different methods for arc extinction. Each of these methods utilizes SF6 gas pressure to “blow-out” or extinguish the arc. a) SF6 Puffer Circuit Breaker - Mechanical compression of the arcing chamber generates SF6 gas pressure. b) SF6 Self-Extinguishing Circuit Breaker - Heat generated in the arcing chamber generates SF6 gas pressure. c) SF6 Double (Dual) Pressure Circuit Breaker - Uses a pressurized SF6 gas chamber that is released in the arcing chamber during operation. Some other facts include: Dead Tank SF6 Circuit Breakers are often equipped with SF6 gas-filled bushings that cannot be isolated for field testing. So, the condition of the bushings are unfortunately integrated in the over insulation system. Applying the correct test protocol will help identify failure modes and the associated component. The bushings often have CTs mounted on the upper external ground sleeve near the mounting flange, which removes the need for free-standing CTs.

IV. TIMING AND TRAVEL Circuit breaker timing and travel measurements entail three steps: 1) Perform a dynamic timing and travel measurement 2) Calculate performance characteristics 3) Compare results to the manufacturer’s recommendations or user-defined limits Table 4 provides the fundamental tests and calculations involved in circuit breaker timing measurements and diagnostics.

Stroke

ReClose Time (O-C)

Table 4: Circuit Breaker Timing Fundamentals

Measured Signals When performing circuit breaker timing and travel measurements, there are five primary signals that are of interest. 1. Displacement 2. Contact State (Open-Resistor-Close) 3. Command Coil Current 4. Auxiliary Contact State (OW-OD-C) 5. Battery Voltage It is worth noting that the main contacts can take on three different states, OPEN, CLOSE, and RESISTOR, because some breaker applications require Pre-Insertion Resistors (PIRs). When the breaker performs a CLOSE operation, a resistor will be placed across the open contacts for a few to several milliseconds in order to limit potential overvoltage associated with long transmission line applications. It is important to capture the operation; specifically, the timing of this resistor switch. Also, depending on the use and availability of the auxiliary contacts, such as 52a and 52b, etc., these contacts may be wet (voltage present) or dry. The measurement must be configured for such conditions.

Performance Characteristics For Dead Tank Circuit Breakers, there are 12 performance characteristics in all, including 6 related to timing, 5 related to displacement, and 1 for velocity. They are all important, however, due to the specifics of the nozzle and arcing contact design, it is important to analyze the contact wipe closely. Figures 1-4 illustrate OPEN, CLOSE, TripFree, and ReClose, respectively.

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Circuit Breakers Vol 2 Analysis of Results Timing and travel results are directly compared to the manufacturer’s performance specifications and previous results. All of the performance characteristics listed above will have pass/fail criteria. Table 5 illustrates typical performance characteristics. It should be noted that not all manufacturers document all performance characteristic limits; it may be worthwhile to baseline anmissing limits with commissioning tests. Identification

Fig. 1: OPEN Operation

Fig. 2: CLOSE Operation

CB1

Control Circuit Open

70-140 VDC / 6.0 A

Control Circuit Close

90-140 VDC / 6.0 A

Opening Time

17-30 ms

Opening Velocity

3.8 m/s minimum

Pole Spread Open

2.7 ms

Closing Time

50-85 ms

Closing Velocity

1.7 to 2.3 m/s

Pole Spread Close

2.7 ms

Overtravel

4.0 mm maximum

Rebound

6.5 mm maximum

Stroke

113 mm maximum

Dwell Time

20-38 ms

Reclose Time (Dead Time)

300 ms minimum

Table 5: Typical Performance Limits Provided by the Manufacturer A few diagnostic indicators, such as contact bouncing, dashpot damping, and command coil signatures are obtained by analyzing the recordings.

V. SF6 GAS ANALYSIS

Fig. 3: TripFree Operation

SF6 Gas Analysis focuses on two properties: dielectric integrity and arc-extinguishing ability. From a technical perspective, SF6 Gas as a dielectric medium offers favorable characteristic, such has high dielectric strength and the ability to self-heal (recombine to SF6 ) after an arcing event. For SF6 to maintain its advertised qualities, the following properties must stay in check:

SF6 Purity

Fig. 4: ReClose Operation

The introduction of any non-SF6 molecules is a form of contamination. SF6 Purity tracks the percentage of impurities in the SF6 gas. Moisture, air, residual material, and by-products affect the purity. Some contaminates can be removed by filtration and some others, not so easy. Air, N2, O2, and CF4 cannot be easily removed from in-service gas, as with other by-products. It is important to understand which contaminates are present and what role they play in effecting the SF6 system. With respect to air, thepurity level should not exceed 5000 ppm for in-service gas [1].

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Circuit Breakers Vol 2 Moisture Just like paper-oil insulation systems, moisture has an adverse effect on SF6 . Moisture may have less of an effect on the dielectric as it does in paper-oil insulation systems, however, the presence of moisture can accelerate the process of decomposition of SF6 , which can create safety concerns when human contact is made with these byproducts. Moisture levels should remain below 200 ppm or per order of the manufacturer’s recommendation [1].

the primary indicators. Decomposition levels should remain below 500 ppm [1].

VI. POWER FACTOR Power factor and capacitance testing provides means of verifying the integrity of the insulation of circuit breaker components. Problems that impair the insulation integrity and can be detected by measuring the power factor and capacitance include:

SF6 Decomposition

● Deterioration of entrance bushing insulation

Decomposition of SF6 occurs during partial discharge events, contact arcing, internal arcing, and high energy thermal conditions. Listed below are the byproducts that can be generated by the breakdown of SF6 gas.

● Presence of particles, impurities and contamination of SF6 insulating medium

● Hydrofluoric acid HF

● Deterioration of interrupter assemblies, insulated operating rods and support insulators due to arcing by-products

● Moisture ingress Damages resulting from partial discharge and tracking

● Carbon dioxide CO2 ● Sulphur dioxide SO2

Test Procedure

● Carbon tetrafluoride CF4

Power factor and capacitance test procedures depend on the design and type of apparatus. The following test procedures are those required to test SF6 Dead Tank Circuit Breakers. However, these test procedure concepts apply to a number of different breaker types.

● Silicon tetrafluoride SiF4 ● Thionyl fluoride SOF2 ● Sulphuryl fluoride SO2F2 ● Sulphur tetrafluoride SF4 ● Disulphur decafluoride S2F10 When analyzing SF6 byproducts Sulphur dioxide (SO2), Thionyl fluoride (SOF2), and Hydrofluoric acid (HF) are generally present for most failure modes. So, these gases are often used as

The applied test voltage should not exceed the line-to-ground rating of the test specimen, or otherwise stated by the manufacturer. The test specimen should be solidly grounded for safety and proper measurement. There are nine recommended and three optional tests performed on Dead Tank SF6 Breakers. Table 6 shows the 12 tests.

TEST INSULATION TESTED BREAKER POSITION HV IN A IN B TEST MODE 1 C1G Open Bushing 1 GST

2 C2G Open Bushing 2 GST 3 C3G Open Bushing 3 GST 4 C4G Open Bushing 4 GST 5 C5G Open Bushing 5 GST 6 C6G Open Bushing 5 GST 7 C7G Open Bushing 1 Bushing 2 GST 8 C8G Open Bushing 3 Bushing 4 GST 9 C9G Open Bushing 5 Bushing 6 GST 10 C1G+2G Closed Bushing 1&2 GST 11 C3G+4G Closed Bushing 3&4 GST 12 C5G+6G Closed Bushing 5&6 GST

NOTE: All unused bushing should be left floating Table 6: Recommended and Optional Tests: Dead Tank SF6 Breakers

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Analysis of Results Tests 1-6 primarily measures the insulation integrity of the energized bushing and also include any insulated support structure, operating rod and SF6 gas. Tests 7-9 assess the condition of the contact assembly and SF6 gas within the interrupter chamber. Tests 10-12 are optional tests that are performed on circuit breakers with more than one contact chamber per phase. This test mode helps stress the additional support structures that will not be seen while the circuit breaker is in the open position. For low capacitance specimens like Dead Tank SF6 Breakers it is generally recommended to assess losses (in Watts) instead of power factor. This is especially true for the open breaker UST measurements. The capacitance is so low that most Dead Tank SF6 Breakers must be analyzed in Watts. Power Factor should not be

used to determine the integrity of insulation if the measured current is less than 0.3 mA. At low measured currents, PF calculations are susceptible to large swings, which could be misleading [2]. Therefore, in those cases, the test results should be evaluated based on current and loss readings. Please note, not all Dead Tank SF6 Breakers are assessed according to measured watt losses, just those units with very low capacitance. On circuit breakers with grading capacitors Tests 7-9 are dominated by the grading capacitors. High power factor or loss readings may indicate deteriorated capacitors. An unexpected increase in capacitance may indicate short-circuited capacitance layers. Figure 5 illustrates typical results obtained from a Dead Tank SF6 Breaker. It can be seen that tests [1 3 5], tests [2 4 6], tests [7 8 9] can be compared, respectively.

Fig. 5: Power Factor and Capacitance Results

VII. CONTACT RESISTANCE Contact Resistance can be a complicated subject. Contact assemblies can consist of both main and arcing contact components. To see both main and arcing contact components, the Contact Resistance is analyzed, both statically and dynamically, respectively.

Static The micro ohm measurement or static contact resistance measurement determines the continuity integrity of the main contact components. Abnormal readings may indicate improper alignment, pressure, or damaged contact surfaces, such as plating or coating. This is the standard test that is performed to measure the actual resistance value of contact continuity and associated series components, such as bushing connections and tulips. The static measurement produces a single, temperature dependent value in Ohms ([Symbol]), more specifically (µΩ). A static contact measurement is to be performed on each phase, using a DC current source. Typical measurements are close to

or less than 100 µΩ, see Figure 6; however, the manufacturer’s literature should be used to determine the actual expected value. Experience has shown measurements performed on SF6 Dead Tank Breakers range from 75 µΩ to 150 µΩ, with 100 µΩ being a very common result. It is recommended that at least 100A DC is injected for this test [2]. Also, it should be noted that if the breaker is equipped with CTs, it may take several seconds to saturate the opposing effects. Precautions should be taken to ensure that the injected high primary current does not affect protection circuits.

Fig. 6: Typical Dynamic Resistance Measurement Due to the very low resistances, in the µΩ range, it is recommended that a high DC current source be used in conjunction with a Kelvin connection. The Kelvin 4-wire method is the most effective method used to measure very low resistance values.

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Circuit Breakers Vol 2

The Kelvin 4-wire method will exclude the resistance from the measurement circuit leads and any contact resistance at the connection points of these leads. The concept of the Kelvin 4-wire method is to apply the voltage and current leads separately. This is shown in Figure 7.

CONCLUSION ● Timing and Travel measurements determine and validate the performance characteristics of circuit breakers. Measurements are compared to the manufacturer’s specifications. Contact timing, displacement, and velocity are analyzed. Failure modes related to the control coils, mechanical linkages, energy storage device, contacts, and dashpots can be identified. ● SF6 Gas Analysis provides information regarding the condition of the SF6. Moisture, purity, and SF6 byproducts will be determined and compared against industry limits.

Fig. 7: Kelvin Connection Used for Contact Resistance Measurement

Dynamic (DRM) The dynamic resistance measurement is a diagnostic tool to assess the condition of the arcing contacts in SF6 nozzle style interrupters. By measuring the current, voltage, and displacement associated with the contact assembly, it is possible to determine the wear level and integrity of the arcing contact. This measurement, like the static contact resistance measurement, requires high current injection to be successful. Common practice is to use at least 100A DC. Caution must be taken when analyzing the results. As implied by the name (DRM), “resistance” is being isolated and measured. However, in actuality, due to the speed of the contact interaction (roughly 15-20 ms), it is impedance, which includes both real and reactive components, that drives the response. Source leads, CT’s, and capacitances, both stray and fixed, contribute to the unexpected reactance. Figure 8 illustrates a typical dynamic resistance measurement. Motion and the resistance (impedance) response are plotted together. The length of what is left of the arcing contact is determined by comparing it to the distance traveled.

Fig. 8: Typical Dynamic Resistance Measuremen

● Power factor and capacitance testing provides means for verifying the integrity of the insulation components, which is related to the SF6 dielectric of support material. Typically 9 tests are performed with the breaker in the OPEN position. The GST and UST test nodes will be used to isolate specific insulation components. ● Contact Resistance measurements can be performed in either the static mode or the dynamic mode. Typical static values are in the 100 µΩ range. Additional analysis can be performed using the Dynamic Resistance Measurement (DRM). The condition and remaining life of the arcing contacts on SF6 nozzle style contacts can be estimated.

REFERENCES [1] ANSI/NETA MTS-2015, “Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems”. [2] IEEE C57.152-2013, “IEEE Guide for Diagnostic Field Testing of Fluid-Filled Power Transformers, Regulators, and Reactors”.

Charles Sweetser received a B.S. Electrical Engineering in 1992 and a M.S. Electrical Engineering in 1996 from the University of Maine. He joined OMICRON electronics Corp USA, in 2009, where he presently holds the position of PRIM Engineering Services Manager for North America. Prior to joining OMICRON, he worked 13 years in the electrical apparatus diagnostic and consulting business. He has published several technical papers for IEEE and other industry forums. As a member of IEEE Power & Energy Society (PES) for 16 years, he actively participates in the IEEE Transformers Committee, where he held the position of Chair of the FRA Working Group PC57.149 until publication in March 2013. He is also a member of several other working groups and subcommittees. Additional interests include condition assessment of power apparatus and partial discharge.

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EFFECTS OF LOW RESISTANCE MEASUREMENT INSTRUMENTS ON PROTECTION AND CONTROL DEVICES PowerTest 2016 Dinesh Chhajer and Daniel Carreno, Megger

ABSTRACT: Low resistance micro ohm measurement is a routine diagnostic test performed on Circuit Breakers (CB) and bus bars in medium and high voltage substations. This test is important to check the integrity of CB contacts and detection of high resistance joints and terminations for installed bus work. Although the test is very simple and easy to perform, it can prove problematic for other devices connected to the same circuit. The DC current used for measuring the low resistance can affect the protection and control circuitry in adverse ways. Typical problems encountered are Current Transformer (CT) magnetization, accidental tripping of differential relays and inconsistent and unreliable low resistance measurements. The paper will address the root cause of these encountered problems. It will recommend precautions to take prior to performing the test and discuss in detail the recommended practices to avoid any misoperation of connected protection and control devices. The recommended practices will be supported by both a real life case study and lab simulations to thoroughly explain the impact of quality of DC current used for the low resistance measurements, effect of in service tap CT ratio, and associated settings of connected relays. Paper will provide an insight into the factors that can go wrong during micro ohm measurements and how to prevent those using a proactive approach.

LOW RESISTANCE TESTING An electrical conductor is one of the most important elements in any electrical system. It is the part of the system that carries the current flow and its quality mainly depends on factors such as material, geometry (cross sectional area and length) and temperature, which all together define the resistance of the conductor. The operation of electrical equipment depends on the controlled flow of current within the design parameters of a given piece of equipment. Depending upon the electrical asset, current flow under normal operation can range from a few amps to many hundred amps. Any increase in resistance can result in loss of energy in the form of heat in accordance with the formula W=I2R. For instance, a bus joint resistance measured upon commissioning at 50 µΩ is considered to be an acceptable measurement, but over time due to corrosion and lack of maintenance, if the resistance of the joint goes up to 500 µΩ; the power dissipated in the joint also increases tenfold.

The big difference in dissipated power will result in excessive heating and if left unattended, it can lead to catastrophic failure of that electrical equipment. External factors like environmental and chemical attacks, electrical stresses (over voltages or impulses) and mechanical stresses as well, can all contribute to the degradation of joints, contact surfaces and low resistance connection points. High resistance not only causes unwanted heat, but it also causes energy losses which increase operating costs; this is the reason why utilities and other industries are aware of the importance of performing low resistance measurements. The application range of low resistance measurements is very wide and some of the most common applications include motor windings, coils, ground bonds, welded joints, lightning conductors, small transformers, bus bar connections and circuit breakers. A resistance measurement is considered to be of low resistance when the resulting value of the test is below 1.000Ω. The lower ranges of many low resistance ohmmeters measure down to 0.1 µΩ, which is required when conducting tests on breaker contacts and bus joints. At this level of resistance it is important to use the correct test equipment and method that will minimize the introduction of errors due to test lead resistance, contact resistance between the probe and the specimen under test, as well as other phenomena like standing voltages across the item being measured (e.g. thermal EMFs at junctions between different metals). This is achieved by means of a four terminal measurement (two current and two potential leads) as shown in Figure 1 below. It is important to ensure that the potential leads are placed between the current leads for most accurate measurements.

Fig. 1: Four Wire Resistance Measurement

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Circuit Breakers Vol 2 CIRCUIT BREAKERS The basic function of a CB is to interrupt current flow in a circuit when a fault condition is present. However, sometimes it is forgotten that under normal operating conditions a CB needs to act as a very good conductor for the circuit it is part of. The contact resistance has to remain under a certain value to ensure a good conductive path for the current flowing through it to avoid heating and hence energy losses. Regular maintenance programs include contact resistance testing in accordance with standards ANSI C37.09 and IEC62271-100, which specify minimum current values to carry out the low resistance measurement. Special care should be taken when measuring contact resistance of CBs with CTs that are still connected to a protection scheme. Figure 2 shows a typical single line representation of a CB with CTs.

Fig. 2: Circuit Breaker with bushing CTs

DIFFERENTIAL SCHEME A differential protection zone is defined by the location of CTs and in an ideal case this scheme will work on the premise that the total input current of the system (protected zone) will be equal to the total output current. It will determine whether a fault is present within the protected zone if the difference between input and output currents is above a predetermined set value. This threshold and the proper configuration of the protection scheme are affected by certain characteristics of the CTs, like protection class, CT ratio, saturation levels and nonlinearities. Differential protection scheme is generally recommended for all buses as it provides sensitive and fast phase and ground-fault protection. One of the most common approaches used is High-Impedance Voltage Differential, which will use zone CTs connected in parallel with a high impedance element inside the relay. All the CTs used for this application must have the same ratio, similar magnetizing characteristics and a relatively high knee point, in order to avoid a false operation for a given burden. Figure 3 shows a common differential protection scheme for bus and transformer protection. The voltage threshold for a differential element should be set balancing two considerations; first, a low-value setting for maximum sensitivity for in-zone faults or second, a high-value setting to ensure stability for a saturated CT due to a fault present outside the protected zone.

Fig. 3: Differential Protection Scheme for a) Bus and b) Transformer

EFFECT OF DLRO ON THE DIFFERENTIAL PROTECTION SCHEME: A low resistance micro ohm measurement on each phase of medium and high voltage CBs is a routine maintenance test. The DC current applied for the test is passed through the breaker contacts and the voltage drop is measured to determine the breaker contact resistance in micro ohms. The majority of HV circuit breakers in North America are dead tank type breakers. As shown in Figure 4, these breakers have CTs mounted on their bushings. The primary of the bushing CT is basically a center conductor passing through the CT which then gets connected to the breaker interrupting chamber that encapsulates the fixed and moving contacts of the breaker.

Fig 4: DLRO test connection to a dead tank CB When performing a Digital Low Resistance Ohmic (DLRO) measurement, the DC current applied passes through the CT primary. In theory, it being a DC quantity, no current should be reflected on the secondary side of the CT. However, based upon the method used and quality of the applied DC current, in some cases, there is a reflection of that onto the CT secondary circuit. The duration and magnitude of the secondary current will depend upon a number of factors. Some of those include rate of rise and fall of applied DC current, method used to generate DC current such as half wave rectified, full wave rectified or generation using a regulated power supply. A rapidly changing DC current output with

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ripple content or presence of harmonic components can be interpreted as a fault signal (AC quantity) by the relay and protection devices connected to the CT secondary circuit. Additionally, when the bushing CT is part of a differential protection scheme, this secondary current could be interpreted by the protection scheme as an operating quantity. One other side effect of a DLRO measurement is every time a DC quantity is passed through CT primary, it magnetizes the CT and alters the CT performance. If the current magnitude and time is substantial enough one could saturate the CT and introduce ratio errors during CT operation.

tion circuit and short the CT secondary. This has to be performed for any CT secondaries whose primary is part of the low resistance measurement circuit. One of the practical challenges at many utilities is the substation crew is different than the protection and control crew and is not allowed to change any protection circuits. Additionally, there is always a precaution of not changing existing circuits as it might cause wrong rewiring, incorrect selection of CT tap and accidentally leaving the CT secondary open. Because of all those reasons, although being an ideal method, CT secondaries are typically not disconnected for low resistance measurements.

DISCONNECT CT TO AVOID TRIPPING OF DIFFERENTIAL PROTECTION

CT DEMAGNETIZATION

False tripping of relay or protection devices can take out a portion or complete system offline and can cause unreliable and unpredictable system operation. In cases where bushing CTs are part of transformer or bus differential scheme, if the unwanted CT secondary current due to DLRO test is greater than the threshold limits of relay settings, it can accidentally trip the system. To avoid any possibility of inadvertent relay tripping situation, the ideal method is to disconnect the CT secondary from the protec-

After exposing CTs to a DC current flowing through the primary it is possible that CTs may have residual magnetism; it is highly recommended to perform a demagnetization procedure on all the CTs involved in the circuit to ensure proper performance after DC testing has been carried out. The following example shows how the excitation curve for a given CT is affected by DC current injection in the primary circuit. A protection class C200 multi tap CT with a full CT ratio of 600:5 (X1: X3) was used for this test.

Fig. 5: Saturation test after first demagnetization

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Circuit Breakers Vol 2 First, a demagnetization procedure was carried out to ensure the CT had no residual magnetism and then, the first saturation test was run as shown in Figure 5. A knee point of 210.26V was measured for X1-X3 tap (full secondary winding).

A DC current was injected through the primary of the CT to see the effect on saturation characteristics of the CT. 400 A was injected through the primary of the CT using a DLRO as shown in Figure 6.

Fig. 6: Application of DC current to CT primary

Without demagnetizing the CT, another saturation test was performed. In this case, the knee point was measured at 227.11V. As observed in Figure 7, in addition to knee point voltage change,

there was a shift in the saturation curve as well. DC current altered the saturation characteristics of the CT.

Fig. 7: Saturation test after resistance measurement (primary)

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A demagnetization process was performed and another saturation test was run thereafter. Figure 8 shows the curve after the

demagnetization. In this measurement the knee point was observed at 208.30 V which was similar to first test results.

Fig 8: Saturation curve after resistance measurements followed by demagnetization procedure DC current can magnetize the core of the CT and if not addressed properly can leave residual flux in the core. Under extreme cases it can even saturate the CT. These measurements demonstrate the importance of demagnetization processes after performing DC testing on any circuit that has CTs, especially the ones connected to a protection scheme.

CASE STUDY: In a normal differential scheme, one could expect multiple CT secondaries connected and compared for detecting an in-zone fault. When a portion of the circuit is taken offline for maintenance purposes, the Kirchhoff’s current law still holds good and differential scheme works normally. In an ideal scenario, the current from the CT taken offline should be zero. When the offline CT secondary injects an accidental signal current (from injected DLRO DC current into the CT primary) into the differential circuit, pending the magnitude and duration of the current, it can trigger the differential protection scheme. An incident occurred at one of the largest Investor Owned Utility (IOU) with more than 6 million customers and operating in seven different states. The bus differential relay tripped while performing the micro ohmmeter testing on a 138 kV circuit breaker. The technicians attempting the test had difficulty obtaining a good contact resistance measurement, and made multiple test attempts prior to the one that caused the trip. The circuit breaker under test featured integrated CTs that were not isolated from the bus differential protective scheme.

The DC current injected for the measurement was 100 A. The high impedance relay used for differential protection was set at a pick up voltage setting of 100 V with no intentional time delay. During the trip event, it was reported that the relay registered a voltage of 132 V. This prompted an investigation to determine the root cause of the incident to avoid any such future misoperation of the protection scheme. In order to observe how the relay responds to application of DC current through CT primary, field conditions were simulated in a lab environment by using the same make and model of high impedance relay along with the relay settings, CT of similar class and ratio and same micro ohmmeter test instrument with different levels of current. Following instruments and parameters were used as variables to observe different aspects of the problem. ● Tests were performed at different levels of current (100 A 200 A) for varying time duration (0.6 sec - 3 sec) ● Two different multi tap CTs of class C800 and C200 were used ● Different taps of the CTs were used (2000:5 and 4000:5) ● High Impedance relay settings from the relay events log with different trigger settings of 20V, 50 V, 75 V and 100 V were used for the analysis The block diagram for the setup used in this relay tripping investigation is shown in Figure 9.

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Fig. 9: DLRO, CT and relay setup for lab investigation

OBSERVATIONS AND ANALYSIS: Observation 1: Relay settings An initial test was performed to simulate the field conditions with similar CT class, ratio and relay settings. No relay trip

*DNT= Did Not Trip

occurred at a setting of 100 V. The trip settings were then reduced to 75, 50 and 20 V for further analysis. Relay trip occurred at 20 V trigger setting. As expected relay settings play an important role in the tripping of the differential protection scheme.

Table 1: CT: C800-2000:5

Observation 2: DC current output characteristics Different DLRO test instrument may have different quality of DC output based upon the method used to generate DC current from an incoming AC source. There are many factors that can cause the relay to sense initial DC input current as a potential fault current signal. A sudden spike at the start or end, very high level of harmonic components, or ripple current riding over the DLRO DC output are some of the examples that could cause a false trigger of protection scheme.

Ideally, a DC output should ramp up to the target current at a pre-defined ramp rate and follow the same method while ramping down at the end of the test. Additionally, it should have a smooth DC output during the measurement period. If a sudden spike is observed in the output, a relay might see the rising or decaying DC signal as one single narrow pulse and would trip the relay if the magnitude of the filtered output, after passing through one cycle cosine filter, exceeds the relay voltage setting.

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Below are some of the examples:

Fig. 10: DLRO output current characteristics 1 Figure 10 above shows a smooth DC output with no ripple current and a ramp function at the start and end of the current injection. Fig. 12: Illustrates an output with spikes at both the start and finish of the test.

Observation 3: Class of the CT

Fig. 11: DLRO output current characteristics 2 Figure 11 above shows a decaying DC output without any intentional time delayed ramp function.

Two different protection class CTs with C200 and C800 were used as per the connections in Figure 9. Relay settings and DLRO test current were kept the same for two tests. Same CT ratio of 2000:5 was used for both of the CTs. It was observed that with a relay pick up setting of 20 V, C800 relay tripped and C200 did not. Class of CT can affect the response of the relay. The higher the CT class, the more sensitive the relay trip circuit will be.

Table 2: Variable CT class

Observation 4: Ratio of the CT The highest ratio 4000:5 (X1-X5) of the C800 CT was used with different relay voltage settings. The relay tripped at pick up settings of 20 and 50 V, however, it did not trip at any setting above 75 V. At higher CT ratio (compared to Table 1), the relay tripped

at 50 V setting. All other settings being equal, the CT ratio can impact the performance of the relay. The higher the CT ratio, the more sensitive the relay trip circuit will be.

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Table 3: CT: C800-4000:5

Observation 5: Different tap of the CT Performance of two different taps (X1-X3 and X1-X5) of the C800 CT with same relay settings and test current was observed.

As shown in Table 4 below, the relay only tripped on X1-X5 tap and not with X1-X3 tap.

Table 4: Variable tap of CT Based upon the saturation test results performed on the C800 CT, X1-X3 knee point voltage was 394.50 V and X1-X5 knee point voltage was 788.86 V. As per the equation 1 from high impedance relay user’s manual, the minimum primary current required to trip the relay is dependent not only on the current flowing through the relay but also on CT excitation current Iexc and number of CTs connected in parallel to the relay.

Imin=(n*Iexc+Ir+Im)*N

current, making it more sensitive for the same relay trip voltage settings. This is shown in the Figure 13 below.

Equation 1

Imin= minimum primary current n= number of current transformers in parallel with the relay, per single phase Iexc= current transformer exciting current at relay setting voltage, Vs Ir= current through the relay at relay setting voltage, Vs Im= current through the MOV at relay setting voltage, Vs N= CT ratio CTs with higher knee point voltage will have lower excitation

Fig. 13: CT saturation curves for multi tap C800 CT For any given relay voltage setting, the excitation current requirement is less for a higher tap CT. X1-X5 Iexc is less than Iexc for X1-X3.

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Circuit Breakers Vol 2

Additionally, for same relay voltage settings, the number of CTs in the circuit would impact the sensitivity of the relay circuit. Protection schemes with less no. of CTs per phase connected in parallel to the differential relay would be more sensitive when compared against a scheme that has more CTs in parallel. Figure 14, shows a differential relay configuration on the right that is more sensitive compared to the one shown on the left.

Fig. 14: No. of CTs being part of differential protection scheme

Observation 6: Multiple repeat tests Every time a DC current is injected to the CT primary, it magnetizes the core of the CT. This would result in either increase or decrease in CT excitation current requirements when compared against a demagnetized CT. Multiple repeat DLRO test in a short period of time could change the relay sensitivity because of CT core characteristics and make the relay operation unpredictable.

Observation 7: Pick up setting for a relay in service During lab simulations, the relay never tripped for any voltage setting above 75 V for any possible combination of DC current, CT class or CT tap. However, during that accidental bus differential trip, the relay saw a voltage of 132 V. Some other factors such as burden associated with each CT, CT saturation and other design parameters could have contributed to final outcome. During investigation it was determined that even though the high impedance differential relay was set at a pick up setting of 100 V, as per the relay manufacturer’s recommendation, the minimum relay pick up setting should have been 200 V for the high impedance differential relay in question. Above observations and analysis indicated that there are several different factors that can contribute to inadvertent tripping of the differential relay. Some of the factors can be controlled by the user out in the field whereas others are defined by system design and settings. The case study and investigation gave an insight of which parameters can influence the outcome and factors to be considered before performing a DLRO measurement.

SOLUTION AND RECOMMENDATIONS: Instruments designed to measure contact resistance of CBs have incorporated methods to avoid the problems discussed in this paper. The first method implemented is having filtered DC outputs to eliminate any change in frequency that may be reflected on the

secondary of any CT in the circuit, or even having instruments with pure ripple free DC outputs. A second approach, frequently used in conjunction with the first one, is the ability of an instrument to define a ramping rate at both the start and end of the test. A low resistance micro ohmmeter with this feature will slowly increase the injected current, starting from zero to the target current and at the completion of test, the same ramping rate is applied when reducing the current back to zero. This helps in preventing any sudden rise in DC quantity or spike that could possibly be interpreted by a relay as a fault signal. The voltage differential setting in a relay can play a major role as well, as illustrated in a relay manufacturer’s user manual: “a low-voltage setting with no intentional time delay can have an adverse impact on the security of the differential elements for external faults. High-current external faults can result in enough unbalance current to cause operation of the differential elements for these low-voltage settings with no intentional time delay. A minimum instantaneous differential voltage setting of 200 V with no intentional time delay is recommended” 4. When performing low resistance measurement out in the field on bus or breaker contact resistance, technicians have to be cautious and be aware of all the factors that can cause accidental tripping of relays. Class of CT, CT ratio and CT tap in operation are few aspects although can’t be altered, should be kept in mind. On the other hand, CT residual magnetism, demagnetization, unwanted repeated DLRO measurements, relay settings as per the manufacturer’s recommendation and selection of the correct DLRO test instrument with smooth DC output and ramp rate option can certainly reduce the probability of any accidental trip.

CONCLUSION: Low resistance micro ohm measurement is an integral part of regular substation asset maintenance practices. Breaker contact resistance and bus work installation will continue to be checked using this test method. The test, as simple as it is, comes with inherent critical issues that need to be addressed to avoid any inadvertent trips during this measurement. This paper covered a real life case study and an analysis was made to discover the factors that can affect the protection scheme associated with the circuit under test. Understanding the CT performance and relay characteristics will prepare technicians better to take a proactive approach and perform the test in a risk free manner. Selection of the right instrument with proper DC output will go a long way in mitigating any possibility of accidental trip.

REFERENCES: 1) IEEE C37.09-1999, IEEE Standard Test Procedure for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis

Circuit Breakers Vol 2 2) EC 62271-100:2008, High-voltage switchgear and controlgear - Part 100: Alternating current circuit-breakers 3) Megger, A Guide to Low Resistance Testing, USA, 2005 4) Schweitzer Engineering Laboratories, Inc, SEL-587Z Relay Instruction Manual, 2015

Dinesh Chhajer is the Manager of Technical Support Group department at Megger. He holds a master’s degree in Electrical Engineering from University of Texas in Arlington (UTA). He has presented a no. of white papers related to asset maintenance and testing at various conferences within power industry. He has previously worked as an applications engineer at Megger. In that role his responsibilities included provide engineering consultation and recommendation in relation to testing of transformers, circuit breakers and other substation assets. Before that, he worked as a substation design engineer and substation maintenance engineer with POWER Engineers Inc. where he had the opportunity to gain experience and specialization in the areas of transformers, batteries and power quality. He is currently a licensed professional engineer in the state of Texas. Daniel Carreño is an Applications Engineer with Megger, specializing in transformer testing and high voltage circuit breakers. He graduated from Instituto Politécnico Nacional, in Mexico City, with a Bachelor of Science in Mechatronic Engineering. His experience involved working for power transformer manufacturers in Mexico and the USA. Daniel is an IEEE-PES member and actively participates in substation equipment condition assessment and applications development.

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Circuit Breakers Vol 2

POWER FACTOR TESTING OF GAS CIRCUIT BREAKERS PowerTest 2016 Rick Youngblood, Doble Engineering Company

ABSTRACT Power Factor Testing of gas circuit breakers can be complicated and confusing as compared to other types of equipment due to their inherently low losses and relatively small differences between good and bad readings in the test results. It’s only when the technician truly understands both what elements of the breaker they are trying to test as well as the significant and easy to make mistakes that contribute to poor test results, successfully determine the health of gas breakers. This paper will point out what the technician is trying to accomplish and show the common errors made during testing. Additionally the paper will provide sample test results of good and bad breakers.

bottom insulator of the disconnect switch create a path to ground, included with the line and load side bushings of the breaker. In this case we have 5 distinct paths for current to travel to ground. However small they still count! Fig#1 below

Gas Breaker Electrical Fundamentals Testing gas circuit breakers does not have to be complicated if the technician plans ahead and understands the pitfalls involved. Understanding the component pieces of the breaker and what contributes to each reading provides the technician with the information needed to make sound judgments when reviewing the results. Considering SF6 gas is one of the best dielectrics known to man and completely fills the energized portion of the breaker it is easy to understand why the leakage component of gas circuit breakers (GCB) is very low and measured in the micro-amp range (10-6) The level of leakage current in an oil breaker typically measures in the milli-amp range or (10-3). It would also be logical to assume any additional minor path to ground or between the contacts would slew the actual readings and affect the outcome of the results where it wouldn’t affect the outcome of an oil breaker test. Testing Mistakes The biggest and most common mistake made when testing GCBs is not disconnecting the bushings from the bus. This in turn measures the bus and any standoff insulators plus one side of each disconnect switch. Using the picture and diagram below; it is easy to see how multiple parallel paths can affect the readings. Each insulator stack holding the buss up and the

Fig. 1: Power factor is cumulative and averaging. The measurement in effect takes the leakage current of every path and adds them together and divides by the number of paths to get the measured total current, watts and therefore Pf. All 5 paths, in this example, contribute to the final test result. It would be easy to conclude that any conductive path, typically due to dirty, wet insulators or dirty, wet bushings will slew the results and cause the results to look abnormally high. It is therefore imperative that all bushings be cleaned and dried very well and conductors be disconnected from gas breakers to prevent additional paths to ground. It is also very important that the tech realizes disconnecting the bus does not mean separating the buss and the bushing by a small piece of dielectric material such as rubber blanket. Distance is the only true correct disconnect. In cases where blanket or other dielectric material is used and the bus and bushing remain in close proximity, the test tech sets up a capacitive couple between the bushing and ground as shown in figure (# 2) below creating their own testing problem. A minimum of about 6” clearance is required to prevent this problem.

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Circuit Breakers Vol 2 SF6 Bushings are gas filled tubes with either a porcelain or polymer weather shed around it. The diameter of the bushings has little to do with the dielectric integrity but more for the mechanical strength needed to hold up the buss conductors. SF6 bushings do not have test taps because they have no condenser layer internally to grade the voltage from the center conductor to the ground flange and rely solely on the dielectric strength of the gas.

Fig. 2:

TESTING Once the breaker has been thoroughly cleaned and disconnected, the testing procedure can begin. The following are the proper procedures. A sequence of 6 open circuit pole tests are run in Grounded Specimen Test or (GST) on poles 1-6 leaving the opposite pole floating. The next 3 tests are run across the individual phases 1-2, 3-4 and 5-6 with the test set in the Ungrounded Specimen Test mode or (UST). The GST tests measure the leakage from each pole to ground and the UST tests measure the leakage across the open poles of the breaker. See Fig#3 below.

Fig. 3

Hot collar method should be performed to test these insulating stacks for leakage. Apply hot collars to the second skirt from the top. Additional tests on lower skirts can also be performed. Both GST ground and UST tests can be applied. The GST primarily looks for surface leakage where the UST looks deep for cracks and tracking. If the bushing tests good in GST no further testing is required. If it tests bad re-clean and test in UST. Pay special attention around the top 30% of the bushing when using UST. Typically .010 watts or lower are considered good.

Failure of Recognition Test Techs typically don’t recognize small numbers as significant. If each pole is measuring .002 watts loss and one pole is measuring .004 watts loss there is a 100% change and requires investigation. Granted .002 watts is a small number but consider-

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Circuit Breakers Vol 2

ing the materials GCBs are made from and the insulating quality of the gas small numbers become important. Very small changes in current and capacitance are meaningful and comparisons to the other poles or even other breakers of like type and sequential serial numbers can be used for comparisons. It is very common for either the 1,3,5 or the 2,4,6 poles to measure higher in watts than the opposite side. This is due to the interconnection of the operating mechanism to the moveable contacts adding an additional path to ground. These measurements should measure the same differential for each of the three phases and not more than a few percent higher than the stationary side overall. If the measurements are considerably higher the insulation between the mechanism and the contacts should be evaluated carefully for defects. .Tests 10-12 are only conducted on breakers having more than one set of contacts in series. These tests are conducted in GST mode but the breaker is closed rather than open as in all the previous tests. This set of tests is used to detect problems in the support post insulator between the 2 sets of moveable contacts as seen in figure #4 below.

Test results from a SF6 breaker with a bad interrupter

Evaluation of test results

Watts losses on the bad interrupter as compared to sister breakers

Circuit Breakers Vol 2 After repairs to the bad interrupter

Actual findings when interrupter was disassembled

SUMMARY Performing power factor on SF6 filled circuit breakers have proven to be accurate and reliable providing all the rules for testing this type of application are observed. As can be seen from the test reports a very small change in the results from previous pole to ground tests or between phases can result in a very large change in the dielectric withstand for the breaker resulting in a catastrophic failure the next time the breaker is called on to interrupt a fault. It is therefore important for the test technician to pay close attention to the results and question minor differences in readings. Catching a breaker before failure can be the difference between being the villain and the hero. Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA Level 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

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TANK LOSS INDEX WHAT IS IT? PowerTest 2016 Rick Youngblood, Doble Engineering Company

OUTLINE Tank Loss Index 1. Definition of Power Factor Testing for Oil Circuit Breakers (OCB) 1a. Tank Loss Index (TLI) defined as part of power factor testing 1b. Defining parts of breaker to be tested 2. Testing OCBs 2a. Open circuit tests 2b. Closed circuit tests 3. Definition of TLI and how to calculate it 4. TLI Guide 5. Case Studies Tank Loss Index (TLI) is a specific test performed only on oil circuit breakers (OCB)s and designed to provide non invasive information on the internal condition of the breaker tank and parts assembly without having to pull the oil and go inside. To understand tank loss index the test tech must first understand what parts of the breaker they are really testing when they perform power factor (PF). Most techs can hook up the test set and run the tests but truly understanding the results of the test and differentiating between bushing problems, oil problems and tank assembly problems makes all the difference in the world on preventing catastrophic breaker failures. TLI is nothing more than using the information obtained when running the standard poles tests in the open and closed positions and then using the information to determine if there is a problem in the breaker and where to look. Let’s take a look at PF testing of OCBs to see how the first part of the data is obtained. The breaker can be broken in to three main components; the bushings, the oil and tank liner and lastly the operating assembly as shown in Fig #1 below:

The tests performed involve 6 individual pole tests in the open position and then 3 pole tests in the closed position running the set in GST for the all 9 tests as shown below in Figure #2 and Fig # 3 below.

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Circuit Breakers Vol 2 The second half of the test is to perform PF test on each bushing to determine if the individual pole reading is influenced by the bushing. Power Factor is both cumulative and averaging so when the individual pole readings are taken the test tech is actually measuring the combination of the bushing and pole assembly in parallel. The important thing to remember is that a bad bushing will show up in both the individual open pole tests and the combination closed circuit tests making identification of a bad bushing very easy. Tank Loss Index is now nothing more than using the results obtained and calculating the answer. Unfortunately unless the tech truly understands TLI they don’t understand the significance of the differences between two individual pole test results as compared to one retest of the same two poles at the same time. In theory the results should be identical as in a simple math problem of 1+1 =2. From here we must take a look at what the tech is really testing in the open mode and then again in the closed mode. As can seen below in Figure #4 what parts are tested during the first 6 poles individually in the open mode. The influence of the parts that are energized versus the parts that are at ground potential should be closely observed. There is a large emphasis on the individual bushing affecting the test result. The other parts affecting the outcome are made up from the lift rod, lift rod guide and assembly as well as the grid /interrupter itself.

Notice the influence now is the tank and oil because they are at a lower potential than the internal assemblies which are now at the same potential and pass no leakage current between them. This major change in influence will affect the final outcome when tank loss index is calculated providing and easy way to determine if the breaker health is a result of wet dirty oil or a mechanism issue.

Tank Loss Index(TLI) TLI = (2 Bushings) + Lower Lift Rod + Oil + Tank Liner -(2 Bushings) + (2 Lift Rod Guides + 2 Top of Lift Rods+2 Interrupters) = (Lower Lift Rod+ Oil +Tank Liner )- ( 2 Lift Rod Guides + 2 Top of Lift Rods + 2 Interrupters ) As a General Rule: TLI Tends to Be Negative Notice the bushings drop out in the math!!!

Guideline Tank-Loss Indexes (TLI) Oil Circuit Breakers

In the final set of tests lines 7-9 where the breaker is closed and the tech measures two poles at once and the influence changes, although the bushings are still the predominant provider and affects the result in this mode as well. This effect becomes important in the end results because it’s easy to identify a bad bushing which can then be tested individually to prove. See Figure 6 below. Again pay attention to the influences in the test result and look at the differences between Figure 5 and 6.

CASE STUDIES In the case study below the current readings and watts match up for both poles and the TLI is well below 0.10 watts indicating this breaker to be healthy and for service.

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Circuit Breakers Vol 2 CONCLUSION

Analysis of Circuit Breaker Condition Example #1

I (ma)

Watts

%PF

1(Open)

1.150

0.07

0.61

2(Open)

1.150

0.07

0.61

7(Closed)

2.300

0.11

0.50

TLI = 0.11 - ( 0.07 + 0.07 ) = - 0.03 Watts Comments: Test Normal In this case study notice the watts losses and PF are three times higher for pole #2 as compared to pole#1 and the TLI is -0.16 which is over the limit for a good breaker. The indication could point to a bushing or the interrupter assembly. The TLI is not conclusive. The bushing test of C1 and C2 will provide the proof of the bushing health pin pointing the breaker problem.

Analysis of Circuit Breaker Condition Example #2

I (ma)

Watts

%PF

1(Open)

1.15

0.07

0.61

2(Open)

1.2

0.22

1.83

7(Closed)

2.3

0.13

0.56

TLI = 0.13 - ( 0.07 + 0.22 ) = - 0.16 Comments: High Negative TLI “Wet” Interrupter on Bushing No. 2or Higher Losses on Bushing No. 2 High Power Factor on Bushing No. 2, Test Bushing to Confirm In this case study the watts losses and power factors are consistent for both poles yet the TLI is above the limit for a good breaker at a -0.19 indicating a possible problem. The possibility of having two bushings above the limits with the exact same readings are low but having the same contamination to the upper lift rod assemblies and guide rods are common. In this case the determination of the problem is easy.

Analysis of Circuit Breaker Condition Example #3

I (ma)

Watts

%PF

1(OPEN)

1.2

0.15

1.25

2(OPEN)

1.2

0.15

1.25

7(CLOSED)

2.3

0.11

0.48

TLI = 0.11 - (0.15 + 0.15) = -0.19 Comments: High Negative TLI Bushing May Be OK -Test to Confirm Possible Problems: • Deteriorated Operating-Rod Guide • Upper Portion of Lift Rod • Contaminated Interrupter Assemblies

It has been shown that TLI in conjunction with standard power factor testing of oil breakers and their bushings has proven to be valuable in determining OCB health. The level of the TLI can be used to determine if the condition of the OCB can wait until the next normal test interval or should be shortened to insure the breaker does fail in service. In some cases the tests have prevented catastrophic failure catching a problem in the nick of time. It therefore becomes the test techs responsibility to understand and appropriately use TLI in determining the health and continued serviceability of the breaker under test. Not all PF testing software incorporates TLI but as shown the mathematics to determine health is very easy to do, understand, and should always be incorporated.

Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA Level 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

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A CASE FOR TESTING MEDIUM-VOLTAGE BREAKERS NETA World, Fall 2014 Issue Lynn Hamrick

The circuit breaker’s main function is to provide circuit and equipment protection during a fault or other abnormal condition. When a breaker fails to operate or clear a fault, the resulting damage can be very serious in terms of both personnel injury and equipment damage. Therefore, circuit breakers must be tested and maintained to ensure proper operation during these faults. This article will present a case study on the effects of a breaker failure, or in this case two breaker failures, in terms of equipment damage and arc-flash incident energies. BACKGROUND This case study is associated with 13.8 kV breaker failures at an industrial complex. This complex is fed through two 13.8 kV buses each having a main breaker and multiple feeder breakers that provide power to the 20+ unit substations within the complex. During normal operation, each bus feeds approximately half the complex. The buses are independently fed from the utility. The system includes a tie breaker between the buses that is normally open. In 2007, a fault occurred on a 13.8 kV feeder cable at or near the termination point on the line side of a fused, boltedpressure switch feeding a unit substation. A fault condition of this type typically would result in the feeder breaker in the 13.8 kV breaker line-up tripping on time-overcurrent (TOC) and isolating the effects of the fault to just the equipment associated with the feeder. Unfortunately, the feeder breaker failed to trip. Upon failure of the feeder breaker, the lineup’s main breaker should have tripped on TOC. Unfortunately, the main breaker also failed to trip. This resulted in the utility’s feeder breaker feeding this particular 13.8 kV bus tripping and the subsequent loss of power to the all devices being fed from this 13.8 kV line-up, half the equipment to the entire industrial complex. This is the definition of a very bad day.

i .

INVESTIGATION: FAULT AT THE SWITCH Upon investigation, it was quickly determined where the cable had faulted. The switch was damaged beyond repair by the energy released during the fault. Protective relay records indicate the fault started as a line-to-ground fault that became a three-phase fault after approximately 12 seconds. The total length of the fault was approximately 16 seconds. The phase-A terminal of the switch appears to have suffered the most damage with the aluminum conductor separated from the lug attached to the switch terminal and the high voltage cable termination completely disintegrated. Relay records indicated the fault started as phase-A to ground. The switch enclosure was bulged at the top indicating a release of gases during the fault. A large gash approximately four inches in length was observed on the top of the switch above the phase-A switch terminal. Two flash marks were visible on the wall of the switch enclosure opposite the phase-A terminal without visible damage to the external paint of the cabinet caused by heating. The majority of ground fault current appeared to have initially followed the ground strap of the cable termination until it was consumed, but this could not be determined with any certainty. The only other potential visible path to ground was the gash in the top of the switch which was physically a greater distance from a phase-A conductor than the adjacent phase termination or the side of the switch. The insulating arc chutes of the switch were completely consumed by the fault. The cable terminations were removed and returned to the manufacturer for testing. These particular cable terminations

38 had been installed 18 months earlier. The cause of the failure was determined to be poor workmanship associated with installation of the cable termination. It was determined that only dc high potential testing was performed for acceptance testing for this cable.

Circuit Breakers Vol 2 ARC FLASH EVALUATION For this incident, there were three failures: 1) The feeder cable fault at the switch 2) The feeder breaker’s protective relay 3) The main breaker’s trip coil An evaluation was performed in an effort to determine the extent of the damage associated with each failure. The system was modeled using SKM’s PTW Power System Analysis software and the guidance provided in IEEE 1584-2002, Guide for Performing Arc Flash Calculations. A scenario was developed associated with each failure mode and the results in terms of arcing fault current, fault clearing time, and arc-flash incident energy were calculated. For the purpose of this evaluation a working distance of 18 inches was selected for each scenario. A tabulation of the results is presented below. Failure Scenarios

INVESTIGATION: PROTECTIVE RELAY OPERATION The failed main and feeder breakers were removed and inspected. In the case of the main breaker, the trip coil had failed, resulting in the failure of the breaker. However, there was no obvious failure within components of the feeder breaker. The relays were interrogated to ascertain the sequence of events and the potential cause of the breakers failure to isolate the fault. When the cable faulted, both protective relays sensed the overcurrent condition, and provided a TOC operate signal within the timecurrent characteristics of the protective settings. The TOC operate signals were indicated on the front of the relay. The main breaker’s relay also indicated that a trip signal was sent by closing the output contact to power the circuit breaker’s trip circuit. The breaker failed to trip due to failure of the circuit breaker trip coil. Typically a failed trip coil results from the mechanical mechanism of the breaker providing more resistance than the trip coil can overcome causing the trip coil to burn out. However, the feeder breaker’s protective relay did not close the output contact to power the circuit breaker trip circuit for the breaker to clear the fault. The factory default logic configuration for the relay indicates that once an overcurrent pickup condition meeting the criteria of the protective setting is satisfied, the designated trip relay contact should close. Unfortunately, the logic for this relay had been corrupted such that the relay contact command was no longer present in the relay’s firmware. Upon further investigation, all of the feeder breaker protective relays in both lineups were found to be similarly afflicted. The latest version of the settings and logic files were provided by the relay manufacturer and downloaded to the feeders’ protective relays and the relays were proven by testing to operate correctly. The main and tie breakers’ were also tested and were not found to have the same issues.

Feeder cable failure at switch with proper operation of feeder breaker Feeder cable failure at switch with feeder protective relay failure and proper operation of main breaker Feeder cable failure at switch with feeder protective relay failure and main breaker trip coil failure and proper operation of utility breaker

Fault Current (kA)

Fault Clearing Time (sec)

Arc Flash Incident Energy (cal/cm2)

13.156

0.11

6.3

13.156

6.596

81.1

13.156

13.949

306.7

Based on the results for each modeled scenario, the following observations were provided with respect to the extent of damage associated with each failure mode. 1) For Scenario 1, a cable failure was considered with the proper operation of the feeder breaker. This scenario results in a level of arc flash incident energy at the fault (6.3 cal/cm2). Based on this arc flash incident energy, the anticipated damage would probably have been confined to the cable itself. The subsequent unplanned outage activities would have been restricted to production and non-production equipment being provided power through the feeder breaker. Associated remedial action would have been to replace the cable. 2) For Scenario 2, a cable failure, with the failure of the feeder breaker protective relay, was considered with correct operation of the main breaker. This scenario results in a level of arc-flash incident energy at the fault (81.1 cal/cm2) and, therefore, would have been dangerous. Based on this arc flash incident energy, the anticipated damage would have been significant.

Circuit Breakers Vol 2 All cables within the switch compartment and the switch probably would have been damaged. Associated remedial action would have been to replace multiple cables and the switch. Additionally, the logic/programming for the feeder protective relay would require correction. 3) For Scenario 3, a cable failure, with the failure of the feeder breaker protective relay and the main breaker trip coil, was considered with proper operation of the utility’s breaker. Ultimately, this is the scenario that actually occurred. This scenario results in a level of arc-flash incident energy at the fault (306.7 cal/cm2) and, therefore, would have been very dangerous. Based on this arc flash incident energy, the anticipated damage would have been significant. All cables within the switch compartment and the switch were damaged and required replacement. The subsequent unplanned outage activities were extended to all production and nonproduction equipment being fed from the 13.8 kV bus which was effectively half the facility. Associated remedial action was to replace multiple cables and the switch. Additionally, the logic/programming for the feeder protective relay was corrected and the main breaker was cleaned up and its trip coil was replaced. Based on the above arc flash evaluation, the initiating event for the incident was the cable failure at or near the termination in the switch. However, the severity and amount of equipment damage and subsequent remedial action was impacted by the failure of the feeder breaker to operate due to a protective relay that did not operate correctly. It is understood that the main breaker’s failure to operate due to the failed trip coil significantly increased the arc-flash incident energy ultimately experienced during the incident. Failure of the feeder breaker and the main breaker to operate resulted in significant damage to the system. However, the failure of the feeder breaker, with the main breaker operating as designed, probably would have resulted in sufficient damage such that the same level of remedial action would have ultimately been required.

CONCLUSION If a breaker fails to operate in fault conditions, the amount of damage, incident energy released, and cost for remedial action can increase exponentially. For this incident, there were three failures: 1) The feeder cable fault at the switch 2) The feeder breaker’s protective relay 3) The main breaker’s trip coil Each of these failures increased the arc flash potential of the event. Each of these failures probably would have been mitigated with proper acceptance and maintenance testing. Proper testing of the cable, including tan-delta testing should have identified

39 this cable termination defect prior to placing in service. Proper testing of the protective relays, to include operationally tripping and closing the breakers, would have identified the issues with the relays. Proper maintenance of the breakers, to include cleaning, lubricating, and operationally testing the trip and close circuits of the breaker would have identified or mitigated the trip coil failure. Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee

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Circuit Breakers Vol 2

PERFORMANCE TESTING OF GROUND FAULT PROTECTION SYSTEMS: CRITICAL TO ELECTRICAL RELIABILITY AND SAFETY FOR INDUSTRIAL AND COMMERCIAL POWER SYSTEMS NETA World, Winter 2014 Issue Ron Widup Shermco Industries It happens in a fraction of second – and what happens after that can mean the difference between the inconvenience of a power outage to a large-scale electrical failure and/or fire. Therefore, the assurance that your electrical power system does what it is intended to do is paramount. What we’re talking about is a phase-toground electrical fault along with the reaction and ability of the electrical equipment’s ground fault protection relay (GFPR) to clear the fault. Depending on the application, many modern power systems found in industrial and commercial applications have requirement for ground fault protection relays. The requirements can be found in NFPA 70, National Electrical Code® within Articles 230.95, 215.10, 240.13, 517.17, 695.6(G), 700.27, 701.26, and 708.52. [1] While ground fault protection relays are not required on all electrical power systems, for the ones that do such as a 480-volt, 1000-ampere or greater, solidly-grounded, wye system, the use of a GFPR is commonplace. Unfortunately, often these types of systems do not have an adequate level of recommended maintenance and inspection to provide a level of comfort that they will operate as intended.

HOW TO ASSURE RELIABILITY OF PERFORMANCE There is no doubt that we have learned over the years that electrical equipment begins a journey towards a decline in performance and reliability from the first day of installation. Insulation integrity will eventually lessen, lubrication characteristics change over time, electrical and electronic components weaken, and generally the components will ultimately wear out, especially if they are not properly maintained over the lifecycle of the system. But don’t worry! If you take precautions when the system is new (perform acceptance testing and commissioning), and then continue to properly maintain the components and the system throughout their useful life you can be assured of many years of safe and reliable operation. Not doing so and the results can be dire at the very time you need the equipment to operate at peak performance.

Fig. 1: Defective 480-Volt Disconnect So electrical equipment is critical and the proper performance is key, but how do you assure yourself it will work? Well, you don’t have to look too far as the industry has basically figured it out, and already has requirements in place that get us most of the way there, such as language found within the NEC®. Early on, both industry and the NFPA established two very important criteria when dealing with electrical equipment: safeguarding of persons and establishing standards necessary for safety. Keep these very important thoughts in mind as we continue on with the discussion.

Fig. 2: Phase-to-Ground Arcing Fault

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Circuit Breakers Vol 2 Found within the purpose section of the 2014 edition of the NEC®, the standard states: “The purpose of this Code is the practical safeguarding of persons and property from hazards arising from the use of electricity.” [Article 90.1 (A)] “This Code contains provisions that are considered necessary for safety.” [Article 90.1(B)] So you have a new building or an installation that has a GFPR as part of the service entrance. You want to make sure you protect your people and your property, and you want a high degree of certainty that it will perform as intended and as designed. Well then how? It’s really quite simple, actually:

(C) Performance Testing. The ground-fault protection system shall be performance tested when first installed on site. The test shall be conducted in accordance with instructions that shall be provided with the equipment. A written record of this test shall be made and shall be available to the authority having jurisdiction. While the NEC is clear in that the ground-fault protection system shall be performance tested, what is missing (in the author’s opinion) are the words “and shall be conducted by primary current injection.”

MAKE SURE ELECTRICAL PERFORMANCE TESTING OF THE GFPR SYSTEM HAS BEEN COMPLETED BEFORE ENERGIZATION! TESTING AND COMMISSIONING BEFORE ENERGIZATION The acceptance testing of components and the electrical commissioning of a system is critical to safety and reliability. There are many things that can go wrong with the installation, especially when it comes to a GFPR system. From the experience of having actually tested and commissioned literally hundreds and hundreds of GFPR’s, we know that some of the more common problems found prior to, and sometimes well after, initial energization are: ● Incorrect wiring from the current sensor to the GFP relay ● Indicating lamp failure ● Defective or misapplied current sensors ● Improper bonding and/or location of the neutral link connection ● Pickup and delay settings not established or coordinated correctly ● Control power circuits nonexistent or defective ● Defective GFPR control modules ● Main switch/disconnect that will not open on ground-fault signal As it relates to providing a safer application, and as an electrical maintenance testing provider, the frustrating part about nonfunctioning or out-of-tolerance GFPR systems is that the problems are very easily found and corrected in the field simply by applying comprehensive performance testing techniques, yet so many times the complete performance testing tasks are not done. Often, the push to test button is deemed acceptable as a complete test, when in fact it is not. What does the NEC® say about performance testing of groundfault protection systems? Let’s start in Chapter 2, Article 230, Services section of the 2014 Edition of the NEC®, specifically Article 230.95(C) Performance Testing which states:

Fig. 3: Field Testing of GFPR As stated above, the GFPR must be tested as a system, and the only way to completely test the unit as a system is to inject primary current through the main bus or current sensor, through the secondary CT wiring, into the ground-fault protection module, and into the main disconnect switch shunt trip device. If you plan the process and execute a comprehensive performance testing plan for GFPRs, there is a large number of performance-related failures that can be uncovered during the performance testing activities. As stated earlier, the problems range from relatively minor modes of failure, such as an indicating lamp not functioning to major modes of failure, such as no trip under primary fault current conditions. Ground fault systems are not limited to components, but rather, they are a complete system that must be validated and performance tested as a system if the owner and the Authority Having Jurisdiction (AHJ) are to be assured of a properly functioning ground fault protection system. Many of the instructions provided with ground fault protection systems only address one main component, the protective relay, and only require a push to test simulation that does not verify that the other essential components are operational and interconnected correctly. The push to test function, because it is not done by primary current injection, does not completely verify nor validate the performance of the primary sensor, the current transformer windings, the control wiring, and the control power. Nor does it address the location and connection of the main neutral bonding jumper. Because of this it puts the owner at risk of a nonfunctioning ground fault protection system, increasing the possibility of extensive equipment damage and fires when subjected to ground-fault conditions.

42 The procedures for performance testing of both newly-installed and service-aged ground fault protection systems is recognized by industry under the national consensus testing standards ANSI/ NETA ATS-2013, Acceptance Testing Specifications for Electrical Power Distribution Equipment and Systems[3] and ANSI/NETA MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems. As an easily-executed field test procedure for the performance testing of ground fault protection systems, industry standard procedures (from NETA) dictate the following electrical tests… and of special note is item No. 4. While it is not the author’s intent to add all of the industry consensus standard procedures listed below as NEC® requirements, item No. 4 is highlighted as a normal and recognized practice for performance testing in the field of ground fault protection systems. Excerpts from NETA ATS-2013, Section 7.14, Ground-Fault Protection Systems, Low-Voltage; Electrical Tests are as follows: 1. Perform resistance measurements through bolted connections with a low-resistance ohmmeter, if applicable, in accordance with Section 7.14.1. 2. Measure the system neutral-to-ground insulation resistance with the neutral disconnect link temporarily removed. Replace the neutral disconnect link after testing. 3. Perform insulation resistance test on all control wiring with respect to ground. Applied potential shall be 500 volts dc for 300-volt rated cable and 1000 volts dc for 600-volt rated cable. Test duration shall be one minute. For units with solidstate components or control devices that cannot tolerate the applied voltage, follow manufacturer’s recommendation. 4. Perform ground fault protective device pickup tests using primary injection. 5. For summation type systems utilizing phase and neutral current transformers, verify correct polarities by applying current to each phase-neutral current transformer pair. This test also applies to molded-case breakers utilizing an external neutral current transformer. 6. Measure time delay of the ground fault protective device at a value equal to or greater than 150 percent of the pickup value. 7. Verify reduced control voltage tripping capability is 55 percent for ac systems and 80 percent for dc systems. 8. Verify blocking capability of zone interlock systems.

Circuit Breakers Vol 2 IS IT REALLY THAT CRITICAL? There are many reasons why you need your ground-fault protection system to function properly, and one of the real dangers of a nonfunctioning GFPR system is an arcing ground fault…. especially one that occurs below the pickup levels of the upstream overcurrent protective devices, which can create a condition that causes extensive damage to property and can possibly injure personnel. NETA provides guidance on what to do to perform acceptance and maintenance tests on ground-fault protection systems in the field, and the NFPA, in addition to the performance testing requirements found in Article 230.95(C) the NEC®, offers additional guidance in Article 225, Article 708, and Informative Annex “F”, which even further highlights the need to test these critical components in industrial and commercial power systems. So forego the push-to-test button and test your GFPR as a system by primary current injection as detailed in the NETA testing standards to provide peace of mind that the system will work when called upon. If you don’t think ground-fault relays are that important, come along on one of the projects I’m sure we will have in the upcoming months that require equipment repair and replacement due to an inoperable ground fault protection relay…

REFERENCES: Bussmann; Selecting Protective Devices Handbook (SPD) Based on the 2014 NEC® National Fire Protection Association; NFPA 70, National Electrical Code, 2014 Edition InterNational Electrical Testing Association, ANSI/NETA ATS2013, Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems Ron Widup is the CEO of Shermco Industries in Dallas (Irving) Texas and has been with Shermco since 1983. Shermco provides electrical power system testing, maintenance, commissioning, engineering, and training in the United States and Canada as well as electric rotating machinery remanufacturing and service. Ron has a degree in Electrical Power Distribution from Texas State Technical College in Waco, Texas. He is a NETA Certified Level IV Senior Test Technician, State of Texas Journeyman Electrician, a member of the IEEE Standards Association, an Inspector Member of the International Association of Electrical Inspectors, and an NFPA Certified Electrical Safety Compliance Professional (CESCP).

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Circuit Breakers Vol 2

POWERING UP THE LATEST HV CIRCUIT BREAKER TESTING TECHNOLOGIES NETA World, Fall 2015 Issue Charles Sweetser, OMICRON electronics Corp. USA

Understanding diagnostic testing of HV circuit breakers is essential. When diagnostic tests are performed on HV circuit breakers, valuable information can be extracted. From a technical maintenance perspective, these diagnostic tests provide critical information about the condition of the HV circuit breakers. Standard field tests widely applied today in HV circuit breaker diagnostics include: ● Timing and travel ● Contact resistance (static and dynamic) ● Coil and motor current signatures

These subsystems above need to be analyzed both separately and as a complete electro-mechanical system. Timing and Travel Circuit breaker timing and travel measurements entail three steps: 1) Perform a dynamic timing and travel measurement 2) Calculate performance characteristics 3) Compare results to the manufacturer’s recommendations or user-defined limits Table 1 provides the fundamental tests and calculations involved in circuit breaker timing measurements and diagnostics.

● Minimum pick-up

Circuit breaker technology varies depending on the application. Also, the preferred technology is dependent on the geographical region in which it is applied. Case in point, dead tank SF6-filled circuit breakers and bulk oil circuit breakers are primarily used in North America in HV applications, while the rest of the world prefers live tank circuit breaker technology. Regardless of type and technology, circuit breakers are generally designed with the following three functions in mind: ● Direct current flow between desired sections of an electric power system ● Interrupt current flow under abnormal power system events and conditions, such as faults ● Carry load current under normal power system conditions with minimal losses

These three functions must be performed under normal and abnormal (fault) conditions as well as under strict performance specifications. Circuit breakers vary by subsystems: ● Insulation System ● Arc quenching method ● Mechanism ● Contact technology ● Control circuit schemes

CONTROL

MEASUREMENT

CALCULATIONS

Trip (O)

Displacement

Main Contact Timing

Close (C)

Contact State (O-R-C)

Resistor Switch Timing

ReClose (O-C)

Command Coil Current

Delta Timing (Pole Spread)

TripFree (C-O)

Auxiliary Contact State (OW-OD-C)

Velocity

(O-CO)

Battery Voltage

Total Travel

(O-CO-CO)

Phase Currents

Over Travel

Slow Close (C)

Dynamic Resistance (DRM)

Rebound

First Trip (O)

Stroke Contact Wipe Dwell Time (TripFree C-O) Dead Time (ReClose O-C)

Contact Resistance (Static and Dynamic) Contact resistance can be a complicated subject. Contact assemblies can consist of main and arcing contact components. To see both components, the contact resistance is analyzed, statically and dynamically, respectively. Using a dc current source, a static contact measurement is performed on each phase. Typical measurements are less than 100 µΩ; however, the manufacturer’s literature should help determine the actual expected value. Considering all breaker types, experience has shown measurements range from 10 to 150 µΩ depending on the type, with low-voltage vacuum breakers associated with

44 very low measurements and higher voltage SF6 dead tank breakers producing the higher measurements. At least 100A dc should be injected for this test. Also, if the breaker is equipped with CTs, it may take several seconds to stabilize the opposing effects. Take precautions to ensure that the injected high primary current does not affect protection circuits. The dynamic resistance measurement is a diagnostic tool to assess the condition of the arcing contacts in SF6 nozzle style interrupters. By measuring the current, voltage, and displacement associated with the contact assembly, it is possible to determine the wear level and integrity of the arcing contact. Like the static contact resistance measurement, this measurement requires highcurrent injection to be successful. Common practice is to use at least 100A DC.

Coil and Motor Current Signatures Information regarding lubrication, electrical coil performance, and latch operation can be extracted by analyzing the command coil signatures. Lubrication problems are easiest to identify in this scenario. As the armature of the command moves, an expected command coil signature is generated. With motor current signatures, the behavior of the motor current shows you the power needed and how it is consumed by the motor. Unusual current levels and motor timing indicate a potential electrical fault in the motor.

Minimum Pick-Up The minimum pick-up measurement is performed to determine the minimum command coil voltage (trip or close) required to operate the circuit breaker. This is the minimum energy need for the command coil to release the latch. The latch can either be a mechanical release mechanism or a value used to control a pneumatic or hydraulic system. This test is done for each control coil of a circuit breaker. Different considerations must be given to ganged versus independent pole operation (IPO) circuit breakers. All command coils should be tested independently. The IPO breaker may require several more tests to include all command coils.

Optimized Toolset Modern diagnostic test instruments are more than just a data acquisition system. The circuit breaker toolset must include not only measurement capabilities, but also an advanced power source. This power source is needed for contact resistance and minimum pick-up. What’s more, by having this power source makes it possible to operate control circuits, coils, and motors when substation power is unavailable.

Circuit Breakers Vol 2 The diagnostic circuit breaker toolset must provide three functions: ● Timing and travel analyzer ● µ-ohm meter (contact resistance) ● Advanced power supply Therefore, the functions will provide the ability for performing the following tests: ● Timing and travel ● Contact resistance (static and dynamic) ● Coil and motor current signatures ● Minimum Pick-Up It is important today that we are not only monitoring the performance of circuit breakers, but also determining key condition indicators. Utilizing an optimized and pertinent toolset is essential when determining and assessing circuit breaker health. It is important to recognize the value of all available diagnostic tools, beyond just timing and travel, and to implement them appropriately. Understanding the benefits of timing and travel tests, contact resistance (static and dynamic), coil and motor current signatures, and minimum pick-up is a key component to extending the life and maintaining proper operation of circuit breakers. Charles Sweetser received a B.S. in Electrical Engineering in 1992 and an M.S. in Electrical Engineering in 1996 from the University of Maine. He joined OMICRON electronics Corp. USA in 2009, where he serves as PRIM Engineering Services Manager for North America. Prior to joining OMICRON, he worked 13 years in the electrical apparatus diagnostic and consulting business. He has published several technical papers for IEEE and other industry forums. As a member of IEEE Power & Energy Society (PES) for 15 years, he actively participates in the IEEE Transformers Committee, where he held the position of Chair of the FRA Working Group PC57.149 until publication in March 2013. He is also a member of several other working groups and subcommittees. Additional interests include condition assessment of power apparatus and partial discharge.

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Circuit Breakers Vol 2

COMBINED CURRENT AND VOLTAGECONTROLLED SOURCE IN ARCING CONTACTS CONDITION ASSESSMENT NETA World, Winter 2015 Issue Adnan Secic and Radenko Ostojic, DV Power, Sweden

Preventive maintenance of a high-voltage circuit breaker (HVCB) begins with collecting a useful data set, directly where the breaker is installed. Manufacturers provide limits for the majority of testing parameters. Those limits are very useful for maintenance companies as a reference for preventive maintenance diagnostic procedures. For example, consider the opening time, which is a standardized parameter available on the breaker nameplate or in its technical documentation. The manufacturer guarantees that after leaving the production line, the certain circuit breaker (CB) type will trip within these limits after receiving a command from the relay protection. In the event of a short-circuit current, a quick response from an HVCB means that disaster in the electric power system can be prevented. In addition to reference data, maintenance companies often reuse data collected throughout the previous tests. Although it is the simplest way to compare several numerical results to see whether those results are within expected limits, often a set of collected data is more complex and requires a different representation (e.g. in a graphic form, tabular form, etc.) as well as the use of different comparison methods. Considering the large number of installed units, data comparison should be as simple as possible. To clarify information in the maintenance history, standardized measurement methods are needed. Today, a large number of international and national standards are defining the way tests are performed and what data is collected during the testing procedures.

DYNAMIC RESISTANCE MEASUREMENT Frequently, an established practice needs the application of new test methods before it becomes a standard. One of these tests is the dynamic resistance measurement (DRM). The output data set of this test includes a graph showing the movement of the breaker contacts measured by a motion transducer, and a graph representing changes in its resistance during operation. It is important to emphasize that this test can be performed on a fully assembled interrupting chamber. (See photo of HVCB Arcing Contact.) Standards already indicate the dc current value needed to measure the static resistance of an HVCB (higher than 50A). Logically, the DRM should be performed with the same current values.

High-Voltage Circuit Breaker Arcing Contact To simplify comparison of the data, it is necessary to have similar test conditions for different testing intervals. Older measurement methods were based primarily on using a high-power current source and recording the tripping operation data of an HVCB. In this case, considering that the initial state of the breaker is the closed position, it is possible to use the current source to achieve the desired current value. Note that the DRM test’s main goal is to indicate the state of arcing contacts, not to simulate a real-life situation. Actually, portable testing equipment provides significantly lower currents compared to those that occur in real CB operational situations.

DYNAMIC RESISTANCE CURVE DURING THE CLOSING OPERATION Why is DRM needed to capture the dynamic resistance curve during the closing operation of an HVCB? Reasons include: ● During closing operation, the arcing contacts will close first. Contact closing is always followed by more bouncing periods than during the contact opening stage. ● Arcing contacts conduct the current from the initiation of the current flow at pre-strike, followed by pre-arcs stages until the moment the main contacts touch.

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Circuit Breakers Vol 2

● Deformation and erosion of the arcing contact that occurs as a result of electrical and thermal stress generated by the arc is unique to each current-breaking process. For diagnostic

1) Maximum output current is defined by the minimum load (the breaker in a closed position) and is adjusted in the first step of the measurement procedure.

purposes, this is why the dynamic resistance curve should be recorded and observed while contacts are moving in both directions.

2) Current regulation eliminates influence of the cable’s crosssection and length, which ensures similar test conditions in different situations.

● It is always better to extend the useful data set to increase diagnostic’s reliability.

3) Note that the first reported DRM measurements in the 1990s were performed by using 12V car batteries. Many users are accustomed to this approach.

TESTING METHODOLOGY As previously stated, it is helpful to achieve approximately the same test conditions to simplify comparisons of test results. Portable equipment used for DRM needs an integrated power source to provide a high current for the tests. Tests are performed from the ground, which requires cables attached at the height of the CB bushings. This sometimes requires long cables, but the method is best with a small electric resistance, which in turn, requires a larger cross-section. Obviously, it is easier to carry the equipment if it weighs less, but conflicting requirements make this a challenge. Therefore, a compromise is needed. The selected source must be very powerful and lightweight, and the only way to accomplish this is to use a high-frequency dc/dc converter, which will allow higher test currents and eliminate the need for heavy and robust parts such as transformers. Maximum current from the source will flow when the output load is minimal or when the breaker is in a closed position. Therefore, the logical first step in the DRM testing procedure is a current regulation through the closed breaker contact. Current source can be used for that purpose. In this case, regulator feedback will be the total current measured on a resistor shunt or by any other current measurement method (Figure 1).

Fig. 1: Combined current and voltage feedback on a high-power source provides synergy in testing high-voltage circuit breaker arcing contacts. After the desired current is achieved, the regulator switches to the voltage control mode, and the feedback value is memorized. The device output can be temporarily disabled, and the breaker set to the open position. This completes the condition setup for performing DRM and achieves the following objectives:

Starting with the CB open position, the test steps include: 1) Set the output voltage according to the feedback value recorded by the microcontroller unit. The source now works in a voltage mode. 2) Issue the closing command to the closing coil of the HVCB. During the breaker operation, the total current and voltage drop measurements across breaker contacts and motion of the breaker contacts are performed simultaneously 3) After the measurements have been completed, the controller turns off the voltage source.

Safety Methodology A very important aspect of the testing procedure is safety of the test personnel. Grounding the test object on both sides (grounding of the CB terminals) significantly minimizes the risks. In this case, grounding the CB terminals affects the measured resistance. Experimental results are showing that ground resistance and resistance of the grounding cables (Rg) varies in the range of several tens of milliohms (mΩ). On the other hand, resistance of the main contacts (Rm) is much lower and is usually measured in tens to several hundreds of micro ohms (uΩ); the resistance of the arcing contacts (Ra) is usually around a couple of milliohms (mΩ). This means that due to the grounding of the breaker terminals, the total measured resistance of the contacts will be lower than the actual contact resistance. Total resistance measured for the main contacts is equal to Rmg=Rm || Rg, while the total measured resistance of the arcing contacts is equal to Rag=Ra || Rg. However, if a high current is applied during the dynamic resistance measurement process, it is still possible to detect the moment of separation of the main and arcing contacts, which is the primary reason for performing the test. This has been confirmed by performing tests on CBs with a high current measurement module.

REAL OBJECT TESTING Figures 2A and 2B show the DRM results obtained during closing and opening operations of an HVCB. In this figure, results are given in graphical form to represent coil current, voltage, and current through the breaker contacts, motion of the contact mechanism measured by linear motion transducer, and contacts velocity calculated from motion results. The breaker was grounded on both

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Circuit Breakers Vol 2 sides. Measured grounding resistance was approximately 10mΩ, contact resistance approximately 150uΩ, and maximum test current was 100A. This current was regulated with breaker contacts in the closed position, and the regulator was switched to voltagecontrol mode to provide the necessary conditions for performing the test.

During the closing operation, DRM provides more insight into resistance changes inside of the breaker chamber during movement of the contacts. On the other hand, closing of the breaker contacts will result in a mechanical impact, which is inevitably followed by some bouncing periods. Recording of this phenomenon may provide additional information on the state of the contact system and the contact springs, especially if it is taken into account that DRM will provide insights into resistance changes on a milliohm level. Further simplification of this measurement procedure would lead to the recording of the DRM curve during the open-close or close-open operations of the HVCB. That way, all the necessary information could be recorded with only one measurement.

Fig. 2A

Fig. 2B

Fig. 2A and 2B: DRM Results – Top graph is mechanism velocity, second is mechanism motion, and third is dynamic resistance. Bottom is coil current. Results show that the average breaker speed during closing of the contacts is slower than the speed during the opening operation. This makes perfect sense because the CB’s main task is to interrupt short-circuit current, implying that the contacts must have a higher speed when opening. This also implies that the arcing contact overlapping time will be longer for the closing operation of an HVCB. The measured arcing contact overlapping time for the closing operation was 3.8ms, and for the opening operation it was 2.3ms.

High-Voltage Circuit Breaker Testing

SUMMARY When the circuit breaker is out of service, it generates a financial loss for the utilities. To ensure reliable operation, it is necessary to perform offline tests occasionally. During regular maintenance procedures, all other means must be exhausted before disassem-

48 bling the interrupting chamber. This implies conducting a series of tests and measurements and using the results for diagnostic purposes. (See photo of High-Voltage Circuit Breaker Testing.) Tests and measurements should be conducted in the shortest time possible, and the results should be easily comparable with the results obtained in the past. Therefore, it is necessary to find ways to extend the useful data set for the offline testing procedures. Applying the voltage across the CB coil will trigger a CB operation and cause the contacts to move. Movement of the contacts inside of the chamber leads to changes in the total resistance measured from the breaker terminals. This is the only parameter that can provide insight into the state of contacts on a fully assembled CB. The only way to detect such low changes is to apply a high current through the DRM. The DRM test may be carried out during CB opening and closing operations. For the CB’s closing operation, the DRM procedure must be slightly modified to protect the power source used and achieve similar test conditions for different testing intervals. This approach will meet the basic test requirement of having comparable results. Separation and closing of the CB contacts are different physical processes (closing of the contacts is always followed by several bouncing periods), so all these characteristics should be taken into account during diagnostic processes. Most of the utilities have adapted DRM during opening of the CB as a standard testing procedure during maintenance operations. Appropriate cables and test equipment are necessary to perform the test. The DRM test can also be performed during the closing operation of the HVCB. This test approach does not require any additional connection to the CB terminals. The only modification is adding a connection to the closing coil control. The time needed to perform the test does not greatly affect the total out-of-service time; the useful data set is extended, and this can lead to better diagnostics. Adnan Secic is an R&D Engineer at DV Power,Sweden. As a project leader, he is responsible for development of the Circuit Breaker Analyzer and Timer (CAT) device series. In 2014, Adnan received his M. Sc. degree in EEA (Electronics, Electrical Engineering and Automation). Radenko Ostojic is a Test Engineer at DV Power, Sweden, working on the improvement of CB testing equipment and development of new methods for CB testing.

Circuit Breakers Vol 2

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Circuit Breakers Vol 2

THE EVOLUTION OF CIRCUIT BREAKERS NETA World, Summer 2016 Issue Paul H. Grein, Circuit Breaker Sales Co. Inc.

This article examines the changes to medium voltage circuit breaker testing over three generations spanning 70 years from 1945 to today. It discusses the challenges and driving forces that evolved circuit breaker testing, including technological advances in circuit breaker technology, safety practices, and test equipment.

Fig. 1: DThe Evolution of Circuit Breakers Photo courtesy Brian Kaylor

In May 1945, World War II ended; that same year, Westinghouse introduced its first medium-voltage air-magnetic circuit breakers, and the first American standard for ac power circuit breakers was published. Circuit breakers of the day were heavy, expensive, unreliable devices that required regular upkeep to ensure they performed as expected. Early technicians worked in hazardous environments where profits often trumped employee safety. Over three generations spanning 70 years, circuit breaker technology has advanced and safety practices have improved. This article examines three generations of circuit breaker technicians, and how technological and safety advancements have led up to the testing they perform today.

THE OIL YEARS, 1945 – 1975 The Golden Years is often the moniker used to describe the period following World War II. Regulatory intervention from federal and local governments was minimal, and the power equipment industry benefited immensely from an era of rapid growth. Between the years 1946 and 1947 alone, power usage grew almost 15 percent, creating an avid demand for power equipment and men qualified to operate and maintain it. The demand for electric power and advances in productivity created a need for circuit breakers with higher current ratings and interrupting capacities. Growth continued for decades, at a diminishing rate, until it stagnated in the tumultuous 1970s to the average 7 percent we see today. While the Golden Years may delineate the economic growth that drove the circuit breaker industry, the Oil Years better describes the breaker technology that ruled the era.

Circuit Breakers in the Oil Years Before and in the decades immediately following World War II, the most common medium-voltage circuit breaker technology used was oil-tank circuit breakers. Many of the switchgear manufacturers that served the American market during World War II remain in business today, including General Electric, Westinghouse (now Eaton Cutler-Hammer), and ABB. This article bases its discussion on Westinghouse’s introduction of circuit breaker technology with the understanding that competing manufacturers may have innovated the technology earlier or later. The 1940s saw the beginning of a major transition from oil-tank to air-magnetic circuit breakers, but oil-tank technology remained the workhorse of American utilities and factories. Despite the introduction of air-magnetic technology, Westinghouse continued manufacturing its type B and type F oil-tank circuit breakers into the early 1950s. However, extinguishing the arcs produced from larger interrupting currents in insulating oil was reaching its technological limit; for the Westinghouse model B-28-B to achieve maximum ratings of 15kV, 500MVA, 2000A, the breaker had swollen to over 2,000 pounds. To meet the continually increasing demand for higher ratings, Westinghouse introduced its DH-type medium-voltage air-magnetic circuit breakers and switchgear in 1939. Initially the DH line was limited to 5kV up to 150MVA, but by 1946, the maximum voltage of the DH was extended to 15kV; over time, the maximum rated interrupting capacity of the DH breaker reached 1,000 MVA. In 1963, Westinghouse introduced the DH-P type air-magnetic Porcel-line® circuit breaker and switchgear, with all live parts insulated to ground by high-strength porcelain insulation versus the paper phenolic insulation used in the DH designs, but by this time the oil-generation circuit breaker technician was certainly eyeing retirement.

Safety in the Oil Years Safety was not a priority in industrial environments until the Occupational Safety and Health Administration (OSHA) was created in 1970 when the Williams-Steiger Act was signed into law. Electrical safety was not emphasized until 1979 when the National Fire Protection Association (NFPA) published NFPA 70E, Standard for Electrical Safety in the Workplace, at OSHA’s request. Prior to OSHA and NFPA 70E, responsibility for maintaining safe work practices fell on the technician, and electrically safe work practices were anything but. Electrical safety in the beginning of the

50 oil generation can be summed up by this excerpt from the American Electricians Handbook of 1942, which is comical by today’s standards:

“158. Electricians often test for the presence of voltage by touching the conductors with the fingers. This method is safe where the voltage does not exceed 250 and is often convenient to locate a blown-out fuse or for ascertaining whether or not a circuit is alive. Some men can endure the electric shock that results without discomfort whereas others cannot. Therefore, the method is not feasible in some cases. Which are the outside wires and which is the neutral of a 115/230-volt, three-wire system can be determined in this way by noting the intensity of the shock that results by touching different pairs of wires with the fingers. Use the method with caution and be certain the voltage of the circuit does not exceed 250 before touching the conductors.” The precautions listed in circuit breaker instruction and installation books of the day were largely written to protect the equipment from being damaged rather than protecting personnel from injury. The equipment was designed for increased operating safety when compared to previous generation designs; the primary circuits were isolated via steel barriers rather than exposed, and interlocking was integrated into the racking mechanism. Advanced safety features aside, working with oil-tank circuit breakers was a risky endeavor; the breakers were formidable devices whose bulk made them difficult to install and maintain, and their insulation systems were antiquated and often toxic. Combining these factors with the early manufacturing capabilities of the day resulted in unreliable operation, especially compared to today’s standards. When oil circuit breaker failures occurred, the consequences were usually catastrophic.

Circuit Breaker Testing in the Oil Years The majority of circuit breaker testing performed in the oil years was a mechanical process analogous to performing maintenance on an automobile rather than maintaining electrical equipment. Maintenance consisted of testing, cleaning, and changing the oil then physically inspecting the operating mechanism, contact condition, connections, and looking for signs of carbonization. Maintenance was performed by in-house technicians with limited specialized training or test equipment. If available, dedicated test equipment was limited to dielectric test sets that measured the insulating oil resistance and high-potential test sets for the solid insulation. Test equipment and practices did improve through the oil years, but advancements were adopted slowly. It wasn’t until the next generation that circuit breaker testing would begin to resemble what we see today.

THE AIR YEARS: 1965 - 1995 The economic good times experienced during the golden years following World War II would not last forever. A combination of

Circuit Breakers Vol 2 macroeconomic events — including the oil embargo of 1973 — stalled the economy, but growth in the power equipment industry crept along at 7 percent. While the economic setting of the period may have been the Air Years between 1965 and 1995, the technological advances and safety environment we experience today took root in the Air Years between 1965 and 1995.

From Oil to Air As mentioned previously, the transition from oil-tank to airmagnetic circuit breakers began in the 1940s, but the first generation of air circuit breakers was limited to light-duty applications with maximum ratings of 5kV, 50MVA, 1200A. However, customer interest for the new technology and the technological limitations of oil-tank designs encouraged manufacturers to increase ratings quickly. In 1946, air magnetic circuit breaker ratings were extended up to 15kV, 500MVA, 2,000A applications. The first generation of Westinghouse air-magnetic breakers reached their technological limit in 1958 with the model 150-DH-1000, 3,000A circuit breaker. To reach the extended 1,000MVA interrupt and 3,000A continuous current ratings, the breaker design had bloated to 3,908 pounds with each arc chute weighing in at over 600 pounds! The introduction of air-magnetic technology brought many advantages over the oil-tank breakers they replaced, including: ● Removal of the oil and the associated chemical and fire hazards ● Higher contact breaking speeds and faster arc quenching ● Smaller arc duration allowing extended service life of contacts ● Extended interrupt and continuous current ratings ● Smaller size and weight at a given rating ● Much less maintenance Westinghouse introduced its second generation DH-P Porcelline model air-magnetic circuit breakers in 1963. Initially, the breakers were rated up to 15kV, 750MVA interrupt, and 2,000A continuous current ratings; by 1974, the maximum current ratings were increased to 1,000MVA, 3,000A. The innovations introduced in second-generation air circuit breaker technology stemmed from advancements in design, materials, and manufacturing. Rather than paper phenolic insulation used in early generation circuit breakers, the DH-P relied on porcelain to insulate all live parts from ground. Porcelain and similar advanced insulation material technologies are non-tracking, noncombustible, and non-hygroscopic. The reduction of insulation tracking and non-hygroscopic properties allowed circuit breakers to become more compact and lowered the risk of failure from flash-over, increasing reliability and safety. Technician safety was also improved by replacing antiquated materials that could be toxic when mishandled. Early air circuit breaker designs were furnished with a solenoid operated mechanism with cast parts and monolithic pole assemblies. By the late 1960s, stored-energy spring mechanisms had

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Circuit Breakers Vol 2 phased out the solenoid operator, markedly increasing operating speeds. By 1968, cast mechanisms were replaced with machined and modern fabricated mechanisms. Finally, after 1970, monolithic pole units were phased out by the post-insulator pole unit, the single/isolated pole designs employed today. These and other advancements to circuit breaker design had an enormous impact on circuit breaker reliability — so much so that it is common to find equipment commissioned in the 1960s still in use today, over 50 years later. At the end of the Air Years, vacuum circuit breaker technology was arriving in American utilities, factories, and distribution systems. The first-generation vacuum breakers, such as the Westinghouse DVP introduced in 1978, were directly interchangeable with the air-circuit breakers they would eventually replace. The improvements that accelerated during the air years were not limited to circuit breaker technology. Test equipment and especially safety practices developed considerably during the Air Years.

THE AIR SAFETY YEARS The safety environment that many of us take for granted today was pioneered a generation ago as workplace and electrical safety originated during the Air Years. After the Williams-Steiger Act was signed into law in 1970, creating OSHA, in 1979 the NFPA published NFPA 70E, the first nationally accepted standard that addressed electrical safety requirements for employee workplaces. The first edition of NFPA 70E included installation work practices; since that first edition, the document has continuously improved. Published in 1981, the second edition added safety-related work practices. In 1983, safety-related maintenance requirements were included as well. At the end of the Air Years in 1995, the fifth edition of NFPA 70E introduced arc-flash hazards. Since their partnership began, OSHA and NFPA have worked together to establish standards and codes documenting safe work practices to ensure employee safety in the workplace and levy fines when those standard are not followed. The Air Years established the advancement of technician safety through the foundation of standardized and enforced safety practices, which in turn impacted how breaker testing was performed.

Air Years Circuit Breaker Testing From generation to generation, circuit breaker testing requirements have expanded in scope and scale. The introduction of new circuit breaker technology and the advancement of test equipment and safety practices brought forth both new types of tests and testing requirements. The transition between circuit breaker technologies was a gradual process requiring technicians to maintain the equipment of current and previous generations. The growing knowledge and experience required to effectually test the rapidly expanding arena of circuit breaker technologies led to the increased use of specialized breaker technicians, often employed from outside testing compa-

nies versus in-house technicians. Outsourcing circuit breaker testing introduced new challenges, the largest of which was ensuring that testing was performed consistently and accurately by suitably experienced and trained technicians. A group of electrical testing business owners recognized the need to standardize electrical testing to combat the inconsistent testing and safety practices that were commonplace. In 1972, the National Electrical Testing Association (NETA) was formed with the goal of establishing uniform testing procedures for electrical equipment. In 1977, NETA published its ATS-1977, Acceptance Testing Specifications for Electrical Power Distribution Equipment and Systems. The ATS-1977 illustrates how circuit breaker testing expanded since the 1940s. Comparing the maintenance recommendations from circa 1940s and 1950s maintenance manuals to the ATS-1977 test recommendations for like equipment gives an indication of how the types of testing continue to grow. Apart from the basic mechanical inspections predominant in the Oil Years, all of the following tests either took root or became expected during the Air Years: 1) Visual and mechanical inspections

• Contact alignment and condition • Lubrication • Tightness of bolted connections

2) Contact resistance 3) Travel time test

4) Sample insulating liquid

• Dielectric strength • Acidity • Interfacial tension • Color

5) Minimum pickup voltage tests

• Close • Trip

6) Insulation resistance testing 7) AC and/or dc over-potential testing 8) Control wire insulation testing 9) Power factor testing The expanding knowledge requirement was not limited to understanding the idiosyncrasies of the various types of breaker technology — not to mention the various manufacturers and models — but also included the theory and application of new testing requirements. Testing was beginning to see a gradual transition from corrective to preventative maintenance, a trend that would accelerate in generations to come.

THE VACUUM GENERATION: 1985 – TODAY For much of America, the 1970s was a tumultuous time and the 1980s were not free from hardships, but most would agree that

52 history has shown the decade to be a turning point for the country economically and technologically. Driven in part by the intense competition between the United States and the Soviet Union, technological innovation and other advancements exploded in vacuum generation. Many of the most significant circuit breaker advancements took place during the Vacuum Generation.

Vacuum Circuit Breakers In 1978, Westinghouse introduced the DVP type in 500 and 750 MVA, its first vacuum circuit breaker model. The DVP was not a new line (a switchgear); it was an introduction to vacuum technology used with its existing DHP Porcel-line switchgear (directly-interchangeable, identically-rated DH-Ps). Competing manufacturers took a similar approach to introducing vacuum interruption technology. In 1981, Westinghouse introduced its VCP line of vacuum circuit breakers and associated VacClad switchgear in ratings up to 15kV and 1,000 MVA. VCP was Westinghouse’s first generation of modern vacuum circuit breakers.

Circuit Breakers Vol 2 MODERN SAFETY During the Air Years, the largest contributor to technician safety was the development and enforcement of modern safety practices. In the Vacuum Generation, safety practices were further enhanced by OSHA’s institution of lock-out/tag-out procedures in 1989, the recognition of arc-flash hazards by the NFPA in 1994, and subsequent efforts to reduce exposure to arc flash. Recent efforts to reduce or remove the risk of arc flash include arc-flash studies, the implementation of remote and integrated racking devices, and use of advanced personal protective equipment. During the Vacuum Generation, the most significant contributor to safety was technological innovation. The advantages of vacuum circuit breaker technology partnered with modern manufacturing capabilities and materials have dramatically increased the reliability of modern power equipment operation and safety features. Increased equipment reliability results in longer maintenance cycles and fewer failures, which in turn reduces maintenance technicians’ exposure to the hazards.

● Removal of air-magnetic arc chutes eliminates associated maintenance and handling issues.

Despite the progression of safety afforded by procedural and technological advancements, the modern technician faces many of the same risks as those of previous generations. The implementation of new technology in the power industry is a slow process. There are countless installations across the United States that still use airmagnetic and even oil-tank circuit breaker technology that has been in service for over 40 or even 50 years. The continually expanding knowledge and experience level required to safely maintain power equipment technology spanning three generations may be the greatest challenge to present-day maintenance technicians.

● Contact upkeep is reduced to monitoring versus maintenance.

Testing Technicians Today

Vacuum interruption is arguably the most significant innovation in medium-voltage circuit breaker technology. Vacuum interruption has numerous advantages over previous generation equipment, including: ● Breaker size and weight are significantly reduced, allowing two-high stacking construction and making them physically easier to remove and transport for maintenance.

● Vacuum insulation strength greatly reduces the required contact gap, allowing breaker operating mechanisms to become faster to operate, more reliable, and easier to maintain. ● Interrupting arcs are contained, making them non-explosive. ● The mechanisms require significantly less stored kinetic energy during operation, making them safer to maintain. In 1986, Westinghouse introduced the second generation VCPW line of vacuum circuit breaker and associated VacClad-W switchgear in ratings up to 15kV at 1,500 MVA and 38kV at 40kA. VCP-W included product improvements in manufacturing design and performance. In 1995, an arc-resistant version of the VCP-W brand was introduced: CP-W is Eaton’s current switchgear offering in medium voltage. The most recent innovations in medium-voltage circuit breaker technology involve the operating mechanism rather than the interrupting medium. Several manufacturers have introduced magnetic-actuator operating mechanisms that have few moving parts, require no maintenance or adjustments over the life of the product, and are warranteed for five years versus the industry standard of one year.

So far, three generations of circuit breakers have been discussed — the oil, air, and vacuum eras — as well as how technology and safety advancements have affected circuit breaker testing. The primary challenge that today’s technicians face is the overwhelming level of expertise needed to effectively and safely evaluate three generations of equipment. Over the last 70 years, there have been four or five major and several minor switchgear manufacturers that have collectively produced over 100 combinations of models and ratings of medium voltage circuit breakers. Medium-voltage circuit breakers have been the focus of this article, but electrical maintenance personnel and technicians are also responsible for testing the entire lineup of electrical equipment, including low-voltage circuit breakers, motor starters, transformers, cables, motors, metering, relays, and ground fault systems. To overcome these challenges, technicians have evolved from mechanics to electrical maintenance personnel to technicians who specialize in narrow fields of expertise. Specialized technicians may have some experience on the entire spectrum, but have focused expertise and training that is limited to a few — and sometimes a single — category of electrical equipment. No matter what their specific category of expertise may be, all technicians must be trained and proficient in safe work practices.

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LOOKING FORWARD

gear. Pittsburgh: Westinghouse Electric & Manufacturing Company.

The greatest changes to the industry are — and will continue to be — driven by globalization and advancements to circuit breaker and manufacturing technologies. These and other factors have driven costs down to where it almost makes more sense to replace equipment rather than maintain it, and modern breaker designs encourage that practice.

Westinghouse (1949). Instructions - High-Voltage Metal-Clad Switchgear with “F” and “B” Oil Circuit Breakers. Pittsburgh: Westinghouse Electric Corporation.

Circuit breaker designs are becoming modular. The trend began with plug-and-play parts such as coils and motors, but now, complete mechanisms and interrupting assemblies are designed to be quickly and easily replaced in the field. Opinions will vary on whether the philosophy of “make it fast” over “make it last” is an improvement, but everyone should agree that equipment installed today will still be in service in the year 2075. Over the years, the means and methods of electrical testing may have changed, but the goal has remained the same: the upkeep and preservation of electrical equipment. Dramatic improvements to circuit breaker technology, safety practices, and testing capabilities have resulted in continually increasing performance and reliability. Without question, modern equipment is easier and safer to maintain, and as the aging equipment of previous generation is slowly upgraded and industry innovations advancements continue, the risks and costs of maintaining it will continue to decrease.

REFERENCES ABB (2014). AMVAC. Medium Voltage Indoor Circuit Breakers Descriptive Bulletin, pp. 6-7. Lake Mary: ABB. Croft, T (1942). American Electricians’ Handbook, 5th Edition. New York: McGraw-Hill Book Company. Eaton (2013). Medium Voltage Switchgear. In CA08100014E Aftermarket, Renewal Parts and Life Extension Solutions Catalog, pp. V12-T17-53 - 64. Eaton. Howell, J (2014). NETA — Setting the Standard. NETA World Journal, pp. 1-4. Jooma, Z. (2016). History of the NFPA 70E. Retrieved from Electricity and Control: http://www.eandcspoton.co.za/resources/docs/Hazardous/History_of_the_NFPA.pdf Littelfuse (2005). Electrical Safety Hazards Handbook. Des Plaines: Littelfuse Inc. NETA (1977). Acceptance Testing Specifications for Electrical Power Distribution Equipment & Systems. Meriden: National Electrical Testing Association. U.S. EIA (2016, January 15). History of Energy Consumption in the United States, 1775–2009. Retrieved from U.S. Energy Information Administration’s Today in Energy: https://www.eia. gov/todayinenergy/detail.cfm?id=10# Westinghouse (1941). Type “DH” “De-ion” Air Circuit Breakers Instruction Book. Pittsburgh: Westinghouse. Westinghouse (1944). “Unitized” Heavy-Duty Metal-Clad Switch-

Westinghouse (1949). Unitized Metal-Clad Switchgear LightDuty DH Type — Descriptive Bulletin. East Pittsburgh: Westinghose Electric Corporation. Westinghouse (1958). Descriptive Bulletin — Standardized MetalClad Switchgear. East Pittsburgh: Westinghouse Electric Corporation. Westinghouse (1959). Instrcutions — De-ion Air Circuit Breaker Type 150-DH-1000. East Pittsburgh: Westinghouse Electric Corporation. Westinghouse (1965). Porcel-line Metal-Clad Switchgear with Type DH-P Air Circuit Breakers — Descriptive Bulletin. East Pittsburgh: Westinghouse Electric Corporation, Switchgear Division. Paul Grein has been with GroupCBS since 2008, working primarily at Circuit Breaker Sales in Gainesville, TX in the Dallas area. As Vice President, Paul’s primary responsibilities at CBS and the Group include business development, engineering design and management, technical expertise, standards, and project management. He has worked with industrial electrical equipment for over 20 years, beginning in the Navy as a Nuclear qualified Electrician on the submarine USS Topeka SSN 754 from 1996 through 2002, followed by positions in the steel industry through 2005. Paul has a BSEE from the University of Texas at Dallas (2007) and an MBA from the University of North Texas (2014). He participates in the IEEE/ANSI PES C37 Standards Committee, which publishes and maintains the design and testing standards that govern the industrial power equipment industry.

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VACUUM INTERRUPTERS: PRESSURE VERSUS AGE PowerTest 2016 Finley Ledbetter, Group CBS Vacuum technology is the most widely applied power interruption technique in the medium-voltage range (2.4kV-38kV). This technology now dominates the interrupter market throughout the world with millions of vacuum circuit breakers installed and close to 10 million vacuum interrupters (VIs). With the original introduction of vacuum breakers in the 1960s, manufacturers designed and tested vacuum interrupters to last 20 to 30 years. About 40 to 50 years later, hundreds of thousands of these breakers are still in their original installation — and operating under the same expectations as the 1960s. With few mechanical devices on the market today with such an extended working lifespan — and considering the inevitability of age rearing its ugly head — it’s time to wonder when and how age will affect the equipment we rely on. How long can we expect these interrupters to maintain the vacuum levels they require to effectively function?

sufficient to successfully interrupt a fault, but gives no indication of how close the VI is to having a vacuum level that would cause it to lose capability for clearing a fault. Until recently, no technology allowed field testing vacuum levels in VIs. Using a field portable magnetron, test technicians can now test vacuum level and evaluate the VI condition based on that parameter. The vacuum level test is called the magnetron atmospheric condition (MAC) test (see photo of test in progress). Note that this configuration does not require removal of the pole assembly or vacuum interrupter from the breaker.

Our team set out to study the effect of the vacuum interrupter age on its vacuum level by testing 815 VIs installed in over 320 vacuum circuit breakers. Our main objective was to determine the correlation between the following: 1) VI age and VI pressure 2) VI age and VI hipot leakage current 3) VI age and VI contact resistance

4) VI pressure and VI hipot leakage current

VACUUM INTERRUPTER PRESSURE LEVEL All VIs increase in internal pressure over time. The pressure increase may be due to small, long-path leaks from outside to inside, diffusion through the container materials, and/or virtual leaks from materials within the internal volume. To help control the pressure increase from these leaks, a getter material is normally mounted inside the vacuum interrupter, which provides a continuous pumping for low levels of H2, N2, O2, and other various residual gases. When internal pressure rises above 10-2 Pa, the VI dielectric strength will start to fall. The risk of interruption failure increases greatly for pressures higher than 10-1 Pa. As part of a vacuum breaker maintenance routine, manufacturers recommend a vacuum integrity test. This test consists of applying an ac power frequency-rated voltage across the terminals of a VI at its rated gap. If the VI is able to withstand the voltage for the manufacturer-specified length of time, the VI is deemed to have an adequate vacuum. Passing this test indicates that the VI vacuum is

Vacuum Test (MAC Test)

TEST POPULATION To minimize variation due to different manufacturing methods, the 322 circuit breakers tested were all the same model and manufacturer; however, the breakers included a range of ratings and VI types. All of the breakers were in service at some point in their history, but none of the breakers or interrupters had been modified from the manufacturer’s original specifications — with the exception that some of the breakers had one or two VIs missing. The total number of VIs tested was 815. Because the serial numbers were sequential, it was assumed that the VI manufacturing dates were the same as the breakers in which they were installed.

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Circuit Breakers Vol 2 Grouping

The test procedure is as follows: 1) Document the condition of the breaker components and nameplate information photographically. 2) Thoroughly clean all dust and contaminants from the breaker. 3) Check primary contact erosion. 4) Perform contact resistance tests. 5) Perform VI pressure (MAC) test. 6) Perform ac high-potential test and measure and record leakage current at the recommended test voltage.

COLLECTED DATA Standard nameplate data was collected for all circuit breakers. Inspection data collected includes the breaker mechanical operations before and after testing, ambient temperature, humidity, and the technician ID. Test data collected for each of the three phases includes the MAC ion current, contact gap, contact resistance, and the ac high-potential test (called hipot, a pass/not pass and the leakage current). The measured MAC ion current was converted to VI pressure in Pascals using calibration curves based on VI diameter provided by the MAC manufacturer. Approximately 10 percent of the tested population (84 out of 815) exceeded the maximum pressure measurable with the MAC tester (~5 x 10E-1 Pa – high pressure). These units were not included in the correlation analyses because the analysis method requires continuously variable data. As shown in Table 1, the percentage of VIs with high pressure increases with age. Age (Years)

1 – 10 11 – 20 21 – 30 > 30

High Pressure

4% 3% 7% 20%

Measurable Pressure

96% 97% 93% 80%

The population was broken down into subgroups designated by VI type, the voltage rating for each piece of equipment (MVA), mechanism type, and pinch tube existence. Correlation coefficients were calculated for each of the data sets with the curve fits for relationships most commonly found in nature such as linear, logarithmic, exponential, square, and square-root distributions. None of the subgroups had calculated correlation coefficients larger than the entire population. For this reason, the subgroups were dropped and data presented as a whole.

Results Table 2 shows the best-fitting distributions, r (correlation coefficients), and r2 values. Note that the VI hipot leakage current shows minimal to no correlation between either the VI pressure or the VI age. Distribution

x Variable

y Variable

r

r_adj

r^2

Exponential

VI Age

VI Pressure

0.4105

0.4107

16.87%

Exponential

VI Age

VI AC Hipot Leakage Current

0.1194

0.1195

1.43%

Exponential

VI Age

VI Contact Resistance

0.3171

0.3173

10.07%

Linear

MAC Pres

VI AC Hipot Leakage Current

-0.0362

-0.0362

0.13%

Table 2: Correlation Results

DATA DISTRIBUTIONS Figures 1 and 2 are scatter plots of the VI pressure versus VI age and VI contact resistance versus VI age, respectively. The best-fit exponential curve is shown on each graph. The strongest relationship was the age of the VI versus the VI pressure values, with an unbiased exponential correlation coefficient (radj)of 0.4107. Figure 4 shows the distribution of VI pressure ranges within four age groupings.

Table 1: VI Percentage of High Pressure by Age

DATA ANALYSIS METHOD Using standard statistical techniques, the correlation coefficient (r) and the square of the correlation coefficient were calculated for the four data relations given in Table 1. Because of the population size, a standard adjustment was made on the correlation coefficient resulting in radj. Table 2 shows the best-fitting distributions, r (correlation coefficients), and r2 values. Note that the VI hi-pot leakage current shows minimal to no correlation between either the VI pressure or the VI age.

Fig. 1: Exponential Distribution of Internal Pressure vs. VI Age, Where radj = 0.4107 and r2 = 16.87%

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Circuit Breakers Vol 2 a range of manufacture dates from 1978 to 2012. The tests performed included contact resistance, ac high-potential test, and MAC tests. After the data was compiled, correlation calculations were made for the following: ● VI pressure (Pa) versus VI age ● AC leakage (mA) (hipot) versus VI age ● Contact resistance (μΩ) versus VI age ● AC leakage (mA) (hipot) versus VI pressure (Pa)

Fig. 2: Exponential Distribution of Contact Resistance vs. VI Age, Where radj = 0.3173 and r2 = 10.07%

Fig. 3: VI Pressures by Age Group

Explanation of Data A distribution of the VI’s measured internal pressure ranges divided into four age groups is shown in Figure 3. Columns A, B, and C correspond to internal pressures measured by the MAC test set, while Column D (Near Failure/Failed) shows VIs that exceeded the maximum measureable pressure of the MAC test set. The distribution shows that most VIs manufactured within 20 years of the present study had internal pressures in the lowest measured pressure range (Column A). The 21-30 year age range shows a dramatic increase in VIs, with measured internal pressures in the 1E-3 Pa to 1E-2 Pa range (Column B). This could be explained by a large migration of VIs in the lowest range (Column A) to the next higher pressure range (Column B) due to increases in internal pressure. The trend continues in the oldest age range with the percentage of VIs in the two lowest pressure ranges dropping and an increase of nearly 500 percent in the 1E-2 Pa to 1E-1 Pa pressure range (Column C) from the period before. Also in this period is a noticeable increase in VIs that exceeded the maximum measureable pressure of the MAC test set (Near Failure/Failed). Overall, the data is in good agreement with the manufacturer’s stated design life of 20 to 30 years.

Test Summary Tests were performed on 815 service-aged vacuum interrupters of similar design and type, from the same manufacturer, with

Findings Our research showed a relatively close, exponential correlation between VI age and internal pressure. We believe this correlation will be strengthened by an increase in the size of the database and inclusion of time-related data for individual breakers. We found a small to moderate correlation between the contact resistance and VI age, and a minimal correlation between VI ac hipot leakage current and VI age or VI pressure. Given the proven relationship between dielectric strength (interrupting ability) and vacuum level, we are confident that the MAC test, which tests VI internal pressure, provides excellent predictive data for determining VI continuing serviceability. Contact resistance testing may provide some value as a predictive tool; however, two significant issues must be accounted for: (1) Frequent contact erosion adjustments — for example, the interrupter contact pressure can change with wear/interruption history — and (2) the significant differences in contact area (a 400 ampere VI versus a 3,000 ampere VI). Since very little correlation exists between ac hipot leakage current and VI age or vacuum level, the hipot test is of no value in any predictive maintenance program for the VI. The ac hipot test should be used only for evaluating the current functioning performance of the VI as well as the other insulation systems in the breaker.

CONCLUSION To fully understand the scale and scope of the situation, additional studies should be completed. However, based on the data gathered from our study, over the next 20 years, we can expect the failure rate of vacuum interrupters to increase as they continue to age. We need to consider this reality and do what is possible to prevent these failures. The author’s recommendation is to replace the necessary vacuum interrupters or prioritize those for replacement. It is not necessary — or even possible — to replace all vacuum interrupters over 30 years of age, as some are still serviceable and this endeavor would be costly. Previous testing methods are not sufficient to reasonably calculate when to replace a vacuum interrupter, except if the VI is already in need of replacement. However, with the arrival of the MAC test set to the market, we can predict when vacuum interrupters will fail, prioritize replacement, and avoid costly failure.

Circuit Breakers Vol 2 REFERENCES Cadick, John. “Vacuum Interrupters: Pressure vs. Age,” Technical Papers, September 9-11, 2015. Renz, R., Gentsch, D., Slade, P. et al. “Vacuum Interrupters – Sealed for Life,” 19th International Conference on Electricity Distribution (CIRED), May 21-24, 2007, Paper 0156 Slade, Paul G. The Vacuum Interrupter: Theory, Design, and Application. Boca Raton: CRC Press, 2008 Arthur, M.E.; Zunick, M.J. “Useful Life of Vacuum Interrupters,” IEEE Transactions on Power Apparatus and Systems, Vol. PAS-97, No.1, January 1978 Okawa, M.; Tsutsumi, T.; Aiyoshi, T. “Reliability and Field Experience of Vacuum Interrupters,” IEEE Transactions on Power Delivery, Vol. 2, No. 3, July 1987 Moore, David S., McCabe, George P. Introduction to the Practice of Statistics, Fourth Edition, W.H. Freeman and Company, New York, 2003 Finley Ledbetter has worked in power engineering for 20 years, including serving as an applications engineer and instructor for the Multi-Amp Institute. He was the founder of Shermco Engineering Services Division, a division of Shermco Industries — a NETA Accredited Company. Finley is also the founder of Group CBS, Inc., which owns 12 circuit breaker service shops in the United States and Puerto Rico. He is a member of IEEE, a NETA Corporate Alliance Partner, and a charter member and past president of Professional Electrical Apparatus Recycler’s League (PEARL).

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REMANUFACTURED LOW-VOLTAGE BREAKERS NETA World, Winter 2013 Issue Lynn Hamrick

This article will concentrate on low-voltage power breakers, which I will define as breakers that are nominally rated at 600 Vac but typically used at 480 Vac and have a frame rating of 800 A or above. They are typically rack-in and rack-out style breakers but can be provided in a bolt-in style, as well. They also include a trip unit that is adjustable and can be provided with long-time, short-time, instantaneous, and/or ground fault (i.e., L, S, I, and G) tripping capabilities. Low-voltage power breakers have evolved over the last 30 years. Much of this evolution is due to the consolidation of providers throughout the industry. In the last 30 to 40 years, the list of original equipment manufacturers (OEMs) has gone from many (ABB, Allis-Chalmers, BBC, Cutler-Hammer, Federal Pacific, GE, ITE, Siemens, Square D, and Westinghouse) to a few (ABB, Eaton, GE, Siemens, and Square D). During this evolution, the space, cost, quality, technology, and sales considerations have resulted in a variation of new breaker designs and options from these remaining OEMs. It has also resulted in a large installed base of equipment that is now obsolete and, in most cases, no longer supported by the remaining OEMs. Most electrical equipment, like low voltage breakers, is designed for a 25-year life. Because of these realities, end users are faced with the daunting task of replacing this obsolete equipment which can be a very expensive and disruptive proposition. To be more specific, examples of the equipment we are talking about are provided below:

GE AK/AKR

GE WavePro

GE PowerBreak Westinghouse SBD

Circuit Breakers Vol 2

59 This circumstance of equipment obsolescence combined with fewer OEMs has created a niche of third party remanufacturers, which specialize in upgrading existing, obsolete breakers to extend the life cycle of the equipment while maintaining the reliability and operability of the equipment. From a financial perspective, OEMs typically profit more from new sales of currently manufactured equipment. So, even though they often offer remanufacturing services, they focus on selling replacement equipment in lieu of remanufacturing equipment. This has resulted in a growing list of third party remanufacturers.

ITE/BBC/ABB K-Line

Unfortunately for the end user, not all remanufactured equipment is equal. To discuss this further, we will consider the following definitions: ● Retrofitting - adding of new technology or features to older systems ● Refurbishing/Reconditioning - servicing and/or renovating older or damaged equipment to bring it to a workable or better looking condition. This includes readjusting, and recalibrating equipment to bring it to a near-new or nearoriginal operational level.

Square D DS

Square D DSII

Square D Masterpact

● Remanufacturing - rebuilding, repairing, and restoring equipment to meet or exceed original equipment manufacturer (OEM) performance specifications. It requires the repair or replacement of worn out or obsolete components and modules. Parts subject to degradation affecting the performance or the expected life of the equipment are also replaced. Many third party suppliers vary in their efforts to providing replacement equipment. There is a significant difference between a retrofitted breaker and a remanufactured breaker, even though they may look the same. A retrofitted breaker may have a new trip unit and may be cleaned up to look new. The remanufactured breaker will have a new trip unit and be cleaned up; however, it will also have new arc chutes, new finger clusters, replated current carrying surfaces, and new bearings on selected pivot points within the breaker. If the end user does not specify the extent of the remanufacturing process, he may think he is getting a remanufactured breaker, while he is really getting a retrofitted breaker. This could result in the end user not meeting expectations with respect to extending the life of his electrical equipment and resolving his equipment obsolescence issue.

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To combat this possibility, many industrial groups are developing technical standards to assist in remanufacturing equipment. For the electrical equipment, groups like PEARL and EASA are leading the way to ensure that the end users are getting what they want. These groups require certified remanufacturers to have adequate training, test equipment, documentation, and follow established best practices.

AC-PRO

They also require that all retrofitted, refurbished/reconditioned, and remanufactured equipment be tested for functionality and defects. From PEARL’s website: “Electrical apparatus bearing a blue PEARL seal with a unique identification number means that apparatus has been fully [remanufactured] by a qualified PEARL member company following PEARL Reconditioning Standards. This guarantees that the device performs to specifications set by the OEM during original manufacture. PEARL companies may sell new, surplus, or used electrical equipment, any of which may or may not have been remanufactured based on the customer’s request. This is why customers should look for product bearing PEARL seals so they know the device will operate exactly as designed, regardless of whether the device was ever previously placed into service.” Typically, this equipment is sold and serviced by third parties, but actually carries a warranty similar to or exceeding the warranty originally provided by the OEM.

For obsolete low-voltage breakers, it is always recommended that the trip units be replaced. Technological advances have resulted in improved operability and reliability in the trip units from both third party suppliers and the OEMs. Most units have digital readouts. They include protection capabilities for LSIG and have additional protective capabilities for phase unbalance and instantaneous selectivity, which can be used in support of arc flash mitigation during the performance of maintenance. Most trip units now also have optional communication capabilities that are very useful to the end user when integrated into existing power monitoring systems. For the environmentally conscious end users, remanufacturing in lieu of replacing with new equipment is also environmentally friendly: “If a durable product can be made to have a longer useful life, several benefits accrue to society. The value of the labor, materials, energy, and capital equipment that goes into making the product is not prematurely discarded. The drain on human, natural, and technological resources is thereby reduced. The costs of solid waste disposal are reduced. Living standards can be higher for the same amount of resource use … Remanufacturers typically recoup 85% to 95% of the energy and materials in the products they rebuild. If a product with a normal lifetime of eight years can be given an additional eight-year life, the demand on energy and material resources to maintain the population of that product can be cut by 40% to 45%. The doubling of the lifetime of any durable product is likely to accomplish savings of this magnitude. [1]”

SUMMARY Much of the installed base of low-voltage power breakers is now obsolete and, in most cases, no longer supported by the remaining OEMs. Most electrical equipment, like low-voltage breakers, is designed for a 25-year life. Because of these realities, end users are faced with the daunting task of replacing this obsolete equipment, which can be a very expensive and disruptive proposition. Satin American

Fortunately, there is a niche of third party remanufacturers, which specialize in upgrading existing, obsolete breakers to extend the life cycle of the equipment while maintaining the reliability and operability of the equipment. Unfortunately for the end user,

Circuit Breakers Vol 2 not all remanufactured equipment is equal, so the end user should specify remanufacturing expectations to the supplier. Additionally, it is recommended that the remanufacturing process includes the replacement of the trip unit at a minimum. Further, all retrofitted, refurbished/reconditioned, and remanufactured equipment should be tested for functionality and defects prior to implementation. [1] “The Remanufacturing Industry: Anatomy of a Giant, A View of Remanufacturing in America Based on a Comprehensive Survey Across the Industry,” William Hauser, Robert T. Lund, Department of Manufacturing Engineering, Boston University, June 2003.

Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee

61

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

6

ALABAMA 1

2

3

4

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

ARKANSAS 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

ARIZONA

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

CALIFORNIA 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

22

23

29

Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

26

27

28

Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

36

37

30

Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power e tin , Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

COLORADO 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

CONNECTICUT 45

46

47

48

49

Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

ILLINOIS 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

GEORGIA 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

58

FLORIDA 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

INDIANA 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

KENTUCKY

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

IOWA 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 MAINE www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 LOUISIANA www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

MARYLAND 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

MICHIGAN 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

MASSACHUSETTS 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

MINNESOTA CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

MISSOURI 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

NEBRASKA 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

NEW JERSEY 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

NEW HAMPSHIRE

NEVADA 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

NEW MEXICO 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

NEW YORK 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

151

152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

OHIO 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

NORTH CAROLINA

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

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High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

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Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

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Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

SOUTH CAROLINA 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

PENNSYLVANIA

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

OREGON

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

164

OKLAHOMA

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

TENNESEE 181

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Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] TEXAS www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

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Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

UTAH 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

WISCONSIN

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

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Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

VIRGINIA

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

WASHINGTON 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

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Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

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Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

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Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

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Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

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ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: •

The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries.

•

NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

•

A Registered Professional Engineer will review all engineering reports

•

All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST).

•

The firm is a well-established, full-service electrical testing business.

Setting the Standard

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SERIES III

ANDBOOK

Published By

GROUNDING SYSTEMS GROUNDING SYSTEMS HANDBOOK

SERIES III

GROUNDING SYSTEMS HANDBOOK

Published by

InterNational Electrical Testing Association

GROUNDING SYSTEMS HANDBOOK TABLE OF CONTENTS Making a Choice in Instrument Technology........................................................... 5 Jeff Jowett

Ground Testing on Wind Farms........................................................................... 8 Jeff Jowett

Addressing Problems in Wind Farm Testing......................................................... 11 Jeff Jowett

Special Considerations for Lightning Grounding.................................................. 14 Jeff Jowett

Substation Grounding and Personnel Safety........................................................ 17 Jeff Jowett

Substation Grounding and Personnel Safety, Part 2.............................................. 21 Jeff Jowett

Measurements at Large Grounding Systems ....................................................... 24 Moritz Pikisch A Look at the Basics of Lightning Protection......................................................... 28 Jeff Jowett

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Grounding in the Solar Industry......................................................................... 31

Jeff Jowett

Hazmat Grounding.......................................................................................... 34 Jeff Jowett

Electrical Safety Management System Principles ................................................. 37 Mike Doherty

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Grounding Systems

MAKING A CHOICE IN INSTRUMENT TECHNOLOGY NETA World, Spring 2013 Issue Jeff Jowett, Megger A difficult and annoying task that routinely confronts the electrician, contractor, electrical maintenance department, testing service or purchasing agent is in the selection of an instrument for a defined application from a seemingly bewildering host of offerings. But at least where ground testing instrumentation is concerned, the choices are fairly simple and understandable, once a few basic parameters are established. Some dedicated individuals may enjoy the challenge of effectively sifting through a hundred options, but for those who appreciate simplicity and time saved, the thanks can be given to the IEEE (The Institute of Electrical and Electronics Engineers, Inc.).

surements, as will be explained. Three- and four-terminal testers afford a thoroughly rigorous test and one that will stand scrutiny. Properly operated, they can meet the challenge of virtually all situations. If something is wrong, the experienced operator will see it in the results and can take appropriate corrective action. The critical determination between the number of terminals will be discussed under the heading of tests.

That is because ground testing, due to the considerable variability and uncertainty of earthing conditions, must be well defined in order to provide effective and comparable measurements. Accordingly, the IEEE has published Standard 81, Guide for Measuring Earth Resistivity, Ground Impedance and Earth Surface Potentials of a Grounding System. The document describes, among many other things, the proper instrument design and testing procedures for performing a ground measurement. Manufacturers of instrumentation then must fit within these guidelines in order to have a viable product, and this in turn lays the groundwork in fairly cohesive terms. In outline form, there are to be considered types of instrumentation (basically, three), tests to be accommodated (again, basically three), and broad application (two). These in turn have some subheadings, and will be discussed in order.

Fig. 1: Testing with a conventional ground tester

Instrumentation breaks down into traditional fall of potentialstyle-testers that operate with terminals and clamp-on testers. The former in turn may be of three or four terminals. These testers operate with long leads and probes, by which a test current is circulated through the soil between a remote current probe at a considerable distance (the term remote earth is frequently seen in the literature) and the test ground. Meanwhile, a second probe measures the voltage drop of the soil resistance to the point of placement, and then these two parameters calculate resistance to that same point. By moving the test probes, the entire area can be profiled, in order to recognize anomalies and interfering factors (Fig. 1). This technology is somewhat labor intensive, but provides a means of obtaining a measurement that is thoroughly reliable and has the backing of the IEEE standard. By manipulating the test probes, the operator is in complete control of the setup and of what is actually measured. This is in contrast to clamp-on mea-

Clamp-on tests are easy to make. That is virtually the whole story. The operator clamps the jaws of the tester around an appropriate point in the grounding system and voilà! A measurement is displayed. It couldn’t be easier (Fig. 2). But there are conditions, which can be compared to the properties of terminal testers as described above. The operator is not in control; the tester is. It induces the test current onto the grounding system and measures the voltage drop around the loop. It then calculates the series loop resistance. The test current goes where it is best accommodated, not through a defined circuit that the operator has established by placement of a current probe, as described above. This is one of the critical limitations of the technology. The test circuit may or may not include the earth! By definition, a ground test must include the soil. But if the current can find a short circuit, that is what will be measured. Large grounding electrodes, such as grids or rings, are typically

6

Grounding Systems

connected to the electrical system at multiple points. Test current can circulate through metal, to the next connection, back up to the ground bus and back to the tester, without entering the soil. It will give a nice, low reading, but is not a ground resistance test. In order to avoid this, the operator needs to have a working knowledge of the grounding system, not always easy or even possible.

Fig 3: Clamp-on cannot be used where there are opens and shorts.

Clamp-on measurements are reliable, but within their own set of parameters which the operator must understand. Simply going in blind and clamping on whatever is convenient may lead to incorrect results. Scrutiny by a third party can be difficult because there is no way to actually prove the result; what the tester says must be accepted. If the operator understands the system and where the test current goes, the result is reliable. Otherwise, it is just accepted. This contrasts with traditional testing, where the manipulation of probes enables a rigorous test that can be proven, as by graphing of results, for instance. Finally, the clamp-on method does not (as yet) have the endorsement of the IEEE standard. A revision should be available later this year that addresses this technology, which did not exist at the time of the present revision.

Fig. 2: Typical clamp-on application. By extension, it is obvious that the technology does not accommodate all situations. There must also be an existing return circuit. With a terminal tester, the leads and probes define the entire test setup. With a clamp-on, a complete return circuit must already be in place. This is typically provided by having the system connected to the utility. The grounded neutral provides a convenient path for the induced test current. Obviously, then, a commissioning test on an isolated ground that has just been installed cannot be performed by a clamp-on meter. Similarly, applications where no return path exists, such as safety grounding of overturned tank trucks, cannot be accommodated by a clamp-on (Fig. 3).

Next to be considered are the tests being performed. There are three. Obviously, the raison d’etre of any ground tester is the performance of a resistance test on a grounding electrode. But the corollary to grounding is bonding. That is to say, the elements of the electrical system must be continuously bonded at low impedance to the grounding electrode. What good is a low-resistance electrode in the soil if fault currents are impeded by high-resistance connections in the grounding conductors? Fortunately, this is a fairly easy test to perform with either a three- or four-terminal tester. The terminals are shunted into a two-terminal configuration and leads run to opposite ends of the grounding conductor being tested. This could be from a motor head to the ground bus, for instance. The long leads that are standard and the alternating square wave of the test current, that is also standard, readily accommodate this test. Modern testers also have two-pole selector positions so that terminals no longer have to be physically shunted with jumpers. Clamp-ons are even simpler in that they perform a basic bonding test simultaneously with the ground test, by virtue of the necessity for a return current path. The experienced opera-

Grounding Systems tor can spot this readily. An unusually high reading…one that is unlikely to have been produced by the electrode under test… indicates a weak or corroded bond, joint or weld somewhere in the return path, and that can be investigated accordingly. Various bonding conductors can be investigated by clamping different parts of the electrical system, but remote terminations that do not have a return circuit in place cannot be tested. They will simply show as an open. The third test that may be performed by a ground tester is soil resistivity. This is the measurement of the electrical properties of the soil itself, independent of any installed grounding structure. The data is used, among other things, to design and install electrodes that will meet specifications. Here, a four-terminal model is a necessity. Various test configurations exist and are described in the literature, but they typically call for two current probes to establish an even test current over a designated area, and two potential probes to measure the voltage drop within the designated zone; hence, four terminals. The two broad areas of application are electrical and geophysical. This article has focused on the electrical: grounding electrodes, the bonding of the system to them, and the conductance of the surrounding soil. Geophysical testing is considerably different, involving applications such as the inhibition of corrosion along pipelines and deep vertical prospecting for changes in resistivity that may indicate deposits of ore and the like. Testers for this application are comparatively heavy-duty, often requiring higher voltages and currents in order to permeate large spheres of influence. Testers for the electrical arena, by contrast, can be limited to safe levels of voltage and current for operator safety because they have sufficient sensitivity to get the job done. Such testers may also be used in geophysical applications, but the operator needs to know their limitations. In approaching the selection of a tester, then, first determine whether for geophysical or electrical and then proceed to the appropriate market. If electrical, the next determination is whether it is to be used exclusively on existing plant. If so, a less expensive three-terminal model will do fine. But consider the future. If situations may arise where prospecting new ground or designing a new system may occur, then a fourterminal is a must. Clamp-on testers are excellent time savers, but do not meet all situations. Be sure to avoid opens (not connected to the power system), shorts (multiple connections from the system to the grounding electrode), and requirements for proof of test and standards conformance. If these conditions are met, then the ease-of-operation of a clamp-on may make it the preferable choice. One additional consideration is worth noting. Grounding grids themselves may sometimes require testing; that is to say, the actual physical integrity of the grid itself below grade, and not just its resistance to remote earth. This function can be performed in part by models already mentioned, but not rigorously

7 or thoroughly. A terminal tester may be connected in a twoterminal configuration between various points of access and give some indication of the integrity of the connection below. A clamp-on can be applied judiciously to various points around a system and give an idea of the continuity between those points. This may be enough as a spot check. But for rigorous proofing of below-grade integrity, there exist dedicated high-current testers that can be connected at all accessible points and test the ability to pass current around the grid. Look for a grid tester, not a ground tester, for such requirements. Once these fundamental considerations have been met, the refined selection can be made on the remaining distinctions between models, such as noise suppression, range of measurement, safety conformance, field readiness, result storage, and the like. These are largely a matter of operator preference or organizational requirements, and are easily addressed.

Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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Grounding Systems

GROUND TESTING ON WIND FARMS NETA World, Summer 2013 Issue Jeff Jowett, Megger

Like most electrical facilities, wind farms benefit notably from good grounding. And like all grounding, it should be regularly maintained. An established program of testing is integral to the maintenance process. Fortunately, equipment and technique do not depart radically from general ground testing, with only some reasonable accommodations to the application. “Out of sight, out of mind” is an adage that well pertains to grounding sites, and possibly even more so with wind farms. With the blades turning overhead and the generators humming in the nacelles, who is likely to think about what is buried underfoot? In addition, wind energy is largely a young industry with relatively new equipment and a focus on the future. Aged and deteriorating equipment is not likely to be the first order of the day, but studies of installed electrodes by a grounding materials company found corrosion in extreme cases in as little as two years, with four years more the norm.1 Even a young industry would be well served to pay attention. Grounding systems corrode away below grade. Northern climes that experience freezing and thawing add an extra hazard. The physical pressures associated with these sometimes dramatic shifts in the electrode’s environment can literally break apart joints and welds, disrupting grid integrity, and a particular hazard on wind farms is, of course, inadequate lightning protection. Just because a known stroke has been cleared without damage to the electrical plant does not mean that the electrode is still in prime condition. Yes, it was when the stroke occurred, but the demanding job of fault clearance can break apart a grid below grade…out of sight…out of mind.

of an indeterminate volume of soil around the buried electrode. Accordingly, a ground tester affords separate current and voltage measurement circuits by which the soil can be accurately profiled across the critical resistance zone around the electrode. By a long lead and probe, a test current is established through the soil. By the same means, the voltage is measured at a series of designated points and the resistance is graphed. This method is distinct from any other type of electrical testing, and is known as fall-of-potential. The equipment is specialized and the procedure detailed and precise. It is generic and applies to all grounding electrodes, but there are some special considerations that apply to wind farm testing, as will be seen. Another popular type of test equipment specialized to ground testing is the clamp-on ground tester. These are simpler to operate and require less procedure, but have serious limitations in wind farm application that must be understood and observed.

Ground testing should be an integral part of the electrical maintenance program in order to be assured that no such damage or deterioration has occurred. Additionally, a well-maintained ground has numerous other benefits. Another significant issue on wind farms is mitigation of noise and harmonics. Ground resistance is a critical factor here. Add to that fault clearance by protective devices in required time, protection from ground-potential rise and the associated shock hazard from step and touch potentials and inductive voltages, and ESD (electrostatic discharge) protection.

While it has been observed that fall-of-potential applies to ground resistance testing in general, the principle concern on a wind farm is the enormity of the ground grid. With each individual tower ground paralleled together, the total system is at the same potential and can cover acres! In order to be accurate, the measurement must be taken beyond the physical limit of the ground field’s electrical footprint in the surrounding soil. (In the literature, this is referred to as “remote earth,” i.e., a reasonable approximation to the resistance exerted by the whole planet.) At the same time, the measurement must not include additional resistance from the electrical field surrounding the current probe. If a single ground rod were being measured, this is fairly easy to accomplish. But the electrical field of a wind farm ground can extend for prohibitive distances! Lead lengths to test probes are typically on the order of four to five times the maximum grid dimension. It can be easily seen how this requirement can present a problem. Phone lines have been rented and used as test leads! Yes, as radical as it sounds, this practice is actually done. It can be accomplished because ground testers have very little power and operate with a square wave test signal that can travel harmlessly on a phone line.

How, then, is the grounding system tested and what equipment is required? It is important to keep in mind that dedicated equipment and procedures are necessary; trying to adapt multimeters and other generic pieces of test equipment is not the order of the day. Remember that a ground test does not involve a discrete object, like a motor or circuit. What is actually being tested is the resistance

Fortunately, there are more agreeable alternatives. Procedure is as important as equipment in ground testing, and many different methods have been devised in order to meet any demanding situation. For grids that would require impractically or even impossibly long test leads in order to be measured by fall-of-potential, there are the slope and intersecting curves methods. The former employs

9

Grounding Systems a mathematical proof to separate extraneous current probe resistance from the resistance of the test grid in cases where the two overlap and a fall-of-potential graph cannot be properly interpreted (Fig. 1). This means that the current probe doesn’t have to be as far away (typically two to three times maximum grid dimension) and the test may be completed within workable distances. Should the electrical field of the test ground be so large as to extend beyond the current probe, the mathematics become incoherent and the operator knows to find more room or switch to another method. In that case, the intersecting curves method may be substituted. This can work conveniently within distances as little as half again the maximum grid dimension, and employs superimposed graphing based on assumptions in order to find the grid resistance. Only at the true measurement distance do the graphs converge. Both methods have been described fully in prior editions of NETA World.

like extra work at the time, but it will greatly speed subsequent maintenance testing, especially if performed by a different crew with less familiarity with the site. They will be able to operate quickly, be less prone to human error, and the readings will be readily comparable and simple to evaluate. A testing problem peculiar to wind farms stems from static buildup on the blades. As they rotate through the air, the blades develop considerable static charge. This will eventually discharge spontaneously and do so through whatever is most convenient. That could be some part of the electrical system with resultant damage. Add to that the vulnerability to lightning hits. The solution is a conductor through the blade, from tip to hub, and then continuous low impedance down the tower to the grid below. This conductor can take considerable wear (especially from lightning!) and should be routinely tested for continuity (Fig. 2). Ground testers can be employed in two-terminal configuration, but industry standard calls for a 10 ampere test current. This requires a low-resistance ohmmeter of appropriate current rating. The test itself is easy enough to perform. Low-resistance ohmmeters are Kelvin bridges, with two current and two potential terminals. Just connect across opposite ends of the conductor under test and press the test button (Fig. 3). The measurement (industry standard <25 mΩ) appears.2

Fig. 1: The Size of Wind Farms Present a Challenge to Fall-of-Potential Testing Ground testing is also performed at time of installation, but in this instance, the parameters are notably different. Installation is the only practical time at which the elements of the grounding system can be tested individually; that is to say, without the extreme difficulty and cost of excavation. While the final grid will have all elements paralleled and exhibit the same resistance from any point, it is also valuable to check individual elements as they go in. This is for exactly the reason stated in the previous sentence; once the grid is complete, trying to locate problem spots takes a quantum leap in difficulty. It is, therefore, a good idea to go the extra mile and perform sectional testing as the grid goes in. It will reduce the amount of time and money spent later. As the grid is assembled and interconnected, continue to test each larger segment. Keep thorough records. Software programs may be available from equipment manufacturers, and these will prove invaluable to effective recordkeeping. Although this extra step may seem tedious at the time of implementation, it will pay for itself in convenience for later testing and maintenance. Include in stored information the exact locations where current and potential probes were placed to perform the tests. Again, this may seem

Fig. 2: Blade Continuity Can Be Tested From Ground After Installation With Special Leads

Fig. 3: Continuity Testing Before Installation The difficult part here is the distance the leads must traverse, from tip to hub and then to ground. The test(s) can be made tip to hub and

10

Grounding Systems

then hub to ground, or tip to ground all in one. Bucket trucks can be used to connect the leads from the ground, or they can be connected from the nacelle by suspension from ropes (Fig. 4). Either way it is not easy, so it is a good idea to have the best possible lead set so as not to impair the progress of the test or the confidence in the results. Attention must be given to wire gauge and firm metal-to-metal connections. This is one test you don’t want to have to repeat, so getting it right the first time is paramount.

resistance including the structure of the grid. Substantial loss between measurement points indicates diversion by high-resistance flaws in the structure. In addition, ground cables, clamps, and ferrules can be tested prior to installation using the same equipment, and a bad product can be intercepted before it goes into the ground. Operation of the grid tester has also been fully described in a prior edition.

Fig. 4: Continuity Testing From the Air

Fig. 5: Subterranean Grid Structure Tested with a High-Current Tester

Finally to be considered is the evaluation of the grid structure itself. This can be done after installation by the use of a grid tester. The major difference between a grid tester and a ground tester has to do with current. A ground test is performed with only milliamperes of current because that is all that is necessary to make a measurement, and the operator is kept safe. A grid tester, on the other hand, uses a lot of current, typically several hundred amps. The grid structure can be subjected to enormous amperages during a lightning stroke, and so it must be confirmed that the structure is capable of accommodating high currents without damage or deterioration. The grid tester injects the current through a reference ground into the grid being tested (Fig. 5). Welding cable makes good test leads. Whereas ground tests take only a few seconds of operating the tester, a grid test runs for several minutes. A clamp-on ammeter measures current at critical points, and the tester indicates the associated voltage drop. A value of no more than 1.5 volts per 50 feet of straight line ground path should be measured. As a redundant quality check, current returning via the ground path is also measured and should be at least half of output. It is expected that current will concentrate along lines of low

Anyone familiar with basic ground testing can make the straightforward adaptations to wind farm requirements without difficulty. The next edition will examine some further complications and special testing considerations on wind farms.

REFERENCES A. S. Gill, Lyncole XIT Grounding, Electrical Equipment Testing and Maintenance, Prentice Hall.

1

Information courtesy of Vestas Wind Systems, Ringkøbing, Denmark & David Danner, MEGGER®, Chandler, AZ.

2

Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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Grounding Systems

ADDRESSING PROBLEMS IN WIND FARM TESTING NETA World, Fall 2013 Issue Jeff Jowett, Megger The previous article reviewed grounding and ground testing on wind farms from the basics. The considerations don’t depart markedly from general ground testing industry-wide, but there are some special issues endemic to wind power. In a comparatively young industry like wind power, the grounding system may not be receiving primary attention. But factors like corrosion, weather, and lightning may be exerting unwanted effects, and these can become severe. The requisite instrumentation was described in previous articles. So were the specialized test methods that address the biggest issue with wind farm ground testing; that is, the enormous sizes of grids. Effective test regimes were outlined, both during construction and continuing maintenance. The special problems of lightning damage and static buildup on blades, and how to mitigate them were described. Finally, the maintenance of the grid structure itself was reviewed. This sequel will further examine some special problems.

Second only to enormous grid size, the next biggest challenge is to know what is actually being measured. The system may in fact be a lot larger than thought. Initial design considerations focus on the turbine as an entity. But once daisy-chained or interconnected in a star configuration, the associated grounding system takes a quantum leap. Phase cables have grounding sheaths connected to common buses, and communication cables have their own grounded conductors as well. At some stage in construction, it becomes impossible to isolate the grounding of an individual turbine. Design criteria for a single turbine then have to be related to the total system. Furthermore, lightning protection systems use a different set of criteria than power grounding, based on the need to accommodate enormous currents and high frequencies.

Testing for maintenance and testing for conformance should be essentially the same, but may have different goals and can produce conflicting results and interpretations. Utility maintenance teams may be responsible for maintaining a wind farm. At the same time, wind turbine manufacturers may be interested in investigating issues that occur during the warranty period. Many newer facilities are coming to the end of the standard five-year warranty period and manufacturer’s maintenance support will be disappearing from the site. If the baton is to be passed from one maintenance authority to the next, it is desirable to make this as seamless as possible. In addition, there may be safety monitors with their own criteria to be met. Some common issues will be reviewed as follows:

Fig. 2:. Good grounding is the best protection against lightning damage Fig. 1: The scale of wind farm ground grids can make conventional testing prohibitive, requiring extensively long test leads

There may be cross-connection between fault-clearance and lightning protection systems and between different parts of the installation. This connection may be intentional or inadvertent. Fault

12 protection grounding is often shallowly buried, less than a meter below grade, and may be ineffective. The design of the wind farm may have been done piecemeal, even by different consultants, with different design considerations making up various elements of the total grounding. System design is separate from installation and commissioning, which have different economic perspectives and are performed by different subcontractors. Maintenance and performance monitoring are separate from design and installation, and, again, are performed by different subcontractors. System design schematics may not match what was actually installed, as contractors may adjust this to make their jobs easier. Grounding connections are sometimes conveniently made to a nearby conductor and do not necessarily accord with the electrical pattern of the daisy chain of turbines. Shortcuts of this sort are frequently performed to save money. As a result, each individual installation can look different from the last. As reviewed in the previous article on this subject, traditional testing methods can become impractical to implement because of the long length of test leads (typically 6 times the diagonal dimension of the grounding system) required by even smaller facilities. Accordingly, an inordinate amount of time can be wasted at large sites merely in the travel from one installation to another.

Grounding Systems not be effectively run. This example illustrates a common dual problem that should be judiciously avoided: tests being both inadequate and unrepeatable. A frequent compromise practiced by wind engineers is to discount the use of fall-of-potential testing because of the impractically long lead lengths required. Instead they work within agreeable distances and use the results merely for comparative purposes. It is especially important in such situations to record the exact placement of current and potential probes so that the repeat tests will be precise duplicates and comparisons for trending purposes will be reliable. An added complication at wind farms (as if there weren’t enough already from the grid size and multiple parallel paths!) is the possibility of coupling between nearby grounding elements. In most other situations, this is not a threat, because systems are fairly discrete. But with so much metal in the ground at wind farms, grounded cables nearby can provide a convenient low-resistance path that shorts out the propagation of test current evenly throughout the soil. This is why precise records of probe positions are necessary if tests are to be repeated. On subsequent tests, the actual measurements are not considered as significant, only the departure from previous records. A major concern on wind farms is cable theft. Remote location and large amounts of relatively accessible shallow-buried copper make theft an ongoing problem. Typical specifications call for cable to be buried 0.5 to 1 meter depth, but this is often applied only to high-voltage and data link cables. Grounding conductors can be found at depths of less than a foot. Additionally, such shallow burial invites exposure through erosion of the thin layer of soil, which not only implements theft but enhances corrosion. This makes grounding cables the easiest to locate and remove, often by organized operations utilizing a trailer with winding equipment. At least the robber crew may have been considerate enough to leave a clearly visible trench. But if the theft was more surreptitious, it may require some detective work. Otherwise, it will only appear when a fault causes a system failure. Theft mitigation can be integrated into the general maintenance program. Here is where a clamp-on ground tester may be effectively utilized.

Fig. 3: Cross connections in wind farm grids can make it difficult to know exactly what is being tested. Ground testing upon installation is frequently far from rigorous or comprehensive. Not only should traditional three-pole ground tests be performed at different stages of construction, but thorough and accessible written records should be kept. As an example, tests can be performed on inner and outer grounding rings as they are installed and then on the complete turbine. By contrast, one sample site visited, a 140 turbine farm, had performed only a single test, with the current probe at about 1300 feet. This is a long distance for testing a residential or small commercial ground, but not on a wind farm! The direction of the test had not been recorded, so a useful comparison test could

A brief review of instrumentation is in order. Traditional ground testers operate via terminals (three or four), long leads, and probes. On wind farms, these are requisite for measuring ground resistance. Clamp-on testers, which operate similar to current clamps by encircling the ground rod or conductor, are of little or no use on wind farms for measuring ground resistance. But they can be a convenient help for measuring continuity. The reason they are not amenable to measuring ground resistance comes down to the standard electrical problems of shorts and opens. During the construction process, the elements of the grid are not connected to the electrical system and therefore an open exists; the clamp-on tester cannot establish a test current by induction because there is no circuit in place. Once the construction is completed, the multiple interconnections create numer-

Grounding Systems ous shorts; i.e., parallel paths by which inductive test current can complete its circuit entirely by remaining within the metallic structure of the grid. It will not give a ground resistance reading to remote earth, as is required in the definition. But it will give a useful continuity measurement of the grid structure, and that’s where its practical value lies. The clamp-on is a convenient instrument for determining if a circuit is actually intact or if there is an uncommonly high reading that indicates some problem. If the grounding system has been co-opted by theft, clamping at the relevant point will reveal this as an open or high resistance. Potential shortcomings do exist, however. Ac to dc conversion technology is generally in use at a wind farm, and these converters generate earth leakage currents with significant harmonic content that can negatively affect clamp-on readings. On-board current sources in the testers operate at high frequency, typically ~1200 – 1500 Hz. Additionally, leakage current increases dramatically with turbine output. Therefore, such tests are best performed when the wind farm is in a shutdown period or when wind speed and turbine output are low. Bonuses are often based on turbine availability, so these operations must proceed quickly. If these conditions cannot always be realized, be prepared with a tester that exhibits quality noise suppression capabilities. A reliable noise indicator feature on the display is a useful function in warning the operator that the readings may have interference content and perhaps should be taken at a quieter time. Be careful to avoid random placement for taking clamp readings. Make use of reliable schematics of the grounding system and determine where the ideal test points are located. Set up a testing regime that is thorough. One complication that can make this difficult is the presence of parallel paths. These situations may just have to be dealt with as best as is reasonably practical. Most parallel paths result from interconnection of lightning protection and fault clearance grounding. An example of a practical application is to check the interconnection of the HV cable ground sheaths. With the three sheaths of the three phases connected together at the ground bus, the resultant loops can be measured periodically to check for sheath damage or corrosion. Wind farm grounding installation and maintenance provide some unique challenges, related especially to the size and interconnectivity of the grids. Although it may appear a tall order, standardization would be most valuable in the long run. While much more dramatic than the issues discussed here, a recent example from the nuclear industry may afford some insight. Pursuant to the earthquake disaster in Japan, it has been suggested that a universal plan be established by which all nuclear generating stations are built to the same specifications. This would promote maximum speed and efficiency in disaster clearance, as teams could go to work immediately with no time wasted in coping with the individualities of the site. Perhaps the stakes aren’t as high anywhere else as they are in nuclear, but the concept certainly has

13 merit outside that industry. A dedicated maintenance plan should be adopted, layered testing implemented during installation, and design to include not only consideration of lightning and fault protection, but maintenance and ease of testing as well. Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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Grounding Systems

SPECIAL CONSIDERATIONS FOR LIGHTNING GROUNDING NETA World, Winter 2013 Issue Jeff Jowett, Megger It is well known that lightning strokes are a major threat to the function and integrity of electrical systems (Fig. 1), and are not limited just to the hazards of electrocution and the ignition of building fires. To varying degree depending on locale, all electrical plants must be actively protected from lightning strokes. Merely counting on the oft-quoted chance that lightning won’t strike is foolhardy, as the threat is not confined to the area directly hit but is spread for miles over the electrical grid. A nearby hit can produce magnetic induction or capacitive coupling that drive large voltage impulses. Capacitive coupling can also be produced by cloudcharge buildup. Thirdly, ringing phenomena can occur in a tuned cable picking up similar frequencies from the radiated stroke.

Fig. 2: Typical lightning protection design A lightning stroke is comprised of both high- and low-frequency components, with the wave shape of the impulse characterized by a steep rise in both voltage and current followed by a long trailer of excess current (Fig. 3). Typical rise times vary between one to ten microseconds (μs) for the first stroke and 0.1 to 1 μs subsequently. The high-frequency component occurs in the fastrising front while the long, high-energy trailer comprises the low frequency. The steep rise in current makes the inductance of the grounding system an important consideration. The voltage rise ground potential rise (or GPR) is dependent on both the resistance and inductance of the system and is expressed by the formula: …where L is the inductance in microhenrys and di/dt is the current rate to peak in kiloamperes per μs.

Fig. 1: Lightning strokes cause extensive damage to electrical systems Benjamin Franklin invented the lightning rod in 1749, and since that time most lightning protection systems have been made up of the Franklin air terminal, Faraday Cage (vertical and horizontal conductors), or combinations of both (Fig. 2). As would be expected, recent times have seen the introduction of new, less passive technologies, including active and dissipative air terminals. But regardless of the technology employed, all must rely on the grounding electrode to effectively dissipate lightning energy into the earth. A lightning protection system cannot function properly without a good ground. To be fully effective, a grounding system must provide a low impedance and not just a low resistance. To understand why, an examination of the nature of a lightning stroke is in order.

Fig. 3: Wave shape of typical lightning stroke. The threat here is the real possibility of the voltage reaching such a level as to produce flashover, arcing to adjacent metallic conductors. This in turn can have the effect of redirecting the en-

Grounding Systems ergy of the lightning stroke into the electrical system rather than away from it. The injection point can reach hundreds of thousands of volts, and even go into the megavolt range! The inductance combined with the rapid rate of current is the prime factor responsible for such voltage rise and necessitates a low-impedance grounding system. The goal of system design, then, is to minimize potential rise in the surrounding earth while maximizing the rate of fall from the injection point. Equipotential bonding is used throughout the facility in order to eliminate damage from differential ground potentials. Accordingly, the National Electric Code® (NEC®) requires that all systems, such as power, telephone and lightning protection, be bonded together. So it can be seen that simply driving a ground rod may not be sufficient. It is not uncommon for ground rods to be blown out of the earth by lightning strokes. In addition, even complex subterranean grids can be significantly damaged, out of sight and out of mind. Robust construction from the proper materials is the order of the day. Inductance and skin effects are important considerations in the selection of conductors and connectors and in design. Skin effect is the tendency for alternating current at high frequency to flow with maximum density near the surface and to diminish with depth in the conductor. This effectively reduces the cross section of the conductor and increases resistance. One recommended remedy is to install radials of wire or flat strip, proven effective in reducing GPR and directing lightning energy away from the injection point. This construction can be further enhanced by adding short radials from each main radial, typically at a 45° angle from the main radial and pointing away from the injection point. The radials may also be embedded in ground enhancement material such as bentonite. Length of radial is governed by a law of diminishing returns so that the effectiveness is limited to about 50 to 75 feet, after which it drops off. Exothermic welds provide the recommended connections in that they afford the lowest inductance path while maintaining reliability and corrosion resistance. Soil resistivity is an important element in ground design. Resistance to remote earth is directly proportional to soil resistivity. Resistance to remote earth is the term used to describe the resistance relationship between the buried electrode (single rod or complex system) and the surrounding soil. The expression, remote earth, seen commonly in the literature means a distance great enough to have overcome the effect of the immediate environment, where earth has become spacious enough to contribute no additional measurable resistance. Soil resistivity is a measure of the conductivity of the soil, its ability to conduct electric current. It is dependent on the structure of the local soil itself, independent of buried electrodes. Resistivity is most commonly measured by the Wenner method, where four equidistantly spaced test probes from a ground resistance tester are driven into the ground, a measurement taken, and a simple formula applied that converts the reading to a volumetric measurement.1 Then what?

15 Resistance to remote earth is a valuable test and must be part of a grounding system’s installation and maintenance testing. Grounding systems are involved with a lot more than just lightning protection. But resistance measurement doesn’t provide a complete assessment of a grounding system’s true effectiveness under the impulse conditions of a lightning stroke. Ground resistance testers normally operate at a frequency of a hundred or so hertz. This is to simulate performance as defined by the power grid, with exact frequencies chosen just a bit off of harmonic frequencies (120, 240, etc.) so as to provide the tester with a clear signal. This is a good design for assessing the electrode against most of its duties. However, testing at low frequency does not indicate true surge impedance. For openers, establishing a low resistance provides a valuable first step, but not necessarily the end of the process. A useful industry standard is five ohms to remote earth.2 Then, soil resistivity measurements can be used to implement an effective design. The upper layer of soil is most important in lightning dissipation, and if it is poorly conductive, knowledge of soil conductivity aids the designer in applying what is known about conductors and electrodes. For poorly conductive upper layers, larger radial wire or strips will reduce the inductance between ground rods. Spacing between rods is decreased. These adjustments are made to accommodate the reduced capacity of poorly conductive soil to shunt radial inductance. High resistivity promotes a high concentration of charge in the field around the electrode. This in turn can lead to arcing in the soil, a condition that promotes both high-frequency ringing in the supposedly protected electrical system and in nearby systems. Effective separation distances can be calculated using a value of 0.5 kV/cm for the soil breakdown mechanism.3 The high temperature of an arc can fuse minerals in the soil into glass formations called fulgurites. The material of fulgurites is not conductive and can act as an insulator around the grounding electrode, effectively defeating its function. It is unwise to be cavalier about lightning protection. The popular line “…about as much chance as getting hit by lightning” does not apply! Fatalities in the continental US for the period 1990 to 2003 were reported as 759, or about 54 per year (Alaska and Rhode Island had none; Florida had more than double the next nearest with 126!).4 The US Lightning Detection Network reports about 20 million flashes annually.5 Damage is variously estimated at $70 million by the US National Weather Service5 while the National Lightning Safety Institute includes further damage by brushfires, power losses, and the like in their figure of $10 billion.5 Damage results from heat, electromagnetic fields, voltage differentials, and mechanical forces. Average stroke current is 30 kA, and some have been measured over 100 kA. Temperature is typically 50,000°F, or five times that of the sun!6 Much of the ensuing damage can be attributed to insufficient strike protection. A combination of design and testing are recommended in order to assure a fully protective grounding system. The design phase should include resistivity measurements and

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Grounding Systems

the inclusion of appropriately robust and up-sized construction materials in accordance with industry best practices. Strong, effective bonding to create an equipotential plane is essential. The inclusion of transient voltage surge suppression protection provides an additional safeguard against ringing damage. Resistance measurement becomes essential as an installation proof and subsequently as part of the electrical maintenance program to assure that the electrode is maintaining its initial effectiveness. The dual measures of construction and testing will afford maximum grounding protection.

REFERENCES NFPA® (National Fire Protection Ass’n®) 780; UL (Underwriters’ Laboratories) 96 & 96A IEEE Standard 81-2012: IEEE Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Grounding System.

1

Curt Stidham, Harger Lightning & Grounding, Grayslake, IL, Grounding for Lightning Protection.

2

A. Mousa, A., Breakdown Gradient of the Soil Under Lightning Discharge Conditions

3

Figures compiled by National Weather Service and National Oceanic and Atmospheric Administration, reported by National ’Lightning Safety Institute.

4

5

Manfred Kaiser, manfredkaiser.com.

6

M Uman, All About Lightning.

Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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Grounding Systems

SUBSTATION GROUNDING AND PERSONNEL SAFETY NETA World, Spring 2014 Issue Jeff Jowett, Megger

Grounding protection and ground-related performance are vital functions all across the electrical system, from generation to commercial or residential user. A critical element in the system is the substation ground. Although not universal, many electrical systems operate with a grounded neutral. This parallels the end user with the ground grid of the station feeding the site, and so extends the function of the grid from the utility to the customer. What occurs at the substation is of more than just passing interest to the end user! The ground grid serves familiar functions:

Type of Connection

Max Allowable Temp (°C)

Value of K

Conductor only

1083

6.96

Exothermic

1083

6.96

Brazed

450

9.12

Bolted

250

11.54

Table 1: Typical Values of K for Common Connectors

●● It protects equipment by limiting the magnitude of fault currents. ●● It provides a solid connection to earth to dissipate lightning and switching surges. ●● It provides a low-resistance path to aid sufficient current flow in order to operate overcurrent protective devices that clear faults. ●● It facilitates operation of voltage-sensitive, high-impedance control equipment by preventing spurious signals in grid connections. ●● And most important, it protects personnel from injury durin fault conditions by equalizing potentials. Grounding conductors are sized according to the Onderdonk Equation in order to prevent fusing during fault conditions: Fig. 1: Step and Touch Potentials Must Be Limited to Safe Levels Where: A = cable size (circular mils) K = connector factor S = maximum fault time (seconds) I = maximum fault current (amps) Conductor size, then, depends on magnitude and duration of available fault current and on the type of connections utilized in the grounding system. Table 1 shows some typical values of K.

Personnel safety is based on the concepts of step and touch potentials (Fig. 1). These provide the means by which substation safety parameters can be precisely calculated against maximum available fault current rather than left to the presumption that the system is merely grounded. Substations are at the limit of demand on safety requirements for two reasons: ●● There is a high probability that the earth itself will be part of ground-fault current return, in parallel with the familiar metallic return paths within utilization systems. ●● There is a substantial possibility of employees being present in the switchyard at the time of faults. As a consequence, there must exist a system of grounding electrodes paralleled together with interconnecting cables so as to provide sufficiently low ground electrode system impedance.

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Grounding Systems

This impedance must be low enough to maintain the voltage drop within the system at a tolerable level and maintain the voltage drop within zones which personnel might subtend at less than hazardous potential differences. Hazard to the human body is a function of current, not voltage. A harmless carpet shock can be thousands of volts. But the limit of tolerable current magnitude (that will not cause ventricular fibrillation in a 110-pound person) is determined to be:

Where:

t = time of duration of shock in seconds

Ik = rms current through the body in amperes

Fig. 2: As Earth “Shells” Expand in Area, Resistance Increments Decrease

The calculated current relates to passage between both hands, or from hand to foot or hand to both feet. In cases where passage is between both feet, a current ten times as high may be tolerated. However, this is still enough to initiate involuntary leg contractions that could cause a fall and result in contact with the hands to the voltage source. It is instructive to consider the manner in which current distributes itself through the earth. Current flow creates a voltage drop at the earth’s surface. A person standing on the surface will therefore develop a voltage drop between the feet, and this can be of a dangerous magnitude. This is what is referred to as step potential. Remember, current traveling in earth does not have to follow a straight path, as in a circuit, but can radiate in all directions (360°). As it does, voltage drop diminishes across a given distance, but in nonlinear fashion. Recall the basic formula for resistance of a conductor:

Where: R = resistance Ρ = characteristic resistivity of the material l = path length a = cross-sectional area of the conductive path

Fig. 3: Step Potential Voltage/Distance Curve: Note V2 << V1 For a wire, a is the gauge and, therefore ,another constant. But with a current injected into the earth, a changes continuously. For illustrative purposes, imagine the electrode as being surrounded by concentric shells of earth. These shells become progressively larger with distance from the electrode (Fig. 2). Therefore, a increases while the resistance increments in l are becoming progressively smaller. Eventually, a point is reached where the outer shell has such a large surface area that any additional increase adds little to the total resistance. At this point, resistance can be considered constant and voltage drop is negligible (Fig. 3). For the consideration of personnel safety, a person standing or walking near the point where the fault current enters the earth may have a large and injurious potential difference from foot to foot. The potential difference across the same span will be less and less with distance from the entry point. Substation grounding, then, must maintain this potential below injurious levels.

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Grounding Systems

Fig. 4: Fault Can Apply Voltage Across Worker’s Body

Similarly, touch potential represents the possible danger that could arise from a person contacting any part of the substation structure, both inside or outside the fence, with an injurious potential being applied across the body. A common example is that of a worker operating a disconnect switch with the remote possibility of the switch faulting to the structure (Fig. 4). With a fault condition as shown in Fig.5, the worker would be in parallel with the tower and a portion of the fault current shunted through the body. Some typical values can be used to illustrate how the worker could be protected from injury. Good grounding connections could limit the tower-to-ground mat resistance (Rt) to 0.5 mΩ. A similarly reasonable assumption would fix the operator’s contact to ground (Rcg) at 50 Ω, based on a ground resistivity of 35 Ω. The fault current will be assumed to be 50,000 A. Utilizing these assumptions through the circuit described in Fig. 6, the current through the operator’s body (Ib) would be 50,000 X 0.0005/550 = 45 mA. This would be a safe value for 500 milliseconds (30 cycles). The critical component here is Rt. Increasing the resistance of the connection to the ground mat to a mere 5 mA would endanger the operator.

Fig. 5: Disconnect Switch Faulting to Structure

Fig. 7: Touch Potential Hazard Reduced with Metal Platform

Fig. 6: Schematic Equivalent of Figure 5

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Grounding Systems

Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

Fig. 8: Schematic Equivalent of Figure 7 A method to further reduce the potential danger would be to have the operator standing on a small metal platform connected by a low-resistance cable (Rc, 4/0 copper) to the operating handle (Fig. 7). Now, current to ground is divided between the operator’s body and the short cable, which has a typical resistance of 0.2 mΩ. Further reasonable assumptions can be made that each connector has a resistance of 0.15 mΩ, making a total resistance of 0.5 mΩ, plus a 1Ω resistance for the platform to ground (Rsp). Calculation via the circuit described in Fig. 8 shows that: Isp = 50,000 X 0.0005/1.0010 = 25 A While: Ib = 25 X 0.0005/500 = 25 μA This step has reduced the current through the operator’s body from 45 mA to 25 μA, a reduction by a factor of nearly 2000! So it can be seen that Ib, the current through the operator’s body, is dramatically affected by resistances Rt, Rc, and Rsp. The first two increase Ib when they increase, the last decreases Ib when it increases. Worst cases are Rc increasing to infinity due to a broken connection, Rt becoming high due to broken or bad connection to the ground mat, and Rsp approaching zero. The system must be such that it limits current through the operator’s body to a safe value. The platform cable may be sacrificed in the operation, but that will be readily detectable visually. The next column will review some of the details of construction, connections, and testing of a grounding system that will meet the rigorous yet essential requirements described here.

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Grounding Systems

SUBSTATION GROUNDING AND PERSONNEL SAFETY, PART 2 NETA World, Summer 2014 Issue Jeff Jowett, Megger

The previous column dealt with substation grounding and the function of the grid in limiting fault currents, dissipating lightning, and switching surges, enabling the proper function of overcurrent protective devices and equalizing potential around the substation so as to protect personnel. Step and touch potentials were defined and reviewed in this context as well as the role of current, its effect on the human body, and its limitation. Protective structural features and design were described for establishing and ensuring redundant safety of workers in substation environs. Some additional detail with respect to equipment and connections and testing to assure effective function are now reviewed. The independent standards authorities in this field are the National Electric Code® (NEC®) and the National Electrical Safety Code (NESC). They go into great detail to provide grounding requirements and applications. NEC Article 250-51, Effective Grounding Path, requires that the ground path from circuits, equipment, and enclosures shall be permanent and continuous, have sufficient capacity to safely conduct any likely fault current, and have sufficiently low impedance to limit voltage to ground and facilitate operation of protective devices. System grounding connections are described in NEC article 250, Section K, Grounding Conductor Connections. Article 250-113 states that grounding conductors bonding jumper connections to conductors, and equipment must be connected by pressure connectors, clamps, or similar approved means. Solder connections are banned because the heat generated by fault currents will readily open solder connections and render them ineffective. Article 250-115, Connection to Electrodes, completes the fault current path to ground by describing the connections to the grid. Grounding conductors are required to be connected by suitable lugs, pressure connectors, clamps, or other approved means. This may seem like a statement of the obvious. But it is all too easy, having completed the physical task of stringing conductors and completing the wire map, to finish the job with an inadvertent connection method that will degrade and open during fault clearance, leaving the system dangerously exposed to voltage rise. Verifying and maintaining a low impedance path as described by the NEC can be made easier by the use of a loop tester. This is a fairly simple handheld instrument that measures impedance

around the entire electrical circuit to which it is connected. The test connection can be made by either a pair of alligator clips or by plugging into the relevant outlet. The test can be done either hot or neutral to ground and is performed on an energized circuit. Depending on the hookup, the tester briefly shorts the hot to ground or to neutral. Don’t worry; breakers won’t trip. The test is completed so quickly (less than a cycle) that protective devices never see it. What is measured is the impedance of the circuit, all the way to the utility feed and back through the hot to the point of test. As the name indicates, this is an electrical loop test. It will not give the individual impedance of the grounding conductor by itself, as described in the NEC mandate, but if a comfortably low reading is shown for the entire loop, then the grounding conductor (or neutral, depending on test hookup) is substantially lower. If a high or suspicious reading is obtained, then the system needs to be investigated in more detail. The NESC goes into greater detail in covering grounding methods. Section 9, Grounding Methods for Electrical Supply and Communication Facilities, provides practical methods of grounding. Sections 93.A, 93.B, and 93.E describe connection requirements. Joints must be made and maintained so as not to materially increase the resistance of the grounding conductor, as in 93.A. They must have appropriate mechanical and corrosion-resistant properties. Means of connection must be compatible with both the grounded and ungrounded conductor and suitable to prevailing environmental conditions, as described in 93.B. The requirements in 93.E.2 state that uninsulated joints and splices that are to be buried should be welded, brazed, or compression type in order to minimize the possibility of loosening or corrosion. Note that while these requirements are most seriously considered at the time of installation, they are permanent and should remain in an effective condition throughout the life of the grid and conductors. While much of the structure is out of site, it can still be routinely tested by employing a high-current injection device and the use of a current clamp meter. Since the substation structure is intended to be maintained at equipotential, current distribution should be uniform. Any deviation indicates a diversion of current such as that caused by a poor connection (Fig. 1). The technology is available to readily test and maintain a grounding system even on the below-grade level.

22

Grounding Systems A bit more involved to implement but also effective and durable is the exothermic weld (also known widely as Cadweld®). No outside source of heat or power is required. Powdered copper oxide and aluminum are placed in a graphite crucible that surrounds the conductors to be joined and ignited with a flint igniter. The two metals interact exothermically, releasing heat, and produce a molten copper and aluminum oxide slag (note the transfer of electrons and rearrangement of the chemical structure of the components). The molten copper flows over the conductors in the graphite mold, melting and welding them together (Fig. 3). The resultant connection has good mechanical strength and electrical characteristics, and a current-carrying capacity equal to that of the conductors. It is a permanent molecular bond that cannot loosen or corrode. It will withstand repeated electrical faults and will not deteriorate with age.

Fig. 1: Ground Grid Integrity Test The connector must not be the weak link in the grounding system. Accordingly, grounding connectors must meet three requirements: ●● Ampacity is not less than that of the conductor. ●● Do not deteriorate with age. ●● Are able to withstand repeated faults. There are two types of acceptable connections: exothermic and compression. There are several types of pressure connectors, but those most used in utility grounding are crimp-type compression connectors. The connector sleeve is crimped over the conductor by use of a crimping tool, either hand-operated, pneumatic, or hydraulic. The tool exerts a pressure that changes the shape of the connector, causing the conductor strands to flow into the serrations of the connector barrel, which then compresses around them. The result is a joint with good electrical continuity as well as mechanical strength (Fig. 2).

Fig. 2: Crimp-type Compression Connection

Fig. 3: Exothermic Weld Compression-type lugs are typically used for connecting copper grounding conductors and bonding jumpers to ground buses, equipment frames, metal enclosures, switchyard steel connections, and cable trays. They are most commonly utilized in exposed areas. They are standard power cable connections, in this case being utilized for grounding applications. They are normally two-hole termination lugs, installed in accordance with manufacturer’s instructions. Lugs and connectors should be color-coded and crimp-type. Crimping tools and dies are either hexagonal or circumferential crimp-type and color-coded with the connectors. Manufacturer’s instructions are followed in application of compression dies. Prior to crimping, the ground conductor should have all surface material removed and be wire-brushed to remove oxide. As compression connectors are tin-plated, no additional preparation of them is required. Install approved bolts, nuts, and washers. Outdoor applications require silicon-bronze hardware. Exothermic welds are typically specified for below-grade, embedded (e.g., in concrete), building steel, and similar connections that are inaccessible or demand a high degree of reliability. They include cable-to-cable and cable-to-ground rod splices, cable-tobuilding steel, and cable lug terminations.

Grounding Systems Additional safety considerations involve surface resistivity, operating handles, and fences. Resistivity of the substation surface is maintained at a high value. This is important in reducing step and touch potentials. The earth surface is covered by a four to six inch layer of crushed rock, which typically has a resistivity around 500,000 Ω∙cm. There must be no intrusion of underlying earth into the rock, nor contamination such as tracking of soil by vehicles. Mixing of the rock layer with earth lowers overall resistivity and diminishes the rock layer’s protective value. Operating handles for disconnecting switches can be particularly dangerous. Augmented protection is in order, such as that provided by a mat of conductors or mesh covering the area where the person stands and connected directly to the operating handle. A diagram of this solution was presented in “Substation Grounding and Personal Safety,” NETA World, Spring 2014. Fences can present a hazard to passersby from the general public. The ground grid can be extended outward to include the fence or a conductor can be buried one meter under or outside the fence and connected to the grid. Adherence to the well-established design principles and considerations described here will assure that the grounding system is safe upon installation; however, for the reasons listed above, a substation grid is subject to considerable trial and stress. Routine testing should be implemented to make sure that the grid retains its full protective capabilities. Two specialized tests have already been discussed above. For the most basic function, resistance to remote earth, there are five tests commonly employed: fall-ofpotential method, simplified fall-of-potential method, two-point method, slope method, and intersecting curves method. All of these have been previously described in detail in editions of NETA World. The fall-of-potential method is the most thorough, rigorous, and reliable method. It takes time and is somewhat labor intensive. The simplified fall-of-potential method relieves some of the work required, but substitutes a mathematical proof of results. The slope method is the most commonly employed for large grids that would otherwise demand too much space for a fall-of-potential test to yield the requisite readable graph. The intersecting curves method is the most labor intensive of all but can be used for sites where space is so tight that even the slope method cannot be used. Finally, the two-point, or dead earth, method provides a quick and easy backup test where nothing else works, but is neither rigorous nor thoroughly reliable. Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

23

24

Grounding Systems

MEASUREMENTS AT LARGE GROUNDING SYSTEMS NETA World, Summer 2015 Issue Moritz Pikisch, Omicron Electronics When it comes to grounding system testing, size is important. For large extra-high voltage substations, the test setup must be considered carefully to obtain true values for step and touch voltages and ground potential rise. Grounding systems are the electrical link between the network’s neutral and ground. In the event of a ground fault, the current returns to the transformer’s neutral via the grounding system. Therefore, the grounding system must have a low impedance to ground in order to avoid hazardous step and touch voltages in and outside the substation. Step and touch voltage, as well as ground potential rise test measurements, help to identify the potential hazards to utility workers and the general public during actual faults. If the test measurements indicate the hazard level is high, the corrective actions needed to ensure personnel safety can then be taken. Performing the required measurements at large grounding systems requires injection of the test current via an adequately remote current probe. IEEE 81-2012 states, “If the distance between the current probe and the ground grid is inadequate, then the measured touch voltages will be less than their true values.” In other words, placing the current probe too close to the grounding system under test would lead to underestimating step and touch voltage as well as ground potential rise. As a result, people could be put at risk by step and touch voltages which exceed the permissible limits during ground faults This article compares two ways for the injection of the test current for the step and touch voltage measurements: Injection via a current probe and injection via an existing power line. A case study including a measurement at a relatively small grounding system revealed significant differences in regards to ground potential rise between the two methods. It shows that the injection via an existing power line leads to a higher ground potential rise than the injection via a current probe. Therefore, the impact of current probe spacing on ground potential rise, as well as step and touch voltages, should be even higher for large grounding systems.

CURRENT PROBE SPACING As shown in Fig. 1, when testing a grounding system, the potential rise of the grounding system and the current probe must not interfere with each other. Between these two potentials is a zone which is not influenced by the grounding system under test or by the current probe. This potential is called reference ground and represents the potential of the entire planet earth. The injected grid

current causes a potential rise of the grounding system under test, which is determined by performing a fall-of-potential measurement. The corresponding step and touch voltages are local potential gradients, as between a metallic structure and a location three feet away (IEEE 80-2000).

Fig. 1: Sufficient Current Probe Spacing If the current probe is placed too close to the grounding system under test, the potential of the current probe and the grounding system overlap. This results in a relative increase of the reference ground relative to the ground grid’s potential. In other words, the ground potential rise is decreasing. Step and touch voltages in and around the substation are associated with ground potential rise. The higher the ground potential rise, the higher are step and touch voltages. Therefore, for insufficient current probe spacing, the measured step and touch voltages will be smaller than an accurate measurement would determine them to be. If they are then used to calculate what the actual step and touch voltages will be in the worst case condition of a remote ground fault, the result will be an underestimation of the true hazard to people inside and outside the substation.

INJECTION VIA CURRENT PROBE For large grounding systems, the extent of the potential rise could reach hundreds of feet. This implies that the current probe must be located even further away to avoid overlapping. IEEE 812012 recommends a minimum distance of five times the ground grid’s largest dimension between the ground grid and the current probe. The largest dimension of extra-high voltage substations can exceed 600 feet, which means that the current probe must be placed greater than a half-mile minimum.

25

Grounding Systems Many practical problems are involved with this requirement Installing the injection line is time-consuming, especially when it involves crossing roads or other obstacles. For some environments, it is simply impossible to draw an injection line with the required length due to inaccessibility. Safety is another critical issue which must be addressed Step and touch voltages at the ground grid under test which are caused by the test current are usually between 10 and 100 mV and are therefore no threat to personal safety. In contrast, the remote current probe may be hazardous since the major part of the test device’s source voltage drops there. The touch voltage of the current probe could exceed a safe value. The area around the current probe must therefore be cordoned off and observed to safeguard passing people or animals. Using a ground tester that only applies voltages lower than approximately 50 V is beneficial from a safety perspective since the current probe’s touch voltage would be limited to a safe value. Such a test source poses an accuracy issue though because the measured touch voltages in the substation would be very low, as only a minor part of the source’s voltage is dropping at the grounding system. As an example, the ground impedance of a current probe and a large grounding system are assumed to be 500 Ω and 100 mΩ, respectively. Using a 42 V source voltage, the potential rise of the grounding system under test would only be approximately 10 mV. The touch voltage at distinct locations in and outside the substation can be conservatively considered as one-tenth of that value or less, which means that the measured touch voltage would be under 1 mV. To measure such small voltages, the test device accuracy has to be considered, along with the effects of interference from adjacent live parts. With respect to interference, an effective noise-suppression method can be employed, as discussed later in this article (Fig. 3).

INJECTION VIA EXISTING POWER LINE Injection of the test current using an existing power cable or an overhead transmission line offers an alternative to overcoming the problems involved with using a current probe. Of course, shutting down a line for grounding system testing is not easily arranged. Nevertheless, this alternative is worth some consideration for a number of reasons.

Safety: As discussed previously, hazardous touch voltages occur at the current probe when injecting adequate test currents to maintain an acceptable signal-to-noise ratio for the step and touch voltage measurements. Injecting the test current via a remote grounding system eliminates this problem since the touch voltages will be much smaller due to the smaller ground impedance. Connecting a test device to an existing line usually involves coupling from parallel systems. There are dedicated test sets

available in the market that emphasize operator safety and protect against overvoltages on the line under test for all known scenarios.

Accuracy: Injection via a remote grounding system allows for higher magnitude test currents due to the low impedance of the phaseto-ground loop used for injection. The resulting step and touch voltages, as well as the potential rise of the ground grid under test, is higher than using a current probe and thus results in a better signal-to-noise ratio.

Simulation of Real Fault: Injecting the test current via an existing line simulates a ground fault at a remote substation. While the test current is smaller than the maximum fault current, the scenario’s setup is the same as a true ground fault. Thus, a more realistic measurement of the step and touch voltages in and outside the substation can be made.

Convenience and Time Saving: No long injection line has to be taken out to the field to ensure sufficient current probe spacing; hence, the measurement is less time consuming and complicated.

COMPARATIVE TESTS To compare the two previously introduced injection methods, comparative field tests have been performed. The setup of one test is shown in Fig. 2. The grounding system under test is for a 20 kV – 0,4 kV substation with dimensions of 82 x 33 feet. The maximum dimension of the grounding system corresponds to the length of the diagonal which is 88 feet by employing Pythagoras’s theorem. According to the requirement in IEEE 81-2012, the current probe for injection of the test current must be placed at least 5 times the maximum dimension of the grounding system distant or 440 feet in this example. The environment around the substation is agricultural area and includes two ponds. There are water pipes going out of this station, which therefore have to be considered as part of the grounding system. Their impact will be discussed later. The comparative test only included the fall-of-potential test. Step and touch voltage measurements have not been performed. However, step and touch voltages are associated with the ground potential rise of a grounding system. Therefore, fall-of-potential measurement results are indicative of what can be expected for step and touch voltages as well. For injection via an existing power line, a 20 kV power cable has been taken out of service (marked in yellow in Fig. 2). The remote end of this cable is located in a 110 kV substation about 820 feet away from the grounding system under test. Therefore, the required minimum distance of 440 feet for the test current injection location has been met. The cable has been grounded on its remote end to inject the test current via the remote substation’s grounding system.

26

Grounding Systems

Fig. 2: Test Configurations and Results A test current of 80 A was injected first at 30 Hz and then at 70 Hz. The fall-of-potential measurement was made in the direction of the blue arrow in Fig. 2 at various distances from the grounding system under test. The measured voltage is processed by a digital filter, which suppresses noise at frequencies above and below the test current’s frequency. Fig. 3 gives an example of the voltage measurement at 30 Hz with considerable interference at 50 Hz. To prevent the interference from affecting the measurement accuracy, only the portion at 30 Hz is measured .The results for 30 Hz and 70 Hz are then interpolated to 50 Hz to obtain the value related to the power system frequency. This test has been performed in Germany with an operating frequency of 50 Hz. For an operating frequency of 60 Hz, the same methodology can be used by simply selecting the test frequencies accordingly. Fig. 3: Frequency Selective Measurement at 30 Hz and Interference at 50 Hz

27

Grounding Systems In the yellow table in Fig. 2 and the diagram in Fig. 4, the results of the fall-of-potential measurement with the power cable are displayed as an impedance pattern over distance. Since the injection of the test current was performed via a shielded cable with the shield grounded on both ends, the shield current must be measured to calculate the grid current. This is because only the grid current causes the measured potential rise of the grounding system. The current, which returns via the shield, doesn’t contribute to the potential rise.

Fig. 4 compares the fall-of-potential profiles for all four injection scenarios using the values from the tables in Fig. 2. For the injection via the power cable, the measurement was fully performed, whereas only the last three measurement locations for the injections via the current probe were done. The values are sufficient for a valid comparison between the two employed injection methods. The results of the injection via the power cable are higher than the ones for the current probe injection. This indicates that the actual potential rise of the grounding system would be underestimated by using the current probe injection. A remote fault on the power cable would cause a higher potential rise than determined during the test measurement. It is also interesting to see the differences between the three current probe locations. The most remote current probe showed a slight increase of the impedance over distance, similar to the injection of the power cable. The closest current probe even shows a decrease of the impedance over distance which could be caused by the outgoing water pipes.

Fig. 4: Fall-of-Potential Profiles for the Four Different Injection Scenarios

5. Conclusion

Measurement of the shield current can be easily performed by using a clamp-on meter located on the cable’s shield connections to ground. The phase angle of the shield current in relation to the injected current must be taken into account to calculate the magnitude of the grid current accurately, due to complex subtraction as shown in following equation:

Testing small grounding systems by using current probe injection is usually sufficient. However, the comparative measurement illustrates that injection via a current probe may underestimate step and touch voltages for large substations. Therefore, the injection of the test current via an existing power line should be considered for the most accurate determination of step- and touchvoltage and ground potential rise.

Therefore, according to following equation, the intermediate impedance results from the fall-of-potential test have to be corrected since intermediate results are calculated by using the entire test current. None of these values can be directly compared to the values obtained by injecting the test current via a current probe.

Moritz Pikisch studied electrical engineering at the University of Karlsruhe in Germany. After working as an instructor at OMICRON between 2010 and 2013, he switched to a product management role at the beginning of 2014. In this new capacity, Moritz is responsible for the development of testing solutions for line impedance measurement and the testing of grounding systems.

|ZG| = ZG,intermediate|*

|Itest| |Igrid|

For the injection via a current probe (CP), three different locations CP 1 – 3 (orange dots) have been selected, as shown in Fig. 2. Here, a test current of 3 A was used, employing the same noise suppression method as for the power cable injection. The distance of the current probe from the grounding system under test was 295 feet (CP 1), 492 feet (CP 2), and 886 feet (CP 3). The current probe consisted of 4 interconnected ground rods which had been driven about 8 inches into the soil. The fall of potential measurement was performed along the same direction as for the injection via the power cable. The rods used for the voltage measurement were not removed between the individual tests to ensure equal conditions for all tests. For the injection via a current probe, the entire test current was considered for the calculation of the impedances.

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Grounding Systems

A LOOK AT THE BASICS OF LIGHTNING PROTECTION NETA World, Summer 2015 Issue Jeff Jowett, Megger

A lightning stroke can be considered a huge electric spark traveling between clouds or cloud to earth. With such an uncontrolled phenomenon, estimates are no more than just that, but 30 to 50 million volts and 18,000 amperes are reliable parameters. The stroke is approximately 90 percent negatively charged. Protection against such an awesome force is a tall order, but nonetheless achievable. The demand is rigorous, including air and ground terminals, grounding conductors and interconnecting conductors, surge suppression devices, and appropriate fittings. The process of lightning protection consists of intercepting the discharge, safely conducting the lightning currents while minimizing the effects, and dissipating the currents into the earth. Various systems have been devised to address these demanding requirements. Some of these involve advanced technologies, such as the early streamer air terminal and dissipating air terminal. Some commentary remains that they are unproven technologies; furthermore, they are not recognized by standards organizations like UL and NFPA. The most widely-accepted protection method continues to be the Franklin air terminal. Building a protective system begins with risk assessment, including the type of structure to be protected and its construction, location, topography, and contents. A major consideration is the lightning frequency in the area, which varies drastically around the country. These factors are described by six indices and can be assigned numbers indicating relative degree. Type of structure begins with small single-family residences and proceeds through various sizes of commercial buildings, from sensitive structures such as smoke stacks and towers, to hospitals, to buildings housing or manufacturing volatile materials. Construction takes into account both frame and roof while assessing them with respect to use of wood, concrete, structural steel, and other materials. Where metallic structure is involved, electrical continuity is a further important consideration. Location involves surrounding structures and terrain, with both the square footage and the height above surrounding structures and landscape being assessed. The highest risk factor here is height extending more than 50 feet above adjacent structures and terrain. Topography is assessed in four categories: flat, hillside, hilltop, and mountaintop. Contents include furnishings, combustible and non-combustible materials, population of occupants, livestock, and equipment. This category extends to

fine points such as historical nature of materials and mobility of personnel (e.g. bedridden). Last assessed is lightning frequency, known as isokeraunic level. This is the number of lightning strokes per unit time and is assigned a rating from 100 in much of central and south Florida, especially the western side, diminishing steadily proceeding north and west, with some uptick in activity in central Colorado and western Montana before dropping along the Pacific coast to a zero to 10 rating. Once these six factors have been assessed, the risk factor is calculated according to: where F is an index number inversely proportional to the isokeraunic level. Zero to two is considered light risk, with anything over seven considered severe. Being able to objectively assign a number to risk helps provide a basis for evaluating the next step, which is to design a protective system. Applicable standards are NFPA 70 and 780, and UL 96 and 96A. NFPA 780 is the standard for installation of lightning protection systems. It is the most active standard but not an enforced code. UL 96A is also an installation standard, while 96 covers the manufacture of materials. Independent, thirdparty inspection is described and outlined in 96A. NFPA 70 National Electrical Code includes lightning protection systems and separate but connected grounding electrodes. NFPA 780 describes strike termination devices (lightning rods), the initial contact point at which the lightning stroke is to be deflected into the protective system and away from where damage could occur. These terminals provide the initial line of defense, but they are not required for exposed metal structural parts of at least 3/16 inch thickness, which can be connected directly to the protective system. For redundant safety, at least two current paths must be provided. The height of the air terminal should be at least 10 inches above the protected structure. If over 24 inches, the air terminal must also be supported by braces permanently and rigidly attached to the building and at a point not less than one-half the height.

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rod. Its description in terms of size, depth, and number of rods is covered by 2014 Edition of the NFPA 780, 4.13.1 through 4.13.8. If it is a dedicated electrode, it should be paralleled with the electrical system ground to prevent voltage gradients that could draw current into building wiring and equipment.

Fig. 1: Air terminals must be correctly spaced to provide complete protection. Positioning of the devices is also critical and prescribed. On pitched roofs, devices are to be placed within two feet of ridge ends. On gently sloping or flat roofs, they are placed at edges and outside corners. Density of placement is not to exceed 20 feet, but for devices 24 inches and above in height, placement can be extended to not more than 25 feet. Flat or gently sloping roofs that exceed 50 feet in length or width shall have additional air terminals spaced not to exceed 50 feet on flat and gently sloping areas.

A lightning protection system creates what is called a zone of protection (defined in NFPA 780 3.3.45 as the space adjacent to a lightning protection system that is substantially immune to direct lightning flashes). Its breadth can be determined by the rolling sphere method. Described in NFPA 780 Annex A.4.8.3, the zone of protection is the space not intruded by a rolling sphere with a radius of 150 feet. Imagine this as a ball tangent to earth and resting against the air termination. All space in the vertical plane between the two contact points (earth and air terminal) and under the sphere define the zone of protection. Similarly, if the rolling sphere were resting on two or more strike terminations, the vertical plane under the sphere and between those points defines the zone of protection. The rolling sphere is defined by the formula: d = √[h1(300 – h1)] - √[h2(300 – h2)] d = horizontal distance h1 = height of higher roof h2 = height of lower roof (top of object) Use of the formula is based on a 150-foot striking distance. The sphere must be tangent to the lower roof, or in contact with earth and in contact with the vertical side of the higher structure. The difference in height between the upper and lower roof or earth must be no more than 150 feet. As an example, imagine a main building 120 feet in height with an annex 50 feet high and extending 30 feet: d = √[120(300-120)] - √[50(300-50)] d = √21,600 - √12,500 d = 146.97 – 111.8 d = 35.17 The calculated distance extends beyond the actual size of the structure, and therefore, it falls within the zone of protection. (See Fig. 3)

Fig. 2: Conductors must have proper bend r a dii to prevent puncture. There are also standards which describe allowable bend radii for conductors. (See Fig.2.) A common, and potentially disastrous, error in lightning protection design is to randomly string conductors together and let them fall where they may. For effective lightning protection, the demands are more rigorous. Lightning does not like to travel a curved path and will punch through insulation at right-angle bends. Accordingly, no conductor bend shall have a radius less than eight inches or form an included angle less than 90 degrees. The down conductor (grounding conductor) terminates at a grounding electrode (ground rod). Depending on local soil conditions, this may be a more elaborate system than a single

Fig. 3: Rolling Sphere of Zone Protection

30 Materially, then, a lightning protection system is made up of terminations in air and ground, conductors, connectors, and fittings. It may also have a surge suppression device. The air terminations intercept the lightning discharge, direct the currents into a safe path to ground, and provide zones of protection. The conductors concentrate the lightning current in a safe path away from equipment and personnel. They must be low impedance paths, and having multiple parallel paths enhances their effectiveness. They can be of copper or aluminum, and some offer UL listing. The ground termination dissipates the current into the earth. It must be of low resistance and not lead to dangerous step potentials in the surrounding area. Grounding electrodes range in complexity from the single ground rod through plates, meshes, and large grids of interconnected rods. They all do essentially the same thing, just providing larger and larger amounts of interface with the soil to lower resistance and overcome difficult soil conditions. Ufer grounds are concrete encased electrodes using rebar in foundations. They should not be relied upon solely because lightning dissipation can damage concrete foundations. Poor local soil conditions can be countered by the use of enhanced ground rods, where a bore hole is drilled and backfilled with some form of conductive material around the ground rod. Not to be overlooked are various connectors and fittings that serve to bond conductors to terminals and building structure. These must be tight and well maintained to alleviate potential between metal bodies and prevent flashover. Because of the enormity of lightning strokes, both in magnitude and variance, no protection system can offer a 100 percent guarantee. But, by following the standards and observing established good practices, the chance of damage can be more like, “getting struck by lightning,” as the expression goes. Upcoming articles will examine additional steps in more detail, such as surge suppression and other measures for assuring redundant safety. Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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GROUNDING IN THE SOLAR INDUSTRY NETA World, Summer 2016 Issue Jeff Jowett, Megger

Solar energy is a rapidly developing and expanding segment of the electrical power industry, spurred by the need for additional sources and green (i.e., environmentally friendly) generation. In photovoltaic power generation, a miniscule fraction of the limitless energy of the sun is chemically converted to usable electricity. Solar generation can provide power directly to homes and commercial facilities and is also integrated into the larger power grid. The basic unit of generation is the solar panel (module), where the sun’s energy is converted to electricity. The individual modules can then be tied together into arrays, sometimes covering vast areas of land to enhance total output. Like the more common parts of the electrical system, solar generation must be grounded. In Photovoltaic Design & Installation by Ryan Mayfield (John Wiley & Sons), Mayfield refers to grounding as “the most confusing, debatable, and fun topic in the photovoltaic world.” Just as in other segments of the grid, effective ground protection consists of two distinct and inter-related parts: bonding and grounding. Bonding (also referred to as equipment grounding) is the connecting of individual pieces of equipment in an equipotential network. System grounding is the termination of the equipment grounding at an electrode buried in the earth. This article will examine equipment grounding first.

battery boxes, and any metallic box holding electrical equipment can have a properly sized conductor connected to the ground lug on the equipment and then to the grounding system, thereby creating an equipment-grounding conductor (EGC). Every module must be connected to an EGC. There is often a connection point on the frame for this purpose, usually in the middle of the long edge, but necessary hardware and instructions have been reported as frequently lacking. Two means of connection are most employed: ground lugs and grounding clips. A ground lug (Fig. 1a) is a metallic screw-type clamp. It can be placed at the manufacturer’s suggested point on the module. The EGC is then screwed tight to the lug. The same EGC can be run from lug to lug, thereby connecting the whole array. The lug must be rated for outdoor use and direct burial. This option, however, can be tedious and time-consuming.

EQUIPMENT GROUNDING The purpose of equipment grounding is to maintain all electrically conductive components at ground potential. If a live conductor accidentally contacts any of the protected equipment, the current is provided with a low impedance path to ground that effectively shunts it around personnel while inciting protective devices to trip. Accordingly, the National Electrical Code (NEC) states that “exposed non-current-carrying metal parts of module frames, equipment, and conductor enclosures shall be grounded.” This requirement applies to all PV systems. The equipment-grounding conductor runs alongside the other conductors in the PV circuitry. It is defined by the NEC as “the conductive path installed to connect normally non-current-carrying metal parts of equipment together and to the system-grounded conductor or to the grounding-electrode conductor, or both.” Electrical components such as combiner boxes, inverters, disconnects,

Fig. 1a: Ground Lug Alternatively, a grounding clip (Fig. 1b) can be placed between the module and the racking system that composes the structure upon which the modules are mounted. The clip pierces the module frame and the racking system, metallically bonding the two and making the mounting rails the EGC. Be certain all the rails are connected together, which can be done prior to installation of the modules.

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Grounding Systems In addition to considering the potential damage to undersized conductors from over-currents, the possibility of physical damage should also be taken into account. If such risk exists, the EGC can be protected in conduit or be at least 6 AWG, as the heavier gauge will withstand physical abuse that might damage a lighter gauge. In the PV industry, EGCs are most commonly bare copper. Within conduit, either bare copper or insulated ground conductors are used. Using building wiring for ground wire in conduit is acceptable.

Fig. 1b: Grounding Clip After all components are bonded together, a single EGC can be bonded to one of the rails and brought to the combiner box. This method is not as labor-intensive, but the clips must be placed precisely as specified by the clip manufacturer. Full contact with the module and rack must be verified; otherwise, there is the possibility of an open or weak bond that would defeat the purpose of ground protection of the array. Similarly, if a module is removed, it must be done without disrupting the ground continuity of any other part of the structure. If the lug method uses a continuous conductor, then the structure remains protected. Proper rail bonding assures similar protection where the clip method has been used. The equipment-grounding conductor must be sized properly to accommodate maximum prospective current. Again, the requirements are set forth in the NEC and are based on the over-current protection device (OCPD) for the system. A ground fault protection device (GFP) should also be installed in the system. Article 690.45 provides a table that specifies the gauge of the EGC based on the amperage rating of the OCPD. Not all PV systems require OCPDs. In that case, the grounding conductor is sized based on the short-circuit current. The same table can be used, substituting the short-circuit current for the OCPD of the same rating, but no gauge smaller than 14 AWG should ever be used. If there is no ground fault protection device (GFP) installed in the system, the EGC is sized with an ampacity at least twice that of what is called the “conditions of use” ampacity for the current-carrying conductors. These parameters are given in Tables 310.15(B) (2)(a), 310.15(B)(2)(c), 310.16, and 310.17 of the NEC. However, these are last-option measures, and it is highly advantageous to have an installed GFP. Fortunately, all grid-direct inverters come standard with built-in GFPs, and for battery-based systems, they are easy to integrate.

Finally, all the current-carrying protection of equipment grounding will be lost if not connected to adequate system grounding. Currents traveling on the grounding conductors must be diverted to earth at low impedance to not exploit unwanted paths through equipment and personnel. This function requires an adequate grounding electrode (GE) making contact with the surrounding earth. The most commonly recognized electrode is the ground rod, often a copper rod driven eight feet into the earth. For a better ground, or in poorly conductive soil, a deeper rod can be driven. Also, extra rods can be added and paralleled together with a conductor. To avoid the two rods behaving as only one, the second rod is added at a horizontal distance slightly greater than its depth. A second rod will generally decrease ground resistance by about 40 percent, but additional rods invoke the Law of Diminishing Returns, as increments become progressively smaller. The solar industry also uses the Ufer ground. For roof-mounted arrays, the steel reinforcement of the concrete foundation may be used to make contact with the earth. It is a good idea, however, to augment this with a parallel ground rod, as lightning strikes can damage foundations by vaporizing the trapped moisture in the concrete. (Historical note: Ufer is not an acronym, as sometimes reported. It is actually the name of Herbert G. Ufer, the electrical engineer who pioneered the method. During WWII, a method was needed to safely ground ammunition bunkers — at obvious risk — and it was Ufer who came up with the idea that the foundation steel already in place would serve.)

GROUNDING ELECTRODE CONDUCTOR The second essential element in system grounding is the grounding-electrode conductor (GEC). This is a conductor that connects the rod(s) or Ufer to a point where all the other grounded conductors can be connected. A good example is a 6 AWG or 4 AWG wire from the grounding electrode at one end to the ground busbar inside the main distribution panel (MDP) at the other end. Article 690.47 is the principal NEC reference. If the PV system is utility-interactive, either grid-direct or battery-based, the PV system grounding is then paralleled with the existing utility system ground. Electrically separate grounds can develop voltage gradients between them that will behave counter to the purpose of the grounding system, causing ground currents to flow into an electrical system. Paralleling them together brings them to the same potential. There are two common ways to make the system-grounding connection in a utility-interactive system.

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Grounding Systems One is to connect an additional ground rod or two to the inverter system grounding (6 AWG GEC recommended) and parallel it to the existing utility electrode (Fig. 2 top). This must be done with a GEC of the same gauge as the existing utility GEC. A second method is to run a GEC from the inverter to the existing utility electrode (Fig. 2 bottom). This conductor would be sized according to NEC requirements. For stand-alone, batterybased systems (the solar array is providing the sole source of electricity to the ac load), a utility ground is unavailable, so a new grounding electrode must be installed. Two 6 AWG or 4 AWG GECs must then be connected, one from the dc wiring enclosure where the inverter connects to the battery bank and the other from the ac MDP. As to sizing the GEC, Article 250.66 of the NEC describes the requirements for the ac side, and Article 250.166 covers the dc side. For utility-interactive systems, a GEC will already be in place from the original contractor. Stand-alone,

battery-based systems require the installation of a new GE and GEC. The GE is installed as close to the MDP as possible. If the GEC is run outside without conduit, it should be at least 6 AWG. The robustness of this gauge is considered sufficient to provide physical protection. If the GEC can be run without exposure to physical damage, an 8 AWG conductor for the dc side may be adequate. Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

Fig. 2: Two Common Ways to Make System-Grounding Connection in a Utility-Interactive System

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HAZMAT GROUNDING NETA World, Fall 2016 Issue Jeff Jowett, Megger

Electrical grounding is installed primarily for safety and also for the efficient functioning of the electrical system and installed equipment. The grounding system diverts unwanted currents (fault currents) safely into the ground and away from persons and equipment to protect against potential electrocution and fire. The grounding system also mitigates noise and establishes a firm zero reference for voltage rating, thereby aiding proper and efficient functioning of electrical equipment. These core functions are well known and are commonly implemented by permanent grounding structures in the soil, from a simple rod for a residential ground to a complex and extensive grid underlying a power substation or commercial facility. However, there are less well known but equally important protective functions of grounding. One of those is HAZMAT (hazardous materials) grounding during transportation. This includes highways and railways as well as accident situations and normal operation. Performance isn’t the issue; it’s all about safety. The grounding electrode isn’t normally a permanent part of the larger electrical system, but often a hastily installed rod in a race against time. Tanker trucks and tank cars on railways can carry volatile and potentially dangerous materials and become involved in accidents.

Fig. 1: Tipped Truck with Ground When this happens, the previously well-protected dangerous material can become instantly exposed to potentially catastrophic consequences. One of the worst of these hazards is

ignition. Volatile materials can be readily ignited to explode or catch fire. Given tank-car quantities, the ensuing conflagration can wipe out a small town. The responsibility for averting or successfully containing such potential disasters usually falls upon the local or municipal fire department. A major culprit causing the ignition of volatile materials is static electricity. Just picture the shower of sparks flying as a metallic body goes careening down a road surface. Such violent stress in a conductive material like a tanker hull can readily cause a separation of charge. Static charge will usually dissipate on its own as electrons flow to reconstitute a neutral state. But if the separation of charge is across an air gap, even of miniscule dimension, an arc may occur. If this happens in the presence of volatile material, the heat of the spark can start a monumental chain reaction and a devastating explosion. Safe, non-volatile dissipation of charge can be readily accomplished by effective grounding. The quicker a good, lowresistance ground can be established, the better. A heavy-gauge grounding conductor of negligible resistance is attached to a ground rod driven into the earth with the other end connected to the hull of the stricken tanker.

Fig. 2: Train tanker with Ground Firefighters and first responders are trained to move the potential spark or arc out ahead of them. They would connect the cable to the tanker first and then take it to the earth ground. This is a safety feature to protect firefighters and first

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Grounding Systems responders. Once a good electron path is established, safe equalization of charge can occur through the earth. Although soil in small quantities is not considered a good conductive material, planet Earth is a good conductor, principally because there is so much of it. The important thing is to have the ground rod make an efficient low-resistance contact with the vastness of the surrounding soil. Simply driving a standard rod may provide a good ground, or it may not. The conductive quality of soil varies considerably and is profoundly affected by local conditions, everything from weather to local construction. To be thorough and rigorous, as well as to conform with various authorities such as insurance coverage and local safety codes, you may be required to test the rod. At crash sites, time is of the essence. Even though a resistance test of the temporary ground rod may be advised or required, it may be skipped over for the sake of expediency. To actually perform the task, the obvious method of choice would be the clamp-on test. To review, a clamp-on ground tester is similar to a clamp-on ammeter; the jaws are opened and clamped around the test item, and voilà — there’s the measurement. Sorry, Charley, it’s not that easy. A clamp-on ground tester has two circuits and two windings in the jaws, one for current and one for voltage. A test current is induced on the grounding system and the voltage drop measured around the circuit. Ohm’s Law performs the resistance calculation. The technique works well in utility-grounded systems where the multi-grounded neutral provides a convenient lowresistance return. But on an overturned tanker, no such circuit exists. The tester merely reads an open circuit.

Fig. 3: Truck with Clamp-On Ground Tester Indeed, a temporary return can be rigged by running a wire back from a metal fence post, but this is a drop-dead or betterthan-nothing alternative at best. It wouldn’t fare well under intense third-party scrutiny. A more traditional method is called for: in this case, a standard three- or four-terminal ground tester. Here, in place of windings in a clamp, the voltage and potential circuits are extended out by long wires from terminals on the tester to probes driven into the ground at discrete distances.

Fig. 4: Traditional Fall-of-Potential Ground Test These distances are largely dependent on soil conditions and can be hundreds of feet, hardly amenable to a quick test under pressure. The full procedure, as described in IEEE Std. 81, is to graph a series of readings taken at regular intervals as the potential probe is moved toward the current probe. The graph then reveals the maximum resistance at the limits of the electrical field around the ground rod, beyond which no additional resistance is encountered. This procedure is called Fall-of-Potential (FOP) and is regularly described in the literature. Its limitation is obvious: time. For a permanent structure, like a building ground, it’s the method of choice. But for HAZMAT grounding, a quicker method is the order of the day. Experienced ground testing technicians often take a shortcut around Fall of Potential by merely moving the potential probe back and forth five or 10 feet and taking two or three additional readings, as opposed to plotting and graphing the entire distance. The measurement displayed on the test instrument is the soil resistance to the point of placement of the potential probe. The three or four readings so collected may vary by a few ticks due to localized inconsistencies in the soil. They can be averaged to get an acceptable measurement. What one does not want to see are steadily rising numbers as the potential probe is moved away from the ground under test. This would indicate that the maximum resistance that defines the quality of the ground connection has not been reached. The test is being conducted within the electrical field of the test ground, not beyond it. The probes would have to be moved to greater distances and the test rerun. As every such measurement may not be exactly the same to the last decimal, a degree of operator interpretation is involved in accepting or rejecting the result. Therein lies a possible source of error. To make such a test more objectively reliable, one can go to the Simplified Fall-of-Potential. The test procedure is basically the same, involving only three measurements. But instead of the operator deciding, a brief mathematical proof separates an acceptable test from a spurious one. The three readings are taken halfway and at 40 percent and 60 percent of the distance to the current probe. The readings are averaged, and the one that deviates most from the aver-

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age is expressed as a percentage of the average. This figure is then multiplied by a correction factor of 1.2. The resulting calculation is the percentage accuracy of the average, like an accuracy statement for a meter. The same general rules apply. For example, if a calculation of 10.2 Ω calculates to a 1.5 percent accuracy, that’s good. If it calculates to greater than a 10 percent accuracy (industry standard), the test should be considered unacceptable and repeated with new probe spacing. Submitting the calculation in a test report gives the test objectivity and removes the stigma of possible operator misjudgment in the eyes of third parties. Taking the reduction of test time one step further to its optimal single measurement brings us to the familiar 62-percent rule. Seen widely in ground-testing literature, the method consists of placing the potential probe at 62 percent of the distance to the current probe and taking a single measurement. Yes, this actually works, but it is based on ideal test conditions. The theory behind it states that a FOP graph will coincide with the probe position for the perfect measurement at 62 percent (actually 61.8 percent) of the distance to the current probe. As a complete FOP graph covers all the points from virtually zero at the test ground to some value higher than that of the test ground, because of the superimposed resistance of the current probe, the graph must coincide at some point with the correct measurement. This point is at 62 percent. However, this isn’t a universal test procedure because it relies on ideal conditions. Among numerous factors, these include soil uniformity, underground objects, and current probe placement at a sufficient distance that its own resistance is not included. These conditions are frequently not met in practical testing, necessitating other methods. Nonetheless, the 62-percent method does have reference in IEEE Std. 81 and in many cases, will yield the correct measurement, more or less by luck. Under the time pressures that often accompany HAZMAT clearance, it may be the best choice. The ground rod has now been verified, but the grounding conductor that runs from the tank to the rod must also be verified as providing a continuous, low-impedance path. This is relatively easy with a three- or four-terminal ground tester. It does not require an additional piece of test equipment. Modern testers have a selector switch, allowing the operator to engage the desired number of terminals for the required test. Physical jumpering of terminals is no longer required as it was in the old days; just turn the selector to the two-terminal position and run test leads from the tank to the rod. In seconds, the resistance of the grounding conductor will be displayed and should be less than one ohm. If a high reading appears, take measures to tighten the contact at both ends. Alternatively, replacement of the conductor may be necessary.

Fig. 5: Bonding Test Showing Selector Switch The site has now been grounded and static charges dissipated harmlessly into the soil. But the job is not finished. Dangerous materials must be off-loaded into safe containers or tanks. Normally, fluids passing through hoses are considered benign, but in fact, the friction involved can again separate the charge in the hose material, and the site reverts to a dangerous condition with a risk of arcing. To guard against this, hoses have to be electrically tested. A new piece of test equipment, an insulation tester, is now required. Fortunately, none of the requirements are demanding, and so an economical basic-function tester may be employed. Industry standard is to perform a 500-volt test, end to end. Resistance of the hose material must be low enough to permit movement of charge to counter the effects of the rapidly passing fluid within, so that dangerous separation of charge doesn’t develop on the surface and build voltage to the point of arcing. Since the hoses are made of insulating material, much higher resistances are involved, and hence, the need for greater test voltage. Different materials have slightly different properties, and manufacturers should be consulted on their recommendations. Resistance must be adjusted to hose length, but in general, an industry standard of less than 1 MΩ is recognized. HAZMAT sites can be volatile and dangerous, but all the procedures are established and in place to render sites safe through diligent application of safe working practices. Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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ELECTRICAL SAFETY MANAGEMENT SYSTEM PRINCIPLES PowerTest 2016 Mike Doherty, Shermco Industries Canada Inc.

ABSTRACT This evolution of Safety Management Systems in the electrical safety sector has progressed in the most recent 2015 editions of both standards and continues to gain momentum as the most effective and foundational way to manage electrical safety. NFPA 70E, CSA Z462, NESC, CAN/ULC S-801 and various other IEEE, ANSI, NFPA and CSA guidelines and standards will be heavily referenced to make a strong case to manage electrical safety in the Plan - Do - Check - Act spirit of ANSI Z10 and CSA Z1000. The concepts explaining why Safety Management System standards in fact fully support your Electrical Safety Program will be discussed. The parallels with integrating your Safety Management System concepts into your electrical maintenance management system will also be explored. The obvious terminology within the safety realm in the electrical sector is to say we work within the parameters of “electrical safety.” As a foundational point within this paper I want to add one more important word and discuss “electrical safety management.” I have said for years if we managed our financial system in our business units like we managed our electrical safety program will be still be in business? This is a core question and as obvious would depend on what your electrical safety program looks like, functions like and quite frankly how it is managed. There are those that do not have any form of electrical safety program and those that have electrical safety programs and may or may not need to manage them in a more efficient and robust process.

bit of information in regards to how Steve Jobs from Apple ran his company. One of his quotes of interest is as follows: “Innovation has nothing to do with how many dollars you have. When Apple came up with the Mac, IBM was spending at least 100 times more on R&D. It’s not about the money. It’s about the people you have, and how you’re led.” To me what this really means is outstanding management and leadership, truly one and the same thing. Without great leadership, management, you will never be as effective as he could and should be. Obviously, these management requirements go across all industries. These management requirements for keeping the worker safe can be demonstrated for example even in the mining industry in Northern Ontario. The significant challenges in regards to managing ore and water levels in one mine led to the deaths of two workers in a fraction of a second and changed their families forever. An electrical accident often happens just as quickly and lives and families most often suffer similar consequences. In any industry and without question in regards to electrical safety and its management it is critical to document not just lagging indicators but very importantly the leading indicators for potential incidents for any electrical work. There are moral, social and economic costs to any injury or fatality. We all know and understand this concept but it needs to be the drive and passion behind the reasons why in our sector, electrical, that we manage effectively to best case practices and existing standards.

Just like any other business process it is clear that robust and efficient “electrical safety management” is truly a best practice not only for the safety of the company’s workers and its contractors but also to the financial bottom line of any business unit. This paper will touch on many of the important and best case practices that can give you some of the what’s, when’s and where’s in regards to managing electrical safety as a best practice.

I always like to say when I’m running a crew there are only two things going to happen today. Number one nobody gets hurt. Number two will be done by 4 o’clock. If we can’t get number two done occasionally because of number one that’s okay. What we do have to do is ensure that we manage the electrical safety risks such that safety is paramount but within the spirit of being a learning organization we also execute outstanding and time responsive execution of task.

One of the most important things you need to get done when you leave the 2016 NETA Conference is to ensure that you do something valuable and effective in regards to electrical safety management when you get back to work. Don’t be a tourist and use your employer’s resources while you are here this week and then not get something done that you picked up this week in Texas. There is always something you can do to make things better in regards to what you have learned this week. Recently there has been quite a

Sometimes there are risk takers in the workplace which could be electrical workers who expose themselves to direct contact shock and/or arc flash and blast in their daily duties. This, obviously, is just not acceptable. The supervisor or manager in charge of those tasks could be considered to be a risk bearer. In my opinion risk takers and risk bearers are one and the same. An electrical worker who takes unnecessary risks on himself almost always tolerates those risks for his family as well. An electrical supervisor or manager

38 who bears those risks for a crew can often find after a significant incident that losing their job and reputation in the electrical sector now makes them a risk taker. Two of the most important concepts for everyone in any electrical organization from top to bottom are to be 1) respectful and 2) professional. To be able to see from the worker’s perspective the supervisor’s and manager’s perspective and indeed the VP’s and CEO’s perspective in your electrical business goes a very long way towards ensuring that your electrical safety requirements are managed dutifully. The greatest engineering achievement of the 20th century without question is electrification. The other 19 as impressive as they are would have been impossible without the outstanding electrical infrastructure in place today in North America. There are still some countries in the world that struggle terribly from a very poorly resourced electrical infrastructure. Every single day there are appalling incidents when human beings interact with electricity that truly cannot be managed in an effective manner. In North America we have designed, developed and executed best case practices for electrical safety management in a number of outstanding standards. The first ones that come to mind are typically NFPA 70E and the NESC (IEEE-C2) in the United States and CSA Z462 and CAN/ULC S-801 in Canada for example. They are electrical safety standards for the scope of work within their specific sectors. Certainly the NFPA 70E and CSA Z462 technical committees have worked very closely to ensure technical alignment between them not only for electrical safety but also in regards to good business. This good business allows for far more effective electrical safety management for cross-border business units. This cooperation is an outstanding example of what can be accomplished in regards to personal safety and efficient work process. CSA Z462 in its first published edition in 2008 had a workgroup as led by Lanny Floyd who designed and developed Annex A which was the first documented connection between some of the classic health and safety managed system standards such as OHSAS 18001, CSA Z1000 and of course ANSI Z10. This correlation and alignment of electrical safety management with the best case practices of these three existing health and safety managed system standards was a huge step forward. There are endless books and theories in regards to managing any business process and/or risk in the workplace. Obviously, without great management any program, for eample an electrical safety program, will not flourish without great management. It needs to be organized in an efficient and effective manner. Peter F. Drucker for example says “Management by objectives works if you first think through your objectives. 90% of the time you haven’t.” As always being organized makes all the difference. In the electrical world you need to get out when the work is being done by the outstanding electricians, technicians and linemen are executing their tasks. It is impossible to manage electri-

Grounding Systems cal safety effectively unless you get to the field and make your observations. As per NFPA 70 Article 110.1(I) (1) (2) - Electrical Safety Auditing, one of the most important portions of electrical safety management process I would suggest thinking about are the two following quotes: “A desk is a dangerous place from which to view the world.” - John Le Care “Catch someone doing something right.” - Ken Blanchard and Spencer Johnson Effective management means getting to the field and finding out what’s really happening? You crews will respect and appreciate those that do and will cooperate in regards to managing your electrical safety programs. Simply put “What’s measured improves.” - Peter F. Drucker. Even the very best business units only have so much time, money and resources for any managed system. Ensuring best practices by accessing recognized and valued standards for your electrical safety managed system will go a long way to accessing the funds required that must be approved by those accountable. Workers and supervisors who have the need to improve their electrical safety programs and managed system clearly need to understand that the VP’s and CEO’s speak a language of business. The language of business requires a business plan where financial resources can be used in an effective managed system. It is only fair and reasonable to expect them to support an electrical safety program if it is expected to be executed within a recognized managed system. A shout out here to one of the finest books anywhere in regards to safety management. I cannot recommend any higher the following book in regards to aligning your electrical safety management systems with best practices. Regardless of the identified hazard these principles as found in this book go a long way towards best practices that can be designed and executed in your electrical safety management systems. Fred A. Manuele’s book called Advanced Safety Management: Focusing on Z10 in Serious Injury Prevention is simply outstanding and a great way to access a fast track to electrical safety management principles. Why is electrical safety management so important? Often a management team in place for many years has never had to endure a significant electrical incident at their site. Of course this is always a good thing but can very easily give a false sense of security in regards to the risk for electrical incident. While the probability and frequency of electrical incidents are significantly low the consequences of a significant electrical incident are most often catastrophic. The concept of “risk taker/risk bearer” kicks in very quickly. The data clearly shows that frequency reduction does not necessarily produce equivalent severity reduction. The current measurement systems of low-frequency can very easily create a serious blind spot in regards to electrical incidents.

39

Grounding Systems Total Recordable Rates or TRR is one of the parameters that health and safety professionals and management teams monitor closely in a high-end business unit. Typically this would include many of the higher frequency injuries like slips, trips and falls for example. There certainly is a lower fatality risk to these type of incidents. Of little impact to the TRR are the lower injury frequency and higher fatality risk incidents of which electrical is almost always a part of. The bottom line is that electrical injuries are only 0.16% of all nonfatal lost time injuries. While this might be justification for some to think that electrical incidents are not truly worth significant effort the reality is as follows. The electrical incidents are always high consequence. They are the seventh leading cause of occupational fatality and only account for 1 to 2% of the total injuries1. Again the concept of risk taker versus risk bearer kicks in when we understand that that means that this 1 to 2 % is 28 to 52% of the total medical costs to that business unit2. It is the second most costly worker’s comp claim in the workplace3. There are many direct costs to any incident and unquestionably many that are easy to ascertain in regards to electrical equipment downtime, process and potential customer issues. The indirect costs are also staggering. Electrical safety management needs to be executed in a planned and ordered fashion. There’s only so much time and money in any business so it is important to get it done correctly the first time. The Plan – Do – Check - Act concepts from health and safety managed system classic standards such as OHSAS 18001, CSA Z1000 and ANSI Z10 should be implemented as per Annex A in CSA Z462 for efficient and manageable use of business resources in regards the execution of a world-class electrical safety program in a managed system. In the nuclear power plant programs within North America one of the best practices is in regards to the spirit of continual improvement. Given enough reasonable time and resources your electrical safety managed system can and will improve. Workers and supervisors and indeed the electrical safety managed system need and must execute Shock Risk Assessment and Arc-Flash Risk Assessment procedures as currently documented in NFPA 70 E (70E-16) and CSA Z462 (page 19). Managing these risk assessment procedures, which are in fact from other best case standards that deal with risk, is just a best practice. This risk assessment procedure is world-class. It breaks out into three steps and then of course into the shock and arc flash risk assessment specifics in the standards.

1) Identify hazards



2) Assess risks

3) Implement risk control according to a hierarchy of methods

Without question electrical safety managed systems supports your electrical safety program. Your electrical safety program will never be as strong and effective as it could and should be without using world-class safety managed systems. If your safety program is based on robust and well-designed and recognized standards it goes without saying that your business unit process in whatever it is that you do will be robust and profitable as well. You will attract and retain the very best employees and be an outstanding place to work. As always, “Good Safety is Good Business.” So what are you going to do? Don’t come to NETA and be a tourist. Take back everything you’ve learned this week and get something done. And as a last thought remember what baseball outfielder and manager Casey Stengel said, “The secret of managing is to keep the guys who hate you away from the guys who are undecided.”

REFERENCES: J. C. Cawley, B.C. Brenner, “Occupational Electrical Injury Statistics for the US, 2003-2009,” Conference Record, 2012: IEEE IAS Electrical Safety Workshop, (Daytona, FL: January 30-February 3, 2012.)

1

Wyzka, R and Lindroos, W., “Health Implications of Global Electrification,” Annals of the New York Academy of Sciences, Vol. 888 (Oct. 30, 1999): 1-7.

2

“Work Related Electrical Injuries,” From Research to Reality, Liberty Mutual Research Foundation, Winter 2010.

3

Mike Doherty is Director of Learning and Continual Improvement at Shermco Industries Canada, Inc. Mike actively volunteers for the industry, including serving as the Technical Committee Chair of CSA Z462 Workplace Electrical Safety since its inception in 2006 and participating as a member of the NFPA 70E Technical Committee. From 2006 to 2015 he acted as the official liaison between Canada (CSA) and the United States (NFPA) for electrical safety. Mike is also a member of numerous professional groups including as a Senior member of the IEEE where he is also an Emeritus of the IEEE Petroleum & Chemical Industry Committee (PCIC). In 2013, Mike received the IEEE IAS Petroleum and Chemical Industry Committee (PCIC) Electrical Safety Excellence Award in Chicago, IL.

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

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alabama 1

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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37

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

46

47

48

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

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florida 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

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Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

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Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

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new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

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HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

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ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

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Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

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Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

164

oklahoma

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

182

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184

185

186

187

188

189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

230

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan

231

232

233

234

235

237

238

Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

242

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

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ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

HANDBOOK

Published By SERIES III

INSULATING OILS

INSULATING OILS HANDBOOK

SERIES III

INSULATING OILS HANDBOOK

Published by

InterNational Electrical Testing Association

INSULATING OILS HANDBOOK TABLE OF CONTENTS Oil Circuit Breaker Condition Assessment Utilizing Analytical Testing Techniques....... 5 David Koehler, Paul Griffin, Rick Youngblood, Lance Lewand

Data Center Maintenance – Part 4 – Electrical Distribution System Maintenance..... 12 Lynn Hamrick

Transformer Diagnostic and Condition Assessment Using Liquid Insulation Testing.......................................................................... 16 Mel Wright

Examination of Transformer Oil Moisture Measurements...................................... 21 Don Genutis

Transformer Maintenance Overlooked Items........................................................ 23 Rick Youngblood

Working Safely with Power Transformers............................................................ 28 Ray Curry

Transformer Insulation Degradation ................................................................... 30 Lynn Hamrick

Establishing Maintenance Zero for Large Power Transformers in Today’s Electrical Utility Sector....................................................................... 33 Ray Curry

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Gauging Transformer Condition........................................................................ 35 Don Genutis

Transformer Liquid Sampling Dangers: Where Does the Air Go?............................ 36 Don Platts and Dave Hanson

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Insulating Oils

OIL CIRCUIT BREAKER CONDITION ASSESSMENT UTILIZING ANALYTICAL TESTING TECHNIQUES NETA World, Spring 2013 Issue David Koehler, Paul Griffin, Rick Youngblood and Lance Lewand, Doble Engineering Company

INTRODUCTION Oil circuit breakers (OCBs) were first used by Boston Electric Light Company in 1898 in which initial versions were operated to open and close the electrical circuit. As with any new technology, numerous changes were made over the years to improve both the design and functionality of breakers, eventually resulting in the oil circuit breakers that are still in use today.1 As the result of the proliferation of SF6 breakers, the use of bulk oil circuit breakers has declined over time and a new OCB has not been manufactured for more than twenty years. However, there are still thousands of OCBs in use and they are still a critical part of power management systems. These breakers are utilized to open and close the electrical circuit as needed and involve both movable and stationary contacts that are prone to wear. Over time, these contacts as well as other components degrade, necessitating the need for preventative maintenance activities. Insulating oils are used in breakers to assist with extinguishing the arc generated when the electrical circuit is opened or closed and to dissipate heat from the arcing source. In addition to arcing, other incipient fault conditions may cause degradation of breaker components. Wear by-products from the use and aging of the components are mostly contained in the insulating oil of the OCB. Through the use of applicable laboratory testing programs, an overall equipment condition assessment can be provided by using a ranking or code to manage a population of in-service OCBs. Appropriate oil and electrical test results may be used to determine abnormal conditions, applying diagnostics based on knowing the materials of construction of OCBs. Typical issues found in oil circuit breakers include the following: ●● Insulating fluid degradation ●● Stationary and moving contact degradation ●● Degradation of interrupter shell and metal components ●● Excessive moisture levels or presence of free water ●● Degradation of tank liner

Fig. 1: Breaker Diagram

DISSOLVED GAS ANALYSIS Through experience, it has been found that high ethylene, ethane, and methane gas levels are indicative of overheating issues in a breaker. Oil circuit breakers that show higher than expected levels of acetylene can be indicative of abnormal arcing conditions with excessive arc extinction durations. The ethylene to acetylene ratio is utilized to distinguish between overheating of the arcing contacts, excessive arcing, and normal operation. Overheating of the arcing contacts can occur due to poor alignment between the stationary and mobile contacts, excessive wear, and loose connections in the breaker along with other issues. Since oil circuit breakers typically operate close to ambient temperature, Ostwald solubility coefficients reported at 25°C can then be used as a guide to determine partitioning of gases between the oil and gas space. Some of the dissolved gasses have a greater propensity to remain in the insulating fluid while others have a greater tendency to escape into the headspace region of a breaker and vent to the atmosphere.

6

Insulating Oils

Gas

Ostwald Solubility Coefficient

Hydrogen (H2)

0.0558

Nitrogen (N2)

0.0968

Carbon Monoxide (CO)

0.133

Oxygen (O2)

0.179

Methane (CH4)

0.438

Carbon Dioxide (CO2)

1.17

Acetylene (C2H2)

1.22

Ethylene (C2H4)

1.76

Ethane (C2H6)

2.59

Table 1: Ostwald Solubility Coefficients for Gases in Transformer Oil 2 By reviewing the data provided in Table 1, it can be seen that hydrogen, nitrogen, carbon monoxide, and oxygen gases have relatively low solubility in the insulating fluid. Acetylene, ethylene, and ethane gases have a relatively high solubility in the insulating fluid. For this reason, hydrogen and oxygen gas levels are used to help determine if there is a plugged or narrowed vent on the oil circuit breaker. Plugged vents can be caused by birds, insects, etc. This is typically observed by DGA results showing high levels of hydrogen being present in the insulating fluid, along with decreases in oxygen levels. Dissolved gas analysis is the most critical test offered in our industry to identify incipient fault conditions in oil-filled electrical equipment. Infrared thermography is also used to detect overheating in oil circuit breakers as shown in Figure 2. Once a unit is identified as being a concern via thermography, the unit is already in trouble and most likely will require prompt inspection and removal from service to help minimize the chances of failure. This helps to further demonstrate the importance of regular OCB fluid testing to promote planned outages rather than forced outages.

Fig. 2: Infrared Thermography of Three-Phase Oil Circuit Breaker Even though the priority rating indicates only monitoring is required, it is very obvious which tank was in trouble. If the DGA and oil quality analysis indicated that the tank required inspection, there would be no hesitation to perform this task.

FLUID QUALITY TESTING A variety of tests can be used to ascertain the condition of the fluid quality in an OCB and, hopefully, the condition as well. Through experimentation and research, Doble has come to rely on a certain subset of tests which has provided good information on the condition of the breaker without duplicating the effort. The tests that Doble uses are discussed in the following commentary. In regards to measurement of dielectric breakdown voltage on OCB fluids, the ASTM D-1816 test with a one mm gap is preferred over ASTM method D-877 method. D-1816 test values are more sensitive to the various impurities that can be dissolved, suspended, or in contact with the insulating fluid. Free water is very detrimental to the dielectric strength of insulating fluids and can lead to a dielectric failure. Evaluation of relative saturation of water in oil is an effective means to review how much moisture is present relative to how much the oil can hold. For oil circuit breakers, ambient temperature and relative humidity will be the drivers for the relative saturation level of water in the insulating fluid. If a desiccant is not utilized on an oil circuit breaker, the relative saturation of water in the oil will be very similar to the relative humidity of the ambient environment assuming that the temperature inside the oil circuit breaker and that of the ambient environment are constant for a period of time. Conditions where the ambient temperature is below 0°C can form ice within the oil circuit breaker. Because of the qualities of ice in oil, ice can be found floating in the fluid or it can also be found blocking sampling ports and oil piping at the bottom of an oil circuit breaker where it can rupture the tank. For this reason it is important when the weather turns cold to remove free water that might condense in OCBs. For the dielectric breakdown voltage of OCBs, lower limits are used in comparison to transformers because of the breathing to atmosphere and influence of local humidity. Comparison of the results of the three phases provides useful information. Oxidation is one of the key chemical reactions that causes insulating fluids and solid insulation to age. The initial stage of oxidation will produce polar molecules such as aldehydes and ketones. The presence of these molecules will result in a lowering of the interfacial tension value of the insulating fluid. As these polar molecules are further oxidized, acidic molecules, such as carboxylic acids, are formed. These acid molecules are also polar in nature, thus further decreasing the IFT of the insulating fluid, while showing an increase in the neutralization number. IFT values for OCBs can be used as a guide to determine the extent of polar compounds in the insulating fluid. However, since the neutralization number measures the later stages of the oxidation process, this value is important to help determine the end of life of the insulating fluid. It has also been found that since OCBs have much less solid cellulose insulation than transformers, the amount of energy required to generate the same neutralization number is much greater in OCBs, and thus limits for this particular parameter are more strict.

Insulating Oils

7

PARTICLE COUNT

DETERMINATION OF AN OCB CONDITION CODE

Particle count testing of OCB insulating fluids is very useful in determining the overall cleanliness of the fluid, and with helping to identify the amount of OCB wear particles and contact degradation. Particles greater than 50 microns tend to have a significant impact on the dielectric strength of the insulating fluid. Ratios are used to compare the various particle size ranges to help determine the severity of degradation of components.

The Doble Breaker Analysis Program utilizes a 15-point system to develop the appropriate condition code. DGA results have the most impact on the point scale followed by water, dielectric strength, neutralization number, and the particle count results and concentration ratios between the different micron class sizes. Metals-in-oil results are utilized if the concentrations of key metals are higher than established threshold levels. Condition codes range from a 1 (worst case) to 5 with most equipment ranking a 4 or 5 as shown in Table 2.

PARTICLE TYPE Particles suspended in the insulating fluid can be examined by obtaining a representative sample of the fluid in the laboratory and passing it through a 0.45 micron filter. The filter is examined to determine the relative amounts of carbon, fibers, and other particles present in the fluid. Abnormal levels and types of contaminants on the filter are noted. This test is also useful to compare with the amount of particles found during the quantitative particle count analysis.

DOBLE CARBON CODE The Doble carbon code provides a simple qualitative analysis of the degree of carbon contamination found when filtering the insulating fluid through a 0.45 micron filter. Insulating fluids tends to be dark when sampled from an in-service breaker because of the carbon created in the extinguishing of an arc. Larger amounts of carbon may be normal but that depends on the circumstance.

Point Range

Condition Code Assessment

% of Population

12 - 15

1

Remove from Service

0.4

9 - 11.5

2

Investigate

1.3

5.5 - 8.5

3

Monitor-Resample in 3 months

6.8

2-5

4

Monitor-Resamples in 6 months

30.9

0 - 1.5

5

Monitor-Resamples in 1 year

60.5

Table 2: Condition Codes and Sampling Intervals Over the years, as more data comes into the database, the percentages of each condition code have slightly changed, but it has never been more than one percent for a condition code of 1 and two percent for a condition code 2. Table 2 provides quite a bit of useful and interesting information. It shows that with this condition-based technique, it is possible to prioritize those OCBs that really need work (those having a condition code of 1 or 2), only 5 to 10 percent need closer monitoring and that over 90 percent require no maintenance at all thus providing a much more manageable work load. In addition, it is applicable across all service territories or customers.

SAMPLING Fig. 3: Doble Carbon Code Filters

DISSOLVED METALS ANALYSIS Iron, lead, copper, silver, and silicon are some of the critical metals and elements used to monitor the condition of an OCB. Likely sources of the above mentioned metals are: ●● Iron: Deterioration of tank and operating mechanism ●● Lead: Contamination with soldered materials ●● Copper: Initiation of serious contact wear indicating a severely worn or misaligned contact(s) that should be monitored, or indicative of degradation of the cross-arm assembly ●● Silver: Initiation of advanced contact wear that should be monitored ●● Silicon: Degradation of glass reenforced component made of fiberglass, such as a lift-rod or the interrupter shell.

Probably the single most vital aspect of a condition-based oil sampling program is to provide a sample that reflects the bulk oil of an OCB. Because of the way that OCBs are designed and plumbed, it is easy to retrieve a sample that is not representative and thus have results that lead to a false positive (an indication that an OCB needs work when it really does not). In order to obtain a representative oil sample, Doble recommends the following: ●● Flush 1 quart (liter) of oil through the valve if the tank has less than 300 gallons (1135 liters) of fluid. ●● Flush 2 quarts (liters) of oil through the valve if the tank has 300 or more gallons of fluid. ●● Use both a glass syringe and an amber glass or plastic bottle for samples. ●● Use new tygon tubing for each compartment being sampled. ●● Do not remove bubbles formed after sampling in syringes. ●● Take samples after maintenance has been performed to establish new baseline.

8

Insulating Oils CASE STUDIES

An example of some of the materials required for sampling is shown in Figure 4.

Case Study #1 Infrared thermography and high concentrations of hydrocarbon gases indicated a problem. The combustible gas generation rate and ratio of ethylene to acetylene also indicated a thermal problem was developing.

Fig. 4: Sampling Materials Fig. 5: Infrared Thermography of 345GS1500 Sample Date

H2

O2

N2

CH4

CO

C2H6

CO2

C 2H 4

C 2H 2

C 2H 4/ C 2H 2

11/18/02

5

38100

68400

5

16

14

580

114

122

0.93

04/04/05

7

44200

88200

459

60

490

549

4260

7635

0.56

04/18/05

723

30600

71900

7291

493

4227

549

19746

31809

0.62

04/26/05

3285

33400

75800

16516

774

7823

601

33035

35504

0.93

Table 3: Dissolved Gas Analysis data for 345GS1500 In all the cases presented, the scoring of the condition code was performed after the fact but it does show how the Breaker Analysis Program would have rated the oil results.

●● Condition Code: 2 ●● Action: Investigate immediately ●● R  emedial Action: All stationary and moveable contacts were replaced, along with some interrupters

Case Study #2 Infrared thermography confirmed the overheating and associated coking within tanks 1 and 3 based on the DGA results. Elevated Tank

C 2H 4

C 2H 2

C 2H 4/ C 2H 2

Copper

Silver

copper levels were confirmed by internal inspection showing degraded movable contacts. Cadmium

Particles >2µ

Particles >25 µ

1

44096

10363

4.3

13.1

0.2

0.1

99700

1350

2

3868

9354

0.4

9.0

0.2

0.1

58500

414

3

13179

11088

1.2

4.7

0.1

0.0

59700

546

Table 4: DGA, Metal, and Particle Count Data for 345G

9

Insulating Oils The ratings for these tanks are as follows: Tank 1: ●● Condition Code: 1 ●● Action: Remove from service Immediately ●● Remedial Action: All stationary and movable contacts were replaced Tank 2: ●● Condition Code: 3 ●● Action: Monitor: Resample in three months ●● Remedial Action: All stationary and movable contacts were replaced

Fig. 8: Coking and Degradation of 345G’s Stationary Contact

Tank 3: ●● Condition Code: 2 ●● Action: Investigate Immediately ●● Remedial Action: All stationary and movable contacts were replaced Pictures of the inspection and findings are shown in Figures 6 through 9. Fig. 9: Stationary and Movable Contact for 345G Findings: ●● Maintenance was two years overdue for this breaker. ●● Tanks 1 and 3 were hot on infrared thermography scan. ●● The ethylene/acetylene ratio provided a clear indication of contact overheating (wear), especially in Tanks 1 and 4.

Fig. 6: Infrared Thermography of 345G

●● Interrupter wear was noted by large particle count levels.

CASE STUDY #3 In this case the ethylene to acetylene ratios were elevated for all three tanks, but especially for tanks 1 and 3. These ratio levels were confirmed by evidence of coking during internal inspection. Poor contact compression and higher than expected operation count were the main cause of abnormal DGA results. Metal results and particle count data were slightly elevated for this type of breaker.

Fig. 7: Degraded Movable Contact for 345G

Tank

C2H4

C 2H 2

C 2H 4/ C 2H 2

Copper

Silver

Cadmium

Particles >2µ

Particles >25 µ

1

41915

88

476.3

2.7

0.8

1.1

526000

60900

2

340

20

17.0

0.2

0.1

0.2

26900

176

3

5796

26

222.9

0.4

0.0

0.1

27100

1990

Table 5: DGA, Metal, and Particle Count Data for GM4S

10

Insulating Oils

The ratings for these tanks are as follows: Tanks 1, 2 and 3: ●● Condition Code: 1 ●● Action: Remove from service Immediately ●● Remedial Action: Replaced components that were either broken or those not operating properly

Fig. 10: Interrupter Tank 1, Intermediate and Crank Arm Contacts

Fig. 11: Interrupter #5 Intermediate Contact Findings: ●● Lack of contact compression and damaged intermediate contacts ●● Numerous line switching operations due to recent line construction ●● Coking and wear found in all tanks. Tanks 1 and 3 were the most severe.

CONCLUSION Analytical testing of mineral oils used in oil circuit breakers is a cost effective way to identify necessary condition-based maintenance. Failure and forced outages can be minimized by implementing an effective oil circuit breaker maintenance program resulting in significant savings. This paper presented information

on the key analytical tests used to identify abnormal conditions within oil circuit breakers and as detailed by the three case studies. Strong correlation exists between analytical testing techniques and findings in the field. By examining analytical test data, effective inspection and maintenance intervals can be established along with resampling frequencies.

REFERENCES 1

“ IEEE PES Circuit Breaker Tutorial”, Pittsburgh, PA, July 24, 2003.

2

“ Annual Book of ASTM Standards Volume 10.03”, 236 pp, 2012.

David Koehler received his Bachelor’s Degree in Chemistry from Indiana University and obtained his M.B.A. He is the Business Development Manager-Professional Services for Doble Engineering Company. He has 20 years of experience in the testing of insulating liquids and management of analytical laboratories. He has provided numerous technical presentations and published technical articles within the power industry. David is a member of the ASTM D-27 Technical Committee on Electrical Insulating Liquids and Gases. In 2011, David was an Executive Committee Member of the Indiana American Chemical Society. In 2019-2020 David will serve as the IEEE Region 4 Director, while also serving on the Board of Directors for IEEE. Paul Griffin is Doble Engineering Company’s Vice President of Consulting and Testing Services. He has been with Doble since 1979 and prior to his current role has held various positions including Laboratory Manager and Vice President of Laboratory Services. Since joining Doble, Mr. Griffin has published over 50 technical papers pertaining to testing of electrical insulating materials and electric apparatus diagnostics. He is a Fellow of ASTM and a member of Committee D-27 on Electrical Insulating Liquids and Gases. He was formerly ASTM Subcommittee Chairman on Physical Test, ASTM Section Chairman on Gases-in-Oil, and the Technical Advisor to the U.S. National Committee for participation in the International Electrotechnical Commission, Technical Committee 10 and Fluids for Electrotechnical Applications. Mr. Griffin is a member of the IEEE Insulating Fluids Subcommittee of the Transformer Committee. Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA Level 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

Insulating Oils Lance Lewand is the Laboratory Director for the Doble insulating materials laboratory and is also the product manager of the Doble DOMINO, a moisture-in-oil sensor. The Insulating Materials Laboratory is responsible for routine and investigative analyses of liquid and solid dielectrics for electric apparatuses. Since joining Doble in 1992, Mr. Lewand has published over 75 technical papers pertaining to testing and sampling of electrical insulating materials and laboratory diagnostics. Mr. Lewand received his Bachelors of Science degree from St. Mary’s College of Maryland. He is actively involved in professional organizations including the American Chemical Society and ASTM D-27. The authors wish to thank Ameren Missouri for the case study data and pictures.

11

12

Insulating Oils

NICHE MARKET – DATA CENTER MAINTENANCE – PART 4 – ELECTRICAL DISTRIBUTION SYSTEM MAINTENANCE NETA World, Fall 2013 Issue Lynn Hamrick, Shermco Industries This article is Part 4 of a 4-part series on data center maintenance. In Part 3, we discussed electrical maintenance activities associated with the key electrical systems for most data centers: UPS systems and their battery systems and the backup generation systems. In Part 4, we will discuss maintenance activities associated with the electrical distribution system that ties all of these key systems together: cables, transformers, breakers, and automatic transfer switches. This article will focus on electrical tests that should be performed during scheduled predictive and preventive maintenance activities.

PREDICTIVE MAINTENANCE The Predictive Maintenance activities below will be the basis for implementing a condition-based maintenance program. These activities are to be performed while the facility is operating. To obtain maximum benefit from these inspections, samples, and surveys, knowledge of the equipment, systems, and indications of potential failure modes is required.

Physical Inspections Physical Inspections should be performed on high and low voltage equipment. The inspector should be aware of the visual evidence associated with installation errors, equipment subassembly failures, poor equipment condition, overheating, and corona. Further, where digital readouts of electrical parameters are available (i.e., solid-state protective relays, trip units, power-quality meters, etc.), the inspector should regularly monitor status and other available data for system condition. In addition, periodic walk-throughs should be performed to evaluate general equipment condition and changes to operating parameters. For some equipment, a periodic maintenance route should be developed to ensure that an adequate physical inspection is performed: ●● Transformers. Most liquid-filled transformers have liquid level, temperature, and pressure indicators. These should be monitored periodically to ensure that the transformer is operating within acceptable parameters. For temperature, the high temperature indicator should be noted and reset. For pressure, the value should always be slightly positive. In addition, the route should include inspections for oil leaks and spills. ●● Breakers. Protective settings for breakers should be periodically reviewed to ensure that the appropriate settings are in place.

Oil Sample Analysis Oil sample analysis, including a dissolved gas analysis, should be performed on all liquid-filled transformers and oil circuit breakers. To obtain maximum benefit from this analysis, a qualified person should pull the samples and the samples should be sent to a qualified laboratory for analysis. As a minimum, the analysis should include testing for dielectric breakdown, acid neutralization number, interfacial tension, color, moisture, and dissipation or power factor. Suggested quality limits for mineral oil are provided in IEEE C57.106-1991 Guide for Acceptance and Maintenance of Insulating Oil in Equipment, Table 5. Additionally, the dissolved gas analysis (DGA) should be performed in accordance with ASTM D3612/IEC 60567. Suggested key gas limits are provided in ANSI/ IEEE C57.104. Once the key gas limits are exceeded, the ratios of many of the key gases provided through a DGA are indicative of the type of issue you may have internal to the transformer. The suggested key gas ratio limits are provided in the attached Table 1.

Table 1: Key Gas Ratio Limits for Service Aged Insulating Fluids The ratio of CO2/CO is sometimes used as an indicator of the thermal decomposition of cellulose. The rate of generation of CO2 typically runs 7 to 20 times higher than CO. Therefore, it would be considered normal if the CO2/CO was above 7. If the CO2/CO ratio is 5 or less, there is probably a problem. If cellulose degradation is the problem, CO, H2, CH4, and C2H6 will also be increasing significantly. At this point, it is recommended that additional furan testing be performed. If the CO2/CO ratio is 3 or under with increased furans, severe and rapid deterioration of cellulose is occurring and consideration should be given for taking the transformer out-ofservice for further inspection.

13

Insulating Oils When cellulose insulation decomposes due to overheating, chemicals, in addition to CO and CO2, are released and dissolved in the oil. These chemical compounds are known as furanic compounds, or furans. In healthy transformers, there are no detectable furans in the oil (<100 ppb). As the cellulose degrades, the furan levels will increase. Furan levels of 500 to 1000 ppb are indicative of accelerated cellulose aging, with furan levels >1500 ppb having a high risk of insulation failure.

Infrared Inspection Infrared Inspections, or thermographic surveys, should be performed on high- and low-voltage equipment. The survey will include surveying electrical equipment for thermal differences or high limits, which are indicative of problems that could result in equipment failures. Suggested actions based on temperature rises are available in ANSI/NETA MTS-2011. This type of survey is very useful in identifying loose or bad connections and terminations and overloading conditions and should be applied to electrical equipment (i.e., breakers, transformers, automatic transfer switches, buses, and cable terminations). Additionally, this survey is useful in confirming liquid-filled transformer level.

Ultrasonic Emission (UE) Surveys UE surveys should be performed on high-voltage equipment, only. The survey will include surveying electrical equipment for ultrasonic variations which are indicative of problems that could result in equipment failures. This type of survey is very useful in identifying possible corona and arcing conditions. A UE survey is considered an optional test that can be performed in support of further investigation of identified issues.

Partial Discharge (PD) Testing The integrity of high-voltage insulation systems can be assessed through partial discharge testing and analysis on-line. PD is an electrical phenomenon that causes insulation deterioration. Partial discharge can be described as an electrical pulse or discharge in a gasfilled void or on a dielectric surface of a solid or liquid insulation system. This pulse or discharge partially bridges phase-to-ground insulation or phase-to-phase insulation in an electrical apparatus. PD testing and analysis can be the foundation for a viable predictive maintenance program for high-voltage equipment. Periodic use of the technology allows the identification of problem areas with higher voltage terminations and splices prior to failure.

PREVENTIVE MAINTENANCE The preventive maintenance activities below should be scheduled and performed in conjunction with a condition-based maintenance program. These activities are to be performed during a planned outage while associated portions of the data center are shutdown. To obtain maximum benefit from these electrical tests, knowledge of the equipment, systems, and indications of potential failure modes is required. It is important that job plans and

procedures indicate acceptance criteria to the inspector and that as-found and as-left reports are recorded. To determine test voltage levels and the acceptability of the electrical test results, it is recommended that either manufacturer’s recommendations or ANSI/ NETA MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, recommendations are used.

Cables ●● VLF Tan Delta Test. Very low frequency (VLF) testing can be performed to verify a cable’s ac voltage withstand capability. It is simply a pass/fail ac stress test using an instrument with a 0.1 HZ (or lower) output frequency rather than 50/60 Hz. A tan delta test is a diagnostic test that indicates the degree of cable insulation degradation. Rather than using only a VLF instrument to perform a go/no-go proof test, the tan delta unit, used in conjunction with a VLF source, permits the user to grade the deterioration level of many cables in order to prioritize replacement or rejuvenation, or to determine what additional tests may be useful. It is recommended that the voltage levels presented in IEEE 400.2, IEEE Guide for Field Testing of Shielded Power Cable Systems Using Very Low Frequency (VLF), be used for this test.

Transformers ●● Dielectric Absorption Ratio (DAR)/Polarization Index (PI). DAR and PI tests are used for determining insulation condition for apparatus with complex insulation systems, such as transformers. The polarization index is performed to judge the rate of disappearance of charging and absorption currents. The DAR is the ratio of the insulation resistance at the end of one minute to that at the end of 30 seconds at a constant voltage. The PI is a ratio of the insulation resistance at the end of 10 minutes to that at the end of one minute at a constant voltage. For transformers, a polarization index of greater than 1.0 is acceptable. However, the higher the value, the better. ●● Power Factor/Dissipation Factor. This test measures the insulation’s ac dielectric loss (consists of dielectric absorption, conductivity, and ionization loss components) and power factor and provides a measure of the overall condition of an apparatus’s insulation system. The power-factor test is the most effective field test for evaluating the condition of an oilfilled transformer’s solid insulation and its bushings. The test is useful in detecting moisture, contamination, and/or insulation deterioration. Test data is typically evaluated by comparison to prior results from similar equipment and/ or databases. One of the largest equipment power-factor databases and related technical information is that acquired and maintained by Doble Engineering Company. Because of this it is often referred to as Doble testing.

14

Insulating Oils

●● Winding Resistance. Winding resistance measurements for transformers are used to determine if the connections are correct and if there are any severe mismatches or opens within the transformer. Electrical testing instruments are basically digital low-resistance ohmmeters (DLROs). Regardless of the transformer configuration (i.e, either wye or delta), the winding resistance measurements are made phase-to-phase and are considered acceptable if all readings are within 1 percent of each other. Because of the enormous amount of energy that can be stored in a magnetic field, precautions should be taken before disconnecting the test leads from the transformer that is under test. Never remove the leads during the testing process and always allow for enough time to completely discharge the transformer being tested. Large transformers can require several minutes to discharge. ●● Turns Ratio Test. The purpose of a transformer turns ratio (TTR) test is to measure the turns ratio and exciting current of windings in transformers. A transformer’s turns ratio is equal to the ratio of turns of wire in the primary winding of a transformer to the number of turns of wire in the secondary winding. Deviations in turns-ratio readings indicate problems in one or both windings or the magnetic core circuit of a transformer. The ratio measured with this test includes the losses normally found in the transformer, which will result in a ratio greater than that of the physical turns but reflects the real voltage ratio expected for the transformer. ANSI Standard C57.12 specifies that turns ratio be no more than 0.5 percent from nameplate rating of the transformer.

Breakers ●● Insulation Resistance. The purpose of measuring insulation resistance is to determine if the equipment’s insulation system is suitable for operation or even for a high potential test. An insulation resistance test set (typically referred to as a Megger) must be used to perform this test. This test should be performed phase-to-phase and phase-to-ground with the breaker contacts closed and across the open contacts. Evaluating and trending insulation resistance is important in identifying deterioration as quickly as possible so you can take the necessary corrective measures. Testing voltages and acceptable test results are provided in the attached Table 2.

Table 2: Insulation Resistance Test Values Electrical Apparatus and Systems A cautionary note, insulation resistance measurement is temperature sensitive; therefore, ambient temperatures should be considered when evaluating test results. A suggested temperature correction table is included in ANSI/NETA MTS-2011. ●● Contact/Connection Resistance. The purpose of measuring contact and connection resistance is to verify that contacts, or associated circuit segments, in the electrical distribution system are at a low resistance. A digital low-resistance ohmmeter (DLRO also known as a Ductor) must be used to perform this test. This test should be performed from line-to-load terminals of the contacts with the breaker closed. The values should be within 50 percent of each other and comparable to similar devices. The resistance values vary with the size of the breaker with typical values of less than 100 microhms, with some manufacturers suggesting values of less than 30 microhms. Evaluating and trending contact resistance is important in identifying contact deterioration as quickly as possible so you can take the necessary corrective measures. ●● Vacuum Bottle Integrity. For medium- and high-voltage vacuum breakers (>1000 V), overpotential tests have proven successful in detecting vacuum bottle integrity. The test should be performed across each vacuum bottle with the contacts in the open position. Additionally, this test should only be performed after an insulation resistance test has been performed successfully to ensure adequate contact separation prior to performing an overpotential test. Use of ac high potential test sets is typically recommended by manufacturers. If a dc high potential test set is used, a full-wave rectified model is to be used; a half-wave rectified test set can potentially create peak voltages which can damage the vacuum bottle. ●● Electrical Operability Test, Adjustment, Calibration. Electrical operability testing shall be provided for each device which can be electrically operated. This means that for

15

Insulating Oils breakers, switches, starters, etc., which can be operated using remote devices (i.e., are equipped with shunt trips, protective relays, or trip units) the electrically operated circuitry should be tested for operability. For protective relays and trip units this will require the use of test equipment which either primary injects (the tested circuitry includes associated instrument transformers, control wiring, and trip unit) or secondary injects (the trip circuitry only includes the control wiring and trip unit) currents and/or voltages to simulate various trip conditions for each applicable operating mode. It is preferred that device-specific, time-current-curves (TCCs) for the equipment being tested are developed and used to evaluate the acceptability of the results. Where a power system study has been performed using a modeling software (i.e., SKM), the device-specific TCCs should be readily available. When no manufacturer’s recommendations are provided, information available in ANSI/NETA MTS-2011 can be used for evaluating breaker performance. Care shall be taken to note and reinstall appropriate set points, adjustments, and calibration information for each device prior to placing back in service. ●● Mechanical Operability Test, Adjustment, Lubrication. Mechanical operability testing shall be provided for each device. For electrical equipment with mechanical components, most mechanical problems are due to the environmental conditions, improper or lack of cleaning, and improper lubrication of the device. Cleaning activities should include complete removal of existing lubricating greases and deposits from moving parts and contact surfaces. Cleaning surfaces should not include the use of solvents which may leave residues on surfaces or the use of abrasive cloths (i.e., emery cloths, etc.) due to the potentially harmful effects on the surfaces. In most cases, the electrical contact surfaces are plated and using abrasive materials to clean the surfaces may remove or damage that plating. Application of a very thin layer of new lubricant should be provided in accordance with manufacturer’s recommended instructions using recommended lubricants. Where no lubricant recommendations are specified by the manufacturer, use Mobilgrease 28® on both the contact surfaces and the hinge points of the device. Further, blade alignment, blade penetration, and the mechanical open/trip and close operations should be verified. Most manufacturers recommend opening and closing these devices at least annually as part of the preventive maintenance activities.

Automatic Transfer Switch (ATS) Automatic transfer switches are installed in a data center to transfer the electrical loads from the normal power sources to the standby and emergency power sources upon failure of normal power. The ATS must transfer and retransfer the load automatically. Maintenance programs for transfer switches include checking of connections, inspection or testing for evidence of overheating and excessive contact erosion, removal of dust and dirt, and re-

placement of contacts when required. The maintenance procedure and frequency should follow those recommended by the manufacturer. Automatic transfer switches should also be operated periodically. The periodic test consists of electrically operating the transfer switch from the normal position to the emergency position and then a return to the normal position.

SUMMARY For data centers, the electrical distribution system ties together the key electrical systems and consists of cables, transformers, breakers, and automatic transfer switches. Maintaining this distribution system should include the performance of scheduled predictive and preventive maintenance activities. The predictive maintenance activities should be the basis for implementing a condition-based maintenance program. These activities are performed while the facility is operating. To obtain maximum benefit from these inspections, samples, and surveys, knowledge of the equipment, systems, and indications of potential failure modes is required. The preventive maintenance activities should be scheduled and performed based on and in conjunction with the condition-based maintenance program. These activities should be performed during a planned outage while associated portions of the data center are shut down. To obtain maximum benefit from these electrical tests, knowledge of the equipment, systems, and indications of potential failure modes is required. It is important that job plans and procedures indicate acceptance criteria to the inspector and that as-found and as-left reports are recorded. To determine test voltage levels and the acceptability of the electrical test results, it is recommended that either manufacturer’s recommendations or ANSI/NETA MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems recommendations are used. Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

16

Insulating Oils

TRANSFORMER DIAGNOSTIC AND CONDITION ASSESSMENT USING LIQUID INSULATION TESTING PowerTest 2013 Mel Wright, LICA Transformer Consulting

ABSTRACT Transformer diagnostics using fluid testing is a critical tool for utility maintenance of large power transformers. Unfortunately common sampling procedural errors, sampling at the wrong time, improper sample containers, collected samples undergoing numerous or large temperature changes before arriving at the lab and lax testing procedures prevent consistent and reproducible lab results. Often clients are perplexed by lab data, especially dissolved water and dissolved gases that “seesaw” up and down from test to test. These variable lab results are confusing at best and prevent accurate diagnostic trending of data. Accurate historical test data that can be trended is the foundation of fault risk assignment and condition assessments. Erroneous and expensive maintenance decision can be made or critical problems may be overlooked due to “lack of faith in the lab”.

There are 6 components of a valid and actionable condition assessment using liquid insulation testing (see Graphic 1). ●● Record and track the equipment’s operational parameters at time of sampling. ●● Proper sampling procedures; Critical do’s and don’ts. ●● Fluid Quality “FQ” tests. (Dielectric, dissolved water, IFT, etc.) ●● Furan analysis and calculation of paper strength and aging rate. ●● Dissolved Gas Analysis (DGA). ●● Proper application of DGA key gases, rates of formation, IEEE or IEC Fluid guides.

This brief presentation will address specific issues critical to valid dielectric fluid test results and discusses 6 components necessary to make valid and actionable transformer condition assessments.

THE SIX COMPONENTS OF VALID AND ACTIONABLE CONDITION ASSESSMENT A common misperception is that dissolved gas analysis (DGA) is the sole test for detecting and identifying internal issues in transformers, load tap-changers (LTCs) and other Liquid Filled Electrical Equipment (LFEE). Frequently consultants are sent a DGA lab report or large spreadsheets of DGA data and little else to evaluate the condition of transformers. The reasons for concern are numerous but some examples are minor or major changes in one or more gases or a computer generated diagnostic comment on the laboratory report. I’ve seen perfectly operating transformers show up at a transformer test and repair facility based only on a laboratory computer generated DGA condition assessments. The key to preventing this type of diagnostic error and thousands of dollars in unnecessary expense, is an understanding of the relationship of equipment operating parameters on the concentration changes of dissolve gases and dissolved water in the fluid. Hot oil holds more water, gases and other soluble components. As oil heats it expands and in units with head space, the pressure increases driving volatile gases into the oil thus increasing the concentration detectable gases in oil analysis. There is a diagnostic relationship between loading, temperatures, pressures and changes in the fluid quality, furan and DGA tests results.

Graphic 1: LICA’s six components of condition assessment.

Recording and tracking equipment’s operational parameters The observation and recording of the transformers operating parameters is a critical part of the condition assessment. The collection and comparison of loading levels, headspace pressure, oil level, cooling system status as well as the top oil, winding and ambient temperatures form the foundation of condition assessment. Abnormal temperatures, pressures or cooling system operations provide the first confirmation of normal or abnormal conditions. This information along with any external events such as power surges, tripped protection systems, abnormal loading operations provide information that will assist in validation of laboratory test data. For example a decrease in loading should be reflected in a decrease in the oil and winding temperatures, reduction in headspace pressure and a decrease in the volatile DGA gases detected

17

Insulating Oils in the oil. When the DGA results, dissolved water content and furans tests are evaluated the operating parameters and changes are used to validate any changes in the lab test results.

sulation of your transformer with high water or contaminated fluid it is extremely difficult to undo the effects. (DGA, FQ and Furans)

When a client supplies a set of DGA test data with a lab generated IEEE condition code of 3 or 4, often my first request is for the a list of the operating parameters at the time of each DGA sample taken. Often the client has never considered colleting this data and nearly as often the only time they test the fluid is after a suspected event. Unless a particular key gas is extremely elevated indicating a failure has already occurred, it can be difficult to detect or quantify conditions in time to prevent a failure. The goal of liquid insulation testing is to detect liquid and solid insulation contamination, oxidative degradation, operation errors, harmful external events or internal defects at the earliest stages. Frequently the maintenance required to prevent a major loss of equipment or production is quick and inexpensive when identified at a very early stage.

●● Test the fluid as it is being vacuum treated, filtered and pumped into a transformer. The purpose is to validate that the processor has not contaminated the fluid in some manner such as residual fluid in the system or poor quality hoses that leach contaminates into the fluid. (DGA, FQ)s

PROPER SAMPLING PROCEDURES; CRITICAL DO’S AND DON’TS

●● During the first month: DGAs at weekly intervals to detect manufacturing defects, loose contacts and many other defects that will show up at full loading during this time period.

The Sampler Sampling of dielectric fluids requires a trained person who understands the effects of sampling procedures on the sample integrity. The sampler has the largest effect on the accuracy of the representative sample and thus the reproducibility of sample results. It is the sampler who has the first set of eyes on the equipment, the environment, the operational condition of the transformer. It is the sampler that determines how to obtain a representative sample of fluid based on the equipment’s load and sampling history. It is the sampler who collects the proper amount of fluid, in a manner preventing the loss or gain of diagnostic constituents and in the proper sample container. Training is important.

Sampling Program The sample program should be a combination of time based and operational changes. One of the more frequent question is how often or when to sample and what type of sample to take. Unfortunately this has a lot of “it depends” associated with the answer. What is the class and size of the transformer? What is the loading, the type of load and is the unit critical to the business. A detailed guide is beyond the scope of this presentation but for large power transformers but in general the following is the minimum. The following suggested sampling program is for transformers that are operated at a near constant loading level. For seasonally loaded (irrigation) or highly variably loaded units that may be loaded only Monday thru Friday and on-line, No-load during the weekend, see the suggest plan that follows. Constant Load Units: ●● Test the fluid while still in the tanker. Do not process or use unless it passes all ASTM minimums standards for new dielectric grade fluids. One you contaminate the cellulose in-

●● Between 24 to 72 hours after filling and before energizing, retest to validate that the fluid meets industry standards (IEEE or IEC) for new fluid in new equipment. (DGA) ●● After the transformer has been energized at load for 24 to 72 hours, retest. The object is to detect contaminates that the circulating oil has picked up in the radiators, pumps and elsewhere in the transformer. This validates that the tank was clean, dry and free of debris. (DGA and FQ).

●● Monthly DGAs for the next 5 months, then at 9 months. ●● At 9 months perform DGA. ●● After one year of on-line operation test Furans, Inhibitors, Fluid Quality and DGA. This will validate the oil preservation system, the quality of the cellulose insulation, the fluid quality and any issue that may cause premature aging or oxidation of the fluid and insulation. If the unit has been operated at it typical loading level and frequency during this first year then this data can be used as a baseline indicator of expected annual changes and rates of gas formation. ●● After the first year: Testing frequency and types of fluid tests performed are determined by loading levels, type of load supplied, operational changes and external events that may have affected the transformer. Seasonal or highly variably loaded units: ●● Seasonally loaded like irrigation units that are loaded May to September then off-line during the winter. ○○ Take at least two (2) samples during the loaded season. For example one week after the unit reaches full loading, take FQ, DGA and Furan samples. Repeat just prior to the end of the season. These samples are used to compare rates of for diagnostic interpretation. ○○ Do not try to compare samples taken with unit off-line or very lightly loaded to the result obtained during full loading. ●● Weekly loaded units, such as a factor in operation Monday to Friday. Take samples in the middle of the work week, such as Tue, Wed. or Thurs., where the loading and oil temperatures are at constant levels. Only take and compare samples taken

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Insulating Oils during the same time period, with nearly the same loading levels and top oil temperatures. This will provide the best consistency in dissolve water and DGA results, usable in creating a valid diagnostic condition assessment.

REPRESENTATIVE SAMPLE; DEFINITION AND FLUSHING REQUIREMENT For the sample to provide the necessary diagnostic information to make timely and valid condition assessments the sample taken must have been in circulation through the core, coils and radiators of the unit. In highly loaded units this only requires flushing 500 mls (pint) of fluid from the sampling valve. For transformers that are lightly loaded or on-line no load, it can be a challenge to obtain a sample that is not “dead oil” since the fluid is only slightly circulated or not in circulation. The general guide line is to flush several liters (quarts) of fluid from the large end cap valve. Obtaining a representative sample is the key to reproducible lab results which is the foundation of valid fluid evaluation and internal fault detection. Once the sample value has been sufficiently flushed to remove “dead oil” in or near the valve a representative sample can be taken.

moisture. (See photo #1) A common error is to let the oil free fall into the container which entraps air and can cause false high dissolve water results. Fill the 1 liter (quart) glass bottle to with-in one (1) inch of the bottle neck. ●● Perform a visual examination of the sample collected before proceeding with the DGA or additional samples. Examine the sample for free water or plating out of water (looks like small silver beads on the container walls), sediment and small clear fibers suspended in the fluid. This is one of several reasons for taking the FQ sample in a glass bottle and not plastic. Plastic containers prevent this initial examination of the sample. If free water, sediment or suspended fibers are observed, re-flush the valve with twice the initial flush volume and resample in a new, clean glass bottle. Label as Re-sample and submit both samples to the lab. ●● Prepare to take the DGA sample.

PROPER SAMPLING AND COMMON SAMPLING ERRORS This session is designed to point out the critical points and common procedural errors I’ve observed laboratory or utility personal make. The typical fluid quality (FQ) errors cause increased dissolved water results and addition of particles causing decreased dielectric strength. The errors in DGA sampling cause the loss of some Hydrogen (H2) and an increase in Oxygen (O2) ppm. Methane (CH4) and Carbon Monoxide (CO) may also be reduced in the sample due to sampling errors. ●● Check head space pressure gage for positive pressure. Do not open valve if there is negative pressure which will cause air bubble to be drawn into the unit. Follow additional ASTM D923 safety procedures as well as OSHA high voltage requirements. ●● Clean the valve of dirt, oil or rust. Do not use solvents to clean the valve. ●● Flush the appropriate amount of flush fluid from the large end cap, not from the small sampling port. High volume flushing is required to remove all the dead oil from the valve. Flushing from the small sample port cannot achieve the desired flow rate necessary for complete flushing. This is especially important for lightly loaded, large transformers. ●● Attach 1/4 inch I.D. PVC tubing to the sampling port with sufficient length to reach the bottom of the glass (preferred sample material) sample container. It is important for the tubing to touch the bottom of the container to prevent splashing which entraps atmospheric air in the sample with associated

Photo 1: Tubing reaches bottom of sample container to prevent splashing.

DGA SAMPLING ●● Never re-use tubing between different transformers and especially between LTCs and transformers due to the risk of acetylene (C2H2) carry over. ●● To quickly obtain a bubble free sample, disassemble the syringe, start a flow of oil from the tubing, wet the syringe plunger and the inside of the syringe barrel with oil, reassemble and then connect the tubing to the top port of the 30way stopcock on the syringe. (See Photo 2) The oil creates a seal between the barrel and plunger, preventing small air bubbles from being drawn into the sample when filling. ●● Connect a waste tube to the side port of the 3-say stopcock, orient the syringe vertically with the stop cock up, and open the valve to the appropriate position to fill. DO NOT PULL on the plunger. The pressure of the oil will push the plunger, filling the syringe. (See Photo 3). If pin head size bubbles are

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Insulating Oils observed, expel out of the waste (side) port. If a bubble larger than a marble is observed, expel all oil and refill. ●● After filling the syringe, check the stop cock making sure it is in the closed position and the luer fitting is tight before placing in the shipping box. ●● Correctly and completely fill out the data sheets making sure you have collected all of the equipment operating parameters. (Loading %, Temps, Pressure, etc.)

Photo 2: Disassemble and coat with oil.

Photo 3: Hold vertical while filling syringe.

FLUID QUALITY “FQ” TESTS Fluid quality test are a set of tests that confirm that the fluid is capable of performing its primary function (heat transfer and insulate), if the fluid is new or aged/oxidized and several physical tests to identify the type of fluid. The fluid quality tests are often broken down into 3 categories.

FURANS, DEGREE OF POLYMERIZATION “DP” OF PAPER Chendong in the early 1960’s discovered a relationship between Kraft paper (55̊ᵒC rise paper) cellulose degradation, furan production and concentration in mineral oil. Paper is composed of millions of long polymers of glucose molecules called cellulose. The longer the cellulose, measured in degree of polymerization (DP), the greater the mechanical strength of the paper. As paper degrades due to high heat and high moisture causing breakage of cellulose bonds, with each bond cleavage a furan molecule is formed. Chendong’s challenge was to find a non-invasive method to evaluate the mechanical strength (Degree of Polymerization) of winding insulation using the formation of furans. His research lead to the use of Furans in oil concentration, specifically 2FAL, as an excellent tool in the diagnostic evaluation of Kraft (55C rise) paper (his original formula) and TUK (65C rise) paper using the modified Chendong equation. In addition he developed a formula for estimating the “Apparent Age” of the cellulose based on the calculated DP from the 2FAl concentration. I’ve found that the two formulas, calculated DP of the TUK and the Apparent Age of the cellulose are invaluable in identifying abnormal loading levels or the effects of harmonics on the life of the cellulose. Comparing the ratio of Apparent Age to the actual “On-line with normal loading” or Chronological age of the transformer provides a valid tool in identifying abnormal heating of the windings. (See Chart 1: Apparent Age verse On-Line Age). Comparison of the over-all degradation of the cellulose insulation using furans to the formation of DGA detected Carbon Monoxide (CO) due to localized burning/charring of cellulose is an important diagnostic tool to discriminate the type, cause and location of cellulose degradation.

●● Critical tests: Dielectric, water, visual. ●● Oxidation (ageing) tests: Neutralization number (acid), color (ASTM scale) and interfacial surface tension (IFT), oxidation inhibitors. ●● Physical tests: Specific gravity, viscosity, refractive index, pour point. Hot oil coupled with excess oxygen (O2) and or water (H2O) content will oxidize (age) faster than oil at the same temperature having low O2 and H2O levels. Oxidized components formed in the oil are detected by a combination of the three oxidative test listed above. They also attack the cellulose winding insulation causing paper degradation (see Furans). Oil that is over heated with excess oxygen increases in color while some of the oxidized products are acidic (increasing neutralization number) and chemically polar (decrease in IFT). Thus the three tests: Color, acid, IFT have a unique relationship in determining the oxidative state of mineral oil. As oxidative degradation increases the color and neutralization number increase while the IFT decreases.

DISSOLVED GAS ANALYSIS (DGA) The identification, detection and quantitation of gases produced from various liquid insulating fluids at specific heat energies is the single most important diagnostic tool in all liquid filled

20 electrical equipment (LFEE). From the introduction of oils as a cooling medium in transformers the production of gases was known to be of diagnostic value. The introduction of Gas Chromatography in the identification and quantitation of gases in the early 1960’s has transformed the detection of transformer faults and condition assessments. The understanding of the key gases formed at specific temperatures and the ratios of key gases formed by specific fault types has provide a means of identifying incipient faults before failure. Coupled with a detailed understanding of the construction and loading operations of a transformers allows DGA experts to evaluate not only internal defects, operational errors and some external faults but to assign a degree of risk suspected fault. Some examples are the generic rates of formation and individual gas concentrations found in IEEE C57.104, IEC guides and other risk assessments tools. One of the most accurate DGA risk assessment tool is the “Factor 10” rate of formation calculation and risk table. The formula was created by GE Pittsfield Large Power Transformer lab in the early 70’s as a go/no-go factory heat run tests. The GE Denver Liquid Insulation Laboratory created a six level risk assessment table which proved to be highly accurate in classifying transformer failure risks and action plans. IEEE published the formula in the 1991 revision of C57.104. (See formula below) and modified it to use liters in the 2008 revision. IEEE C57.104, Table 3 guide is the accepted guide in North America for action plans based on an idealized 10,000 gallon transformer. I’m presenting the “Factor 10” risk assessment guide lines for discussion and hopefully many of you will try it out for a few years to see how it works for you. (See the power point presentation for the risk assessment guide.) The key to the success of the GE formula and the “Factor 10” Risk Assessment guide is the inclusion of a correction factor for the volume of fluid in the transformer. This method is far superior that the “normalization” of gases in real transformers to the idealized 10,000 tank that had been used for a number of years. For discussion, let’s compare two transformers, one with 10,000 gallons of oil and the other with 1,000 gallons of oil. If each had the same fault, with the same surface area, time of fault and same heat generated, then the formation of gases will be identical in each transformer. However the gases will be dissolved in different volumes of oil. The difference between the two units is a factor of 10 and thus the concentration in ppm of gases will be 10 times greater in the 1,000 gallon unit than in the 10,000 gallon unit. The rates of formation of TDCG will follow this ratio. The IEEE Table 3 guide does not provide a means to adjust the condition codes or action plans to a real transformer. The “Factor 10” formula adjusts for the volume allowing the risk and action plans to adjust to any size or class of transformer. “Factor 10” Rate of formation formula: Rate of TDCG = [(TDCG2 – TDCG1) (V) (10-6)] / [(7.5) (number of days between tests)]

Insulating Oils - Rate = Cubic feet of combustible gases per day. - TDCG1 = TDCG in ppm on first test date. - TDCG2 = TDCG in ppm on second test date. - V = volume of oil (Gal): (1 liter = 0.26417 US gallons, 3.78541 liters = 1 US Gallon)

PROPER USE OF DIAGNOSTIC TOOLS, GUIDES AND TRANSFORMER OPERATIONAL PARAMETERS TO CREATE A VALID AND ACTIONABLE CONDITION ASSESSMENT An expert in transformer diagnostics and condition assessment can use the 6 components as follows: ●● Key Gas or Duval’s Triangle diagnostic tool to identify the type of fault. ●● Use of the “Factor 10” risk guide (based on the GE formula) to assign a valid risk assessment to the fault. ●● Comparing changes in lab results over time with changes in equipment’s operational parameters (temps and loading data collected at the time of sampling). ●● A useful tool to validate the lab’s test results and the quality of the sample taken. ●● Evaluating cellulose using furans. ●● Using fluid quality (FQ) results to cross check for causative agents or associated changes in the fluid or cellulose. When the 6 steps are performed with each transformer sampling creating a valid and actionable condition assessment is a very logical process. Mel Wright has over thirty years of experience as an expert in transformer diagnostics using liquid insulation analysis. Mel designed, equipped, and managed the General Electric Energy Services transformer oil laboratory in Denver, CO from 1980 to 2008. The Denver LIL performed DGA, Furans, PCBs and fluid quality tests for all GE facilities in North and South America. Mel was the GE expert resource for GE transformer engineers, field service technicians, customers, and utilities regarding transformer condition assessment, fluid evaluation and fault identification. In addition to managing the laboratory, Mel was the GE Polychlorinated Biphenyls (PCB) testing, management, DOT shipping, and EPA Commercial PCB facility manager in Denver as well as the environmental, health, and safety coordinator and the manager of Hazardous Materials and Hazardous Waste for the Denver facility.

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EXAMINATION OF TRANSFORMER OIL MOISTURE MEASUREMENTS NETA World, Fall 2014 Issue Don Genutis, No-Outage Electrical Testing, Inc.

Moisture can be one of the most damaging factors to transformer insulation and one of the more difficult factors to understand. Excessive moisture will cause transformer insulation to degrade at a much faster rate than normal, and this degradation process can generate additional moisture which will increase the degradation process even more. Some studies indicate that doubling paper insulation moisture content will result in reducing transformer life in half; therefore, it is important to know the insulation moisture content of the paper in order to maintain transformer reliability.

Even though the dryness of the paper cannot be measured directly with an oil sample test, it can be determined indirectly by calculating the percent saturation of the oil using the ASTM D1533 moisture-in-oil test results along with the transformer temperature to provide a better indication of insulation dryness. Percent saturation can be determined by using a nomograph such as the one shown in Figure 1. Percent saturation guidelines shown in Figure 2 show that levels greater than 30 percent indicate an extremely wet transformer that should probably be dried out.

Moisture migrates from the oil into the winding paper insulation based upon the temperature of the transformer which is largely influenced by transformer loading. At 20°C, the paper contains about 3,000 times the amount of moisture that the oil does and at 60°C, the paper contains only 300 times the amount of moisture that the oil does. This is because the higher temperatures drive the moisture out of the paper and into the oil. Therefore, the ASTM D1533 Standard Test Method for Water in Insulating Liquids by Coulometric Karl Fischer Titration test is not necessarily a good indication of the dryness of the transformer.

Fig. 2: IEC Guide for Insulation Condition Based on Percent Saturation Present guidelines also state that acceptable moisture levels for in-service mineral oil transformers operating at voltages less than 69 kV is 35 ppm. Looking at the nomograph of Figure 1, one can see that a transformer with 30 ppm (acceptable moisture-in-oil level) and operating at 20°C has a percent saturation level of over 50 percent which is extremely wet. Therefore, we should not rely solely on the moisture-in-oil test but should instead look closer at the percent saturation in order to estimate transformer dryness. Trending or continuous monitoring of moisture in oil along with temperature parameters can of course provide even more accurate percent saturation results as compared to a one time test since transformer loading operation and atmospheric temperatures can vary significantly over time. The following case study illustrates the importance of considering percent saturation results when evaluating transformer condition. Fig. 1: Nomograph for Determining Percent Saturation

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Table 1: Transformer Test Results Displaying Percent Saturation Correlation with Missing Bushings

In this particular case, a client had 19 pad-mount transformers in an outdoor storage yard for a few years. All transformers were pad mount compartmental type, 4,800 V delta primary and either 480/277Y or 208/120Y secondary. All transformers contained approximately 100-300 gallons of mineral oil. Over time, 10 of the transformers were vandalized by copper thieves that removed many of the low voltage bushings which left large openings and allowed the mineral oil to be exposed to atmosphere. Although the overall climate condition at this location is relatively dry, wet weather periods allowed ample moisture entrance into the oil. Since the transformers were not in service, they were not warm and the winding paper insulation absorbed much of the moisture. After careful oil sampling was completed and the samples tested, it can be seen from Table 1 that in all 19 cases the moisture in oil results were acceptable (< 35 ppm). Nine of the first 10 transformers on the list, which were relatively well-sealed, exhibited relatively low percent saturation values. Whereas, of the nine poorly sealed transformers, eight exhibited high saturation values which is indicative of a wet transformer. Based on this data, percent saturation calculations correlate much better with expectations than the moisture results. Although the moisture in oil test results are valuable since this information is used to calculate percent saturation, the percent saturation values are a much better indication of wet windings and, therefore, a much better indication of transformer condition.

Don A. Genutis holds a Bachelor of Science degree in Electrical Engineering and has been a NETA Certified Technician for more than 15 years. He has held various principal positions during his 30-year career in the electrical testing fieldand has primarily focused on advancing no-outage-testing techniques for the last 15 years. Don presently serves as President of Halco Testing Services in Los Angeles, California.

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TRANSFORMER MAINTENANCE: THE OVERLOOKED ITEMS NETA World, Winter 2015 Issue Rick Youngblood, Doble Engineering Company

In my 35 years of involvement with substation transformer maintenance, I have witnessed widely varying perspectives on what maintenance should include. Too often, it is limited to nothing more than inspections. The techs involved might look at the top oil and hot spot indicators, observe the nitrogen pressure or conservator levels, check for leaks — and maybe, if they are thorough — log the load tap changer (LTC) counter. Most technicians comment that the transformer is electrically tested every three to six years by performing the standard regiment of power factor, TTR, excitation, and winding resistance tests; but the majorities are completely unaware of what I call the “overlooked items.” Ignoring the items below can seriously compromise the overall reliability of the transformer.

FAILURE MODES To properly perform transformer maintenance, it is important to identify all, not just some, of the possible failure modes: Electrical, Mechanical, and Dielectric. These can further be broken down into internal tank and external tank. This article highlights the often-overlooked external failure modes rather than the typical internal modes identified in most maintenance programs.

While they are a virtual short circuit at the moment they are energized, that quickly changes as they approach normal operating speed. The twisting force or torque is dependent on the strength of the magnetic flux formed between the stator or stationary winding as compared to the rotating winding or rotor. The rotor then has a shaft connected to the load extending from the middle of the rotor. The flux requirement and the current required to produce it are determined by the load on the shaft. Although polyphase motors do not require any help to rotate, single-phase motors (Figure 1) can require three additional parts to begin rotation: (1) the start winding, (2) a centrifugal switch, as in Figure 2, used to disconnect the start winding when the motor reaches approximately 85% of rated speed, and (3) a starting capacitor, as shown in Figure 3. When a motor is first energized, the current drawn is equivalent to the stalled current and is large enough to quickly overheat the winding. This heat, if it persists, will destroy the winding insulation and eventually the motor. The current reduces rapidly as the motor picks up speed and develops a counter EMF to oppose the source; ac induction motors behave as transformers with a shorted secondary until the rotor begins to move.

EXTERIOR MAINTENANCE Exterior maintenance centers on the LTC drive mechanism, cooling fans, pumps, controls, and gauges. The heart of the LTC drive system is a motor. Some are threephase, but most are typically single-phase fractional horsepower, and they have many failure modes, which can result in LTC failure. While most of us think we understand motors, do we really? Motors are rotating and repelling electromagnets that require current to produce the electromagnetic flux that generates the twisting force known as torque and voltage to push that current. They are very proportional; if the voltage drops, the current will climb, and if the voltage climbs, the current drops. Motors are obedient in the sense that under some circumstances, they will destroy themselves trying to rotate the load by drawing the current they need to generate the torque required to rotate, if not protected by a current limiter such as a fuse or breaker. Their internal impedances are variable.

Fig. 1: Single-Phase Motor

Fig. 2: Centrifugal Switch

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Insulating Oils

Fig. 5: Externally Mounted Start-Up Caps

Fig. 3: Starting Capacitor

Bearing wear, improper lubrication, or rust in jack shafts, sprockets, gears chains, and levers all increase the torque requirements and the measured current (Figures 6 and 7).

COMMON MOTOR PROBLEMS (LTC FANS AND PUMPS) The most common motor problems are related to improperly applied voltage and current. As connections get old and loosen due to thermal cycling, corrosion, and poor crimping, their resistance increases and results in voltage drop. It is easy to determine if this occurs by measuring the voltage before startup and while running at full speed using a good voltmeter. If the voltage drops by more than 10%, one of the previously mentioned conditions exists. Slow start-up can be caused by excessive load or bad start capacitors (Figures 4 and 5). The capacitance of the latter can be measured with any number of good capacitance measurement meters. If the capacitance has changed more than 5% from the tolerance printed on the can, or 10% from the rated value, it should be changed. Because ac capacitors are not polarity sensitive like dc capacitors, the two types cannot be interchanged. If the capacitor is satisfactory, mechanical issues are the next areas to investigate.

Fig. 6: Rusty Chains Due to Leaking Explosion Diaphragm and Lid Gaskets

Fig. 7: Frozen Universal Joint Due to Aged and Broken Rubber Joint Cover Any mechanical or electrical problem that slows the operation of the LTC causes extended transition times, and ultimately, failure in the selector, transfer, and reversing switch contacts. While it might be assumed that the failure is due to bad contacts, the original problem could actually be in the drive motor and mechanism.

Fig. 4: Capacitor Located Under the Cover

Other LTC failure modes are directly attributed to poor maintenance in the controls of the LTC. The contacts must not only move in a timely fashion, but also must stop with precision directly on their stationary mates. The moveable contact can’t stop short, nor can it coast past the proper position. Therefore, one of the following must be employed: ●● Mechanical braking using drums or bands ●● Dynamic braking where the motor is short circuited momentarily ●● Plugging where the motor is electrically reversed to stop its forward motion

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Insulating Oils All are required to occur exactly on step, in time, every time. The cam and position switches, which control these functions, need maintenance and lubrication on a regular basis as well. Lastly, the LTC must recognize when it has reached the last step and protect the motor from trying to rotate past the mechanical stops. Step 17 on a 16-step changer is not good (Figure 8)! Fig. 8: End of stroke stops are mechanical stops to prevent the LTC contacts from moving past the last step End of stroke limit switches are used to electrically disengage the motor drive when step 16 is reached

Threaded bar step positioner requires regular lubrication

Mechanical brakes require adjustment to ensure the brake releases when the operating solenoid is engaged to let the motor rotate but must re-engage exactly at the correct spot required to position the contacts. Brake bands wear over time and need adjustment or replacement (Figure 9). Fig. 9: Brake release solenoid is electrically energized to release the brake, but when de-energized, uses a spring to reapply the brake. Timing is critical. Brake bands use friction to stop the LTC motor in the correct position and must be adjusted periodically.

In closing this section on LTC mechanisms, a failure example is illustrated in Figure 10. Although the failure is located in the LTC tank, the cause is lack of maintenance in the control section, possibly due to binding, low torque, low voltage, high current, bad starting capacitor, etc. Good maintenance procedures should include servicing these parts on a regular basis, which can prevent failures in the LTC tank.

Fig. 10: Damaged Moveable Contact Due to Malfunctioning Brake Circuit in the Motor Control

ELECTRICAL CONTROLS Electrical maintenance is normally only thought of as the in-depth testing of the core and coils, such as power factor, TTR, excitation, winding, and resistance, etc. Seldom are the external controls for the pumps and fans tested to see if they function properly, much less checking calibration for accuracy. It is widely accepted that a continuous increase of 8°C to 10°C above rated temperature can reduce operating life by 50%. Therefore, it is very important that the cooling system on a transformer works as designed to turn on the fans and pumps before the oil temperature reaches the rated upper limit. Top oil and hot spot gauges need calibration using a calibrating oven to see if the needle tracks the actual oil temperature or drifts as the temperature increases (Figure 11). It’s not uncommon for the error in reading to change as the temperature increases. Adding or subtracting a fixed amount to the actual reading compensates for a linear change. A non-linear change requires a replacement

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Insulating Oils

of the temperature gauge. Additionally, determine if the switch set points close at the desired temperature and can be adjusted up or down to compensate for gauge errors. The final check is to see if the electrical switch actually changes state when the set points are reached (Figure 12).

amounts of brass and cast iron in the transformer. These filings will be distributed everywhere, including the windings, eventually causing winding failure (Figure 13).

Fig. 13: Thrust Washer Failure Modes Fig. 11: Transformer Temperature Gauge with Electrical Set Points to Bring Pumps and Fans On- Line In a situation where the fans turn on late by 10 degrees, the windings can be continually subjected to temperatures past their design limit, thereby reducing insulation life. If the transformer is set to trip on high temperature, a bad gauge can trip the unit for no actual reason below the desired temperature, causing collateral damages or an unplanned outage. Fig. 14: Visual Representations of Bearing Wear Using Ultrasonics

Fig. 12: Capillary Tube Temperature Well Calibration Oven

MECHANICAL PROBLEMS Pump problems have negative consequences as well. If a pump starts at a higher temperature than planned, it may be difficult to return the transformer to the desired temperature during hot weather or when the load is above normal. A pump that fails to start leads to insulation degradation. If a pump fails completely, the transformer may fail in a very short period of time. Most transformers have an operational capability less than the OA rating with no pumps running and can overheat with minimum load. Pump failures can be mechanical as well as electrical. Pump motors use a spacer called a thrust washer to center the impeller in the cast iron housing to prevent drag. As a pump ages, the thrust washer wears and eventually permits the impeller to drag on the housing, depositing large

Fig. 15: Use of Ultrasonic Detector to Determine Bearing Wear in Pumps and Fans Using an ultrasonic detection device (Figure 14) can quickly identify a number of failure modes, such as gas leaks, partial discharge, vacuum leaks, and mechanical wear (Figure 15), by converting vibration into audible sound the inspector can hear and record in his head set. Fan failure is common in a majority of companies. In the case of forever-sealed bearings, little maintenance is required other than keeping them clean and unobstructed. Fans are designed for free, unrestricted airflow that loads the motor to a specific torque

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Insulating Oils and current draw. When the fan bearings become dry or the blades obstructed, the current rises to compensate for the increased torque requirements, resulting in overheating and shortened motor life. Simple maintenance such as adding grease to bearings, removing debris from the blade guards, and checking the start capacitor all add many years to the life of the fan and transformer (Figures 16 and 17).

Considering many problems are slow to evolve, taking OQ samples yearly provides adequate protection. But in the case of problems typically caught by DGA, take oil samples from the main tank and LTCs more often. It is recommended to pull DGA samples twice a year due to the speed at which an LTC or winding problem can progress. The cost per sample is marginal compared to a transformer or even just an LTC failure and can be cost justified with one LTC save.

CONCLUSION As explained, what constitutes correct transformer maintenance is not always clear. To provide 100% equipment protection, it is important that technicians and maintenance engineers are aware of all failure modes on each specific equipment type. Suitable tests and service procedures, and the appropriate intervals between them, can then be developed. Once a comprehensive plan is devised to address all three failure modes — electrical, mechanical, and dielectric — the next important step is to implement it. Fig. 16: Bird nests play a primary role in fan failure and overheating of transformers.

Fig. 17: Fan failures due to debris also contribute to transformer overheating.

DIELECTRIC QUALITY The final category of overlooked items involves rigorous and regular oil quality testing. Oil testing falls into two basic categories: dissolved gas analysis (DGA) and oil quality testing (OQ). DGA is used to look for health issues, ranging from basic overheating to partial discharge and internal arcing. By understanding the differences in how gas is generated, it can be determined if the internal problem is serious or can be controlled by load. The results can also point to what electrical tests to perform if the problem proves to be more than operating issues. Typically, OQ screens are ordered in groups of five, seven, or eight separate tests that include dielectric strength, moisture, interfacial tension, acidity, power factor, and color. Other more stringent tests include furanic compounds to determine the remaining life of the insulation, and power factor at 100˚C to look for polar contaminants closer to the true operating temperature of the equipment under test.

Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

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Insulating Oils

WORKING SAFELY WITH POWER TRANSFORMERS IN THE UTILITY SECTOR NETA World, Winter 2015 Issue Ray Curry, American Transmission Company

Here’s a reflection on power transformers/accessory equipment, installation work methods, rigging/moving, and safety practices from the 1970s to today. When examining America’s electrical grid, power transformers are a key component. They are required for generator step-up (GSU), transmission, and distribution duty. In many locations, the Internet Age has caused a large increase in power demand. The bulk of the grid load is handled by aging power transformers, most of which were built in the 1970s and 1980s, with a few even older. These transformers were expected to have a 30- to 35-year life, but many are beyond 45 years. While many utilities are adding new transformers, the planning, purchase, and installation time is very long. Planning can be as long as five to seven years with the actual purchase taking 12 to 18 months. Installation for most transformers will take as long as three weeks. The fact is that everything is speeding up with no end in sight, and many changes and improvements concern power transformers as well. To list a few: ●● Better designs for longer life cycle ●● OEM components manufactured with ISO 9000 standards ●● Better nondestructive testing ●● Insulation materials suited for higher voltages and thermal stresses ●● Improved installation and oil processing/handling ●● Enhanced shipping and GPS tracking Workforce skills and equipment are also improving. The major part of any transformer installation involves moving a large, heavy piece of equipment that can be badly damaged by rough handling. To meet today’s utility specifications, many rigging and heavy hauling companies have invested in the best equipment as well as a skilled, trained workforce versed in an established safety program with a proven track record. Many of the larger transformers that need to be shipped a great distance (250MVA up to 800MVA) must be shipped by rail. With very few substations having a rail siding, a transfer vehicle is required to move the transformer from the rail siding to the transformer pad within the electrical substation. From the 1970s to now, these drayage vehicles have been re-engineered to be more

versatile with hydraulic systems to raise, lower, or level the working platform. Each vehicle has 16 axles that can be steered independently of one another. Self-propelled vehicles are a great advantage over older equipment, which required a tractor. In many older substations, space surrounding a large transformer can be very restrictive. Newer cranes are equipped with digital readers, giving the operator real-time, out-of-limits alarms for different parts of the crane, such as boom loading and outrigger position. For many years, utilities have been associated with having strong safety programs. Today, more and more utilities require all contractors to have a positive safety program and a strong compliance record with OSHA regulations. Qualified Crane Operators are now the norm. The use of fire-resistant clothing is now required by most utilities, along with consistent use of PPE. In the 1970s and 1980s, this would not have been the case with many rigging and hauling contractors. Today, the movement of the transformer, whether by rail or truck, is tracked using a real-time GPS device. The most popular device is a Lat-Lon, which uses a self-contained battery pack. This device records all movement in the X, Y, and Z axis with adjustable alarm levels. An important added feature with this device is its ability to record the main transformer tank pressure. Most transformers are shipped with two to three pounds of certified dry air in the main tank. The premature loss of this air pressure will cause, in most cases, additional vacuum/oil process time. From the 1960s through the 1980s, a mechanical clock recorded all impacts to the transformer during shipping. This impact recorder used paper on a roll to make the recordings. When the shipped load reached a destination, the paper roll was analyzed for any impacts. Compared to where the technology is now with real-time GPS, the old instrumentation was very unreliable and often failed to provide accurate data. The only backup to this was to check the core ground of the transformer and compare to the factory test measurement before shipping. Today, there is an additional test called Sweep Frequency Response Analysis (SFRA), which will be covered in the next article in this series. A valuable aid for today’s commissioning engineer planning a large transformer move is the ability to hire a logistics management firm. Now, contractors will arrange all the services and order a special rail car. The agent will also take care of interaction with

Insulating Oils railroad agents, schedule a heavy hauling company, and file all state and local permits to accomplish a safe and coordinated move. Along with the permits, an over-the-highway move may require a state patrol inspection of the load and on-road escort, all of which is taken care of by the logistics company. Now that the transformer is in the substation and on the pad, the next article in this series will cover assembly, vacuum/oil processing, testing, and placing the transformer in service. This article will also address Maintenance Zero Steps and the use of Behavior Based Safety Observation (BBSO). Ray Curry graduated from Penn State University in 1969. He joined Westinghouse Electric in the East Pittsburgh Division and the PCB Division at Trafford, Pennsylvania. In 1977, Ray relocated with Westinghouse to St. Louis, Missouri, working in the E&ISD Division as a Field Service Engineer specializing in high-voltage switchgear and construction/commissioning power substations. After retiring from Westinghouse in 1994, Ray managed two Municipal Electrical Systems for the cities of Chanute and Garden City, Kansas, from 1994-2000. From 2007 to the present, Ray has been a Commissioning Engineer with American Transmission Company, building and maintaining over 500 69kV138kV to 345kV electrical substations, including more than 200 power transformers within the ATC Service Footprint. He sits on ATC’s Safety Committee and has maintained an active affiliation with NETA for six years.

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Insulating Oils

TRANSFORMER INSULATION DEGRADATION NETA World, Winter 2015 Issue Lynn Hamrick, Shermco Industries

Hartford Steam Boiler Insurance Company has been collecting information on transformer failures for years and periodically issues reports on the causes of such failures. Table 1 represents a compilation of those study results for 1975, 1983, and 1998. Note that “Deterioration of Insulation” was the second most frequent cause of transformer failure in 1998. This article will focus on internal failures of transformers, with a focus on the chemical processes that can cause insulation deterioration as well as how overloading and moisture accelerate the degradation process. Cause of Failure

1975

1983

1998

Line Surges/External Short Circuit 

13.6%

18.6%

21.5%

Deterioration of Insulation

10.4%

8.7%

13.0%

Lightning Surges

32.3%

30.2%

12.4%

Inadequate Maintenance

6.6%

13.1%

11.3%

Moisture

7.2%

6.9%

6.3%

Loose Connection

2.1%

2.0%

6.0%

Poor Workmanship — Manufacturer     

10.6%

7.2%

2.9%

Overloading

7.7%

3.2%

2.4%

Sabotage, Malicious Mischief

2.6%

1.7%

0.0%

All Others

6.9%

8.4%

24.2%

*Results of Hartford Steam Boiler Insurance Company studies on the causes of transformer failures.

Table 1: Causes of Transformer Failures* Basically, insulation within a transformer consists of cellulose (or paper) and insulating oil. A large amount of research has looked at the factors that affect cellulose and mineral oil. Cellulose ages and degrades through three basic chemical processes: oxidation, acid-hydrolysis, and pyrolysis. These processes are caused by the presence of oxygen, the presence of water, and operating at elevated temperatures. The result is a weakening of the cellulose’s mechanical and electrical integrity, as well as sludging and contamination of the insulating oil.

OXIDATION Oxidation is defined as the interaction between oxygen molecules and all the different substances they may contact. Technically, oxidation is the loss of at least one electron when two or more substances interact. Those substances may or may not include oxygen. (Incidentally, the opposite of oxidation is reduction — the

addition of at least one electron when substances come into contact with each other.) In a transformer, oil and paper degrade as a result of oxidation. The most common insulating liquid used in transformers is mineral oil. Some transformer oils, referred to as uninhibited oils, possess a degree of natural protection against oxidation. However, mineral oil, which is known as inhibited oil, requires the addition of an antioxidant to protect against oxidation. For mineral oil, aging and oxidation are synonymous. The aging process begins slowly, as the antioxidants work to neutralize the harmful peroxides and radicals as they are formed. However, with time, the antioxidants decrease in quantity and the aging process increases exponentially. This leads to the formation of acids, aldehydes, ketones, esters, and eventually sludge (a mixture of long insoluble hydrocarbon molecules and particles). The process occurs in the presence of peroxides (unstable oxygen compounds) and free radicals and is accelerated by catalysts such as water and copper. If allowed to continue, oxidized oil will continue to deteriorate and will transport contamination to the cellulose insulation within the transformer. Here the effects are much more serious. Transformer oil can be changed; unfortunately, cellulose cannot be changed. If the oil is not maintained, the condition of the cellulose will deteriorate to the point where the transformer has reached the end of its working life. Cellulose degrades (oxidizes) much faster than oil because it contains oxygen within its molecular structure. The degradation process generates water, carbon dioxide, and furfurals, and is accelerated by external sources of oxygen, high temperature, and high levels of oil acidity. The water that is generated combines with dissolved moisture in the oil to further accelerate the degradation process. The end result is broken molecular chains, a lower degree of polymerization (DP), and loss of mechanical strength. In the absence of oxygen, decomposition occurs more slowly through the process of pyrolysis.

ACID-HYDROLYSIS Acid-hydrolysis is the breakdown of the cellulose using H+ ions in water as a reactant. In hydrolysis, a larger molecule, like molecules of cellulose, is broken down into simpler substances by the addition of water molecules. When this process is carried out in the presence

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Insulating Oils of a small amount of acid, like that produced through the oxidation process, it is called acid-hydrolysis. The acid acts as a catalyst by providing H+ ions to facilitate the cellulose’s intake of water (H2O) molecules. To give an idea of the effects of water in the cellulose, it has been suggested that if the moisture content in cellulose doubles, transformer life expectancy is immediately halved.

PYROLYSIS Pyrolysis is the breakdown of the cellulose at elevated temperatures. Simply stated, the higher the temperature the cellulose operates in, the faster the cellulose will degrade. Operating temperature increases can be the result of operating in overloaded conditions, some type of failure or limitation in the transformer cooling process, or elevated ambient temperature. Any of these situations can result in elevated temperatures of cellulose. It has been suggested that a thermal increase of just 10o C will lead to cellulose lifetime being cut by over 50%. The best way to combat each of these degrading processes is to monitor transformer health by establishing a transformer maintenance routine and performing periodic oil analysis.

TRANSFORMER MAINTENANCE The following should be monitored as part of regular transformer maintenance: ●● Physical and mechanical condition. This should include an evaluation of the paint condition and cleanliness of the outside of transformer compartments and radiator cooling fins. Look at the LTC counter log and record the value. This inspection should also include a determination that no hindrance exists in getting air to the radiator cooling fins. Any suspected problem that could result in an oil leak or reduced system cooling should be recorded and brought to the attention of management for corrective action. ●● Oil leaks and spills. Oil seepage from within the transformer typically appears as a discoloration of the painted surface around a bushing or penetration. All suspected oil leaks should be recorded and brought to the attention of management for corrective action. ●● Correct operation of cooling fans, if applicable. Transformer cooling fans are typically controlled with thermostats, turning on and off based on a temperature setting. If the fans are not running, it should be noted with the as-found thermostat settings recorded. The system should then be exercised by adjusting the thermostat settings to cause the system to operate. With subsequent operation, the thermostat settings should be returned to the original settings with the as-left settings recorded. If the system does not operate, this condition should be recorded and brought to the attention of management for a repair of the system.

MONITOR TRANSFORMER INDICATORS Examination of these indicators is also part of transformer maintenance: ●● Transformer temperature. For an OA 55/65 Class Transo former, operating temperature limits of the windings are 55 o o o C or 65 C (131 F or 149 F, respectively), dependent on the kVA ratings of the transformer. Determine if the sensor is for top oil or winding temperature. It should be noted that the top oil temperature is probably lower than the winding temperature. Also, note the high temperature indicator and reset with each inspection. ●● Transformer pressure. This measures the pressure of the nitrogen blanket above the oil. The gauge usually indicates negative and positive pressure. The pressure can vary from slightly negative to slightly positive due to ambient temperature and operating conditions. For sealed transformers, the pressure should always be maintained at a slightly positive pressure. This is indicative of a proper seal and also ensures that moisture from the air does not leak into the nitrogen-filled gap at the top of the transformer. ●● Transformer oil level. There is usually a mark on the gauge that indicates the 25° C level, which is the proper oil level for the transformer at that temperature. Maintaining the proper oil level is extremely important because if the oil level falls below the level of the radiator inlet, natural circulating flow through the radiator will cease and the transformer will overheat.

PERIODIC TRANSFORMER OIL ANALYSIS The insulation system is typically evaluated by performing the following oil sample tests: ●● Dielectric breakdown voltage. The dielectric breakdown voltage is a measurement of electrical stress that an insulating oil can withstand without failure. It is measured by applying a voltage between two electrodes under prescribed conditions under the oil. The dielectric test measures the voltage at which the oil breaks down, which is indicative of the amount of contaminant (usually moisture) in the oil. ●● Moisture content. Oil moisture is measured in parts per million (ppm), using the weight of moisture divided by the weight of oil. Water can be present in oil in a dissolved form, as tiny droplets mixed with the oil (emulsion), or in a free state at the bottom of the tank holding the oil. Demulsification occurs when the tiny droplets unite to form larger drops, which sink to the bottom and form free water. When the moisture in oil exceeds the saturation value, there will also be free water precipitated from the oil in suspension or drops. ●● Power factor. The power factor of insulating oil equals the cosine of the phase angle between an ac voltage applied and the resulting current. Power factor indicates the dielectric

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Insulating Oils loss of the insulating oil, and thus, its dielectric heating. The power-factor test is widely used as an acceptance and preventive maintenance test for insulating oil. A high power factor in service-aged oil indicates deterioration, contamination, or both, with moisture, carbon, or deterioration products.

●● Interfacial tension. The interfacial tension (IFT) test is employed as an indication of the sludging characteristics of power transformer insulating oil. It is a test of IFT of water against oil, which differs from surface tension in that the surface of the water is in contact with oil instead of air. The attraction between the water molecules at the interface is influenced by the presence of polar molecules in the oil in such a way that the presence of more polar compounds causes lower IFT. The test measures the concentration of polar molecules in suspension and in solution in the oil, giving an accurate measurement of dissolved sludge precursors in the oil long before any sludge is precipitated. ●● Acid neutralization number. The acid neutralization number, or acid number, is the amount of potassium hydroxide (KOH in mg) required to neutralize the acid in one gram of oil. It is indicative of the acid content in the oil. With service-aged oils, it is also indicative of the presence of contaminants, like sludge. The acidity test alone determines conditions under which sludge may form but does not necessarily indicate that actual sludging conditions exist. New transformer oils contain practically no acids. The acidity test measures the content of acids formed by oxidation. The oxidation products polymerize to form sludge, which then precipitate out. Acids react with metals on the surfaces inside the tank and form metallic soaps, another form of sludge. ●● Color. The color of an insulating oil is determined by means of transmitted light and is expressed by a numerical value based on comparison with a series of color standards. It is recognized that color by itself could be misleading in evaluating oils for service quality. The primary significance of color is to observe a change or darkening of the oil from previous samples of oil from the same transformer. Noticeable darkening in short periods of time indicates either contamination or that arcing is taking place. A darkening color with no significant change in neutralization value or viscosity usually indicates contamination. As the transformer ages, the sampling program should also include checking for the oxygen inhibitor level. Oxygen inhibitors should be in the oil at acceptable levels, which is typically in the 0.3% to 0.4% range. DBPC, 2,6-di-tertrybutyl-paracresol, is the most commonly used antioxidant, but there are many types. As you monitor depletion rates, note the type and level for future reference. Additionally, furanic acids should be monitored when you have other indicators that the cellulose has degraded. When cellulose insulation decomposes due to overheating, chemicals are released and dissolve in the oil.

These chemical compounds are known as furanic compounds, acids, or furans. In healthy transformers, no detectable furans are in the oil (<100 ppb). As the cellulose degrades, the furan levels will increase. Furan levels of 500 ppb to 1,000 ppb indicate accelerated cellulose aging; furan levels >1,500 ppb have a high risk of insulation failure. With regard to performing dissolved gas analysis (DGA) and using the results for evaluating cellulose and insulating oil degradation, the ratio of CO2/CO can be used as an indicator of the thermal decomposition of cellulose. The rate of generation of CO2 typically runs seven to 20 times higher than CO. Therefore, it is normal if the CO2/CO ratio is above seven. If the CO2/CO ratio is five or less, there is probably a problem. If cellulose degradation is the problem, CO, H2, methane (CH4), and ethane (C2H6) will also be increasing significantly. At this point, additional furan testing should be performed. If the CO2/CO ratio is three or under with increased furans, severe and rapid deterioration of cellulose is occurring, and consideration should be given to taking the transformer out of service for further inspection.

REFERENCES A Guide to Transformer Maintenance, S. Myers, J. Kelly and R Parish (ISBN-13 978-0939320004) IEC 60076-14 ed 1.0 (September 2013) Power Transformers – Part 14: Liquid-Immersed power transformers using high temperature insulation materials. Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

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Insulating Oils

ESTABLISHING MAINTENANCE ZERO FOR LARGE POWER TRANSFORMERS IN TODAY’S ELECTRICAL UTILITY SECTOR NETA World, Summer 2016 Issue Ray Curry, American Transmission Company

“Use the best of the past to build the future.” — Unknown In the previous article (see NETA World Journal, Winter 2015), I touched on items that affect transformer installation and testing. Now, I want to focus on two items that have changed the field assembly of these transformers. Both have their origin in the 1970s and continue to have a strong influence today.

FALL PROTECTION AND CONFINED SPACE First and foremost was the establishment of OSHA, and in particular, CFR 1910. Perhaps the most influential thing to happen in the 1970s was the establishment of OSHA. The development of OSHA Regulation CFR 1910 on Fall Protection and Confined Space has had a major influence on how the assembly of large power transformers is accomplished. Before any assembly work is started, the best practice is to ground the transformer to the ground grid of the substation. It is also a good practice to ground all cranes, lifts, processing trailers, and tankers. In the area of fall protection, enhancements to and development of man lifts, work platforms, and body harnesses are designed to comply with OSHA regulations. When assembling large transformers, workers operate anywhere from 10 to 40 feet above the ground. Some transformers have attachments on top of the main tank for the placement of railing systems. Some manufacturers provide an attachment area for installing a May Pole (see picture). This pole is rated to have up to four workers attached at one time and still meet OSHA code. Today’s power transformer is designed with a smaller main tank. The intent of this design is to aid shipping the largest MVA transformer over the road versus railroad shipment. The length and width of today’s transformer has not changed much, but the height has been greatly reduced. This reduction creates two challenges for the assembly crew: (1) more field assembly on top of the transformer’s main tank and (2) in most designs, very restricted work space for any inside tank work required to connect the high- and low-side bushings. To address the inside work, draw lead bushings are sometimes used. Side wall access flanges allow employees to make up winding connections on the bottom of the bushings.

By OSHA regulation, should any assembly work be required inside of the main transformer tank, this entry point and workspace must be treated as a confined space. The regulation states that the entry is by permit only. Another part of the regulation requires that the contractor have extraction equipment present while workers are in the permitted space.

DESIGN AND ENGINEERING CHANGES The second influential item of the 1970s affecting transformer field assembly is design and engineering changes. Advancements that began in the 1970s have become global today. Transformer manufacturers must use the building blocks of the past to compete successfully today. The advancement of computer-aided design (CAD), for example, gave rise to computer-aided engineering (CAE), which allowed the engineer to build with modeling software. These programs grew in many directions and gave birth to new support services and ancillary equipment. Start-up companies provided polymers, epoxy resins, and new dielectric insulations, which in turn allowed the transformer to be built with a higher basic insulation level or basic impulse level (BIL), which led to higher kilovolt (kV) levels.

34 When fully loaded, these large transformers produce a tremendous amount of heat. To dissipate this heat, mineral oil is used with pumps and radiators. Silicone and other fluids were developed through the 1970s, but mineral oil still provides the best heat transfer in the large transformer. However, mineral oil can have a negative impact on the environment. To counter this, new products for containment and engineered systems have been initiated for most transformers, new and old. With respect to ancillary equipment, Reinhausen developed the vacuum tap changer and grew its world market share in the 1970s. Most distribution and transmission class transformers have load tap changers. The vacuum tap changer requires far less maintenance compared to older tap changers. Likewise, companies such as Ohio Brass and Qualitrol, among others, developed and improved transformer products through the 1970s and 1980s. Microprocessor-based protective relays — a vast improvement over the electro-mechanical relay — now protect this expensive capital equipment. Computer modeling software has also provided design engineers with the ability to build a transformer that operates with more efficiency, heavier load cycle, and longer operating life. To gain this capability, field assembly and oil processing has been improved from the 1970s to now. Companies such as Barron have designed vacuum/oil processing trailers that are also computer controlled. All transformers in the high-voltage class (50kV and above) are designed to withstand full vacuum. The high vacuum is used to dry or pull moisture out of the transformer. In the 1970s, this processing equipment would attain 800 to 1,000 microns or 0.8 to one Torr. Today’s equipment will typically reach 40 to 200 microns. To put this in better perspective: 1,000 microns = 1 Torr = 1 millimeter of mercury Because of improved design and assembly, today’s transformers use neoprene and nitrile rubber gaskets, compared to units built in the 1960s and 1970s, which used cork or cork-neoprene. On the older transformer, oil leaks occurred early as the cork dried out, which in turn affected annual maintenance work. The preferred gasket or O-ring rubber is Nitrile 70 or Nitrile 90. Many transformers of the late 1980s are in service today with Nitrile 70 and have had little or no oil leak issues caused from degradation of the nitrile. When these units were first assembled and processed, the benefit of having the advanced gaskets and O-rings was a tighter transformer with respect to vacuum/pressure leaks. In turn, this reduced the vacuum processing time. Even with the higher vacuum, the processing and oil filling of a large transformer takes time. Typically, most of these transformers will hold 10,000 to 26,000 gallons of oil. As part of the processing, oil is heated and degassed as it flows through the processing equipment at a rate of 20 to 30 gallons per minute, heated again, and injected into the transformer tank. Some transformer manufacturers also require oil recirculation to obtain lower moisture levels. After

Insulating Oils all, in most installations, the manufacturer is providing a warranty that may last several years. Another aspect of today’s transformer is the preservation of the oil. Many transformers of the 1970s used a nitrogen blanket to control oil moisture buildup. Today’s transmission class transformer will use the conservator oil preservation system (COPS). With the use of COPS, today’s transformer now has a very sensitive dissolved gas analyzer (DGA) system. With the use of another protective relay — a gas-sensing relay that will detect explosive gases — the transformer now has enhanced protection against electrical faults that occur inside the transformer main tank. When an electric arc happens in an oil transformer, explosive gasses are produced; if allowed to accumulate, further damage or transformer failure may occur. An objective of every large power transformer assembly and installation is to maximize its life cycle by establishing a sound maintenance program. A term used today is Maintenance Zero. By obtaining the proper installation, vacuum/oil processing, and detailed final in-service testing, the transformer owner lays the foundation for 40-plus years of useful transformer life. In the next article in this series, I will outline how power transformer testing, test equipment, and record keeping have changed from the 1970s to today. There are challenges going forward. One is maintaining a skilled workforce that can deliver quality technical workmanship safely to the customer. Another is building a strong working relationship between the manufacturer and the field assembler/processor/testing company. As a result, many NETA Certified Companies have formed strong working relationships with Hyundai, GE, ABB, and Siemens to name a few. These relationships are strengthened with factory training, technical seminars, and new product engineering updates. With many of today’s transformers built overseas, reliability to the end customer has taken on a whole new meaning and significance. Ray Curry graduated from Penn State University in 1969. He joined Westinghouse Electric in the East Pittsburgh Division and the PCB Division at Trafford, Pennsylvania. In 1977, Ray relocated with Westinghouse to St. Louis, Missouri, working in the E&ISD Division as a Field Service Engineer specializing in high-voltage switchgear and construction/commissioning power substations. After retiring from Westinghouse in 1994, Ray managed two Municipal Electrical Systems for the cities of Chanute and Garden City, Kansas, from 1994-2000. From 2007 to the present, Ray has been a Commissioning Engineer with American Transmission Company, building and maintaining over 500 69kV138kV to 345kV electrical substations, including more than 200 power transformers within the ATC Service Footprint. He sits on ATC’s Safety Committee and has maintained an active affiliation with NETA for six years. 

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Insulating Oils

GAUGING TRANSFORMER CONDITION NETA World, Fall 2016 Issue Don Genutis, Halco Testing Services

Fluid-filled transformers are unique compared to other electrical equipment in that basic visual inspections can often provide a wealth of condition-related information. The fluid in a liquid-filled transformer provides several critical functions, including electrical insulation and cooling. The high dielectric strength of the fluid allows more consistent insulating capabilities compared to air and also functions as a coolant to allow heat transfer away from the windings. Cooling fins allow the warm fluid to cool and help preserve the paper winding insulation. Fluid-filled transformers are typically equipped with three primary gauges that can provide important operating information. ●● Vacuum-pressure gauge. Large substation transformers are filled with mineral oil that typically does not have oxygen inhibitors or other additives. It therefore is more critical to maintain a positive nitrogen blanket so that oxygen does not have a chance to cause adverse effects on the oil and create corrosion of internal metallic components. A slight positive pressure is desired when inspecting the top gas-pressure gauge. The pressure can fluctuate because of temperature variations due to loading and ambient temperature changes. A gauge that is always at zero may be an indication of a leak that can allow moisture and other contaminants to enter the transformer. ●● Oil-level gauge. This gauge only displays the 25 degrees C mark which is related to present fluid level indicated by the needle. If the present transformer temperature is not 25 degrees C, the needle will fluctuate accordingly; however, if the fluid temperature is near 25 degrees C, the needle should be near this mark. This gauge is very useful to spot low coolant levels, which can impede proper cooling functions and create transformer overheating, which can substantially reduce operating lifetime. ●● Temperature gauge. The temperature gauge provides the present oil temperature. Since fluid temperature can vary, the maximum temperature indicator (if equipped) is useful to determine how hot the transformer got since the indicator was last reset. This indication should be compared to the rating of the transformer to spot possible overheating.

WINDING-TEMPERATURE GAUGE There is another less common and slightly more complex gauge to consider when performing transformer inspections. The winding-temperature gauge is often used to control auxiliary cooling systems such as fans and pumps, which operate when a set winding temperature is reached. The winding-temperature gauge typically determines the winding temperature indirectly by measuring the top oil temperature plus the temperature produced by a small internal heater circuit in close proximity to the temperature bulb. This heater circuit is connected by a current transformer (CT) to one of the low-voltage phases. As the transformer secondary current and thus CT current increase, the heater circuit elevates the temperature of the bulb, thus simulating actual winding temperature. Other transformer gauges may include the bushing oil-level gauge and the conservator tank oil-level gauge. Collectively, transformer gauges provide a simple overview of transformer operating conditions and should be considered when performing no-outage transformer inspections. Don A. Genutis holds a Bachelor of Science degree in Electrical Engineering and has been a NETA Certified Technician for more than 15 years. He has held various principal positions during his 30-year career in the electrical testing fieldand has primarily focused on advancing no-outage-testing techniques for the last 15 years. Don presently serves as President of Halco Testing Services in Los Angeles, California.

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Insulating Oils

TRANFORMER LIQUID SAMPLING DANGERS: WHERE DOES THE AIR GO? NETA World, Winter 2016 Issue Don Platts, Omicron and Dave Hanson, Tj/H2b Analytical Services, Inc.

In many companies, test technicians are assigned tasks that do not involve electrical tests. One commonly performed test is transformer oil sampling for laboratory tests of DGA or oil quality. The typical transformer owner assumes there is little or no risk involved if the oil sampling is done according to any of the many sampling procedures available from ASTM, transformer manufacturers, service providers, and oil testing laboratories. This article addresses potentially catastrophic safety issues encountered while sampling. The tests performed for this report modeled sampling procedures and monitoring device installation. The tests identified the cases where air will always enter the transformer and several other cases where bubble ingress is very likely. Since oil samples are normally taken with the transformer in service, there is a risk of an in-service failure. The energized winding, leads, bushings, etc. could be in the path this bubble will take as it floats up through the oil volume.

REVIEW OF VALVE TYPES Before discussing the issues involved with sampling, let’s review the variety of valves used as transformer drain valves (Figure 1).

tem, the pressurized air moves back through the valve into the transformer.

Fig. 2: These sketches illustrate the danger of a gate valve when used as a transformer drain valve because when the valve outlet is blocked or connected to a closed sampling system, the trapped air moves back through the valve into the transformer. ●● Ball Valve. The ball valve (Figure 3) also provides a full-bore opening. It requires a 90-degree handle rotation between fully open and closed. A ball with a hole through it sits in the center of the valve body and rotates on its vertical axis as the handle is moved. When the ball starts to rotate from its closed position, a small opening in the shape of a football appears. It is oriented vertically, allowing the liquid to move under pressure, displacing the air in the valve cavity. When the output is blocked, the pressurized air in the valve moves back through the opening into the transformer.

Fig. 1: Shown left to right are the globe, ball, and gate valves. Note the construction of the valve bodies. ●● Gate valve. The gate valve (Figure 2) can provide a full-bore opening through the valve to allow maximum oil surface exposure or insertion of a probe. A gate in the center of the valve body moves up and down on its vertical axis as the handle is rotated. As the gate lifts from its closed position, a small opening in the base of the valve cavity appears. It is oriented horizontally so that it allows the liquid to move, under pressure, and to compress the air in the valve cavity. When the valve outlet is blocked or connected to a closed sampling sys-

Fig. 3: These sketches illustrate the danger of using a ball valve as a transformer drain valve because when the output is blocked, the pressurized air in the valve moves back through the opening into the transformer.

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Insulating Oils ●● Globe Valve. The globe valve (Figure 4) provides a restricted flow path, resulting in turbulent flow. A valve disk sits in a valve seat in the center of the valve body and moves up and down on its vertical axis as the handle is rotated, regulating the liquid flow rate. As the valve disk lifts from its closed position, it allows the liquid to move vertically, under pressure, and to compress the air in the valve cavity. With an unrestricted opening, the air will be forced out of the valve along with the liquid. When the valve outlet is blocked (or restricted), the air is trapped in the valve cavity and cannot move back into the transformer.

on the outcome of these experiments. (Note: SAE 10 motor oil has a viscosity of 85 – 140 cSt, and honey is 10,000 cSt.) The different configurations of sampling equipment studied can be broadly categorized into restricted and unrestricted groups. An oil sampling procedure may include a step to open a drain valve while there is a closed system component (or just a pipe plug) attached to the outlet side of the valve (restricted), or a different case where the sampling equipment does not close the outlet (unrestricted). Chamber air pressures used for the trials in each study ranged from -100KPa to 175KPa. As each valve was opened, the entire assembly was observed for bubble ingress (Figure 5).

Fig. 4: There is minimal danger with a globe valve used as transformer drain valve because the trapped air floats above the liquid and remains in the valve.

TEST PLAN TJ|H2b and OMICRON have both conducted tests using the various valves mounted on models of a transformer tank. Test protocols were developed to address:

Fig. 5: As the valve was opened during each of the test trials, the entire assembly was observed for bubble ingress. The results of the trials are summarized in Table 1.

●● Will air enter the tank when the valve is opened and the valve outlet: ○○ Is sealed by a pipe plug? ○○ Has a sampling port with the connected tubing free of restrictions? ○○ Is closed by a second valve in the sampling equipment? ●● Can one safely test for transformer tank positive pressure using the documented procedures? ●● Does pressure level inside the tank affect the results? ●● Do procedures for installing monitoring products prevent air ingress?

SAMPLING EXPERIMENTAL SETUP A pressure chamber was built to test a variety of sampling conditions. Gate valves, globe valves, and ball valves were connected to the chamber filled with water and air for these studies. Pressure in the chamber was varied using fittings on the top. The authors chose to use water rather than an insulating liquid primarily for the convenience and safety of the experiments. Each of the hundreds of trials required that the test assembly be disconnected and all of the liquid drained out before another trial could be started. Since water has a viscosity of 1 cSt and mineral (insulating) oil measures at 2.3 @100C, 9.6 @ 40C and 19 @15C, using water has no affect

Table 1: Results for Cases Where Air Cannot Escape (Restricted) and Where Air Can Escape (Unrestricted).

EVALUATION OF THE TEST RESULTS A review of valve descriptions shows that each valve type presents a different degree of opportunity for air ingress under the tested scenarios. The ball valve loses all restraint at the valve face the moment it is opened. The gate valve loses restraint at the valve face by degree as the gate is raised. The globe valve uses buoyant forces provided by the liquid to maintain restraint as the valve is opened. ●● Sampling with an unrestricted valve outlet. With positive pressure inside the main tank, and with only unrestricted or

38

Insulating Oils open-vented components of sampling equipment on the drain valve, no bubbles will enter when the valve is opened.

●● Sampling with a closed valve in the sampling fittings or tubing. Some sampling equipment components may completely close the airspace external to the valve. When sampled through a ball or gate valve, air is forced into the transformer tank, even against positive tank pressure. The procedure may need modification. As seen in Table 1, only the globe valve will allow this procedure without bubble ingress. ●● Sampling with vacuum or negative gauge pressure in the transformer tank. There is no way to safely sample a transformer while it has negative gauge pressure. The tests demonstrated that with any sampling procedure, and with any valve type, for cases with negative gauge pressures, air will always enter the transformer when the drain valve is opened.

TESTING FOR VACUUM IN THE TRANSFORMER TANK Most sampling procedures include a test to verify positive pressure in the tank before sampling, based on ASTM D923-07, Standard Practices for Sampling Electrical Insulating Liquids. The objective is to ensure that air will not enter the transformer during the sampling process. However, if a negative pressure is present in the tank at the valve, air bubbles will enter the tank, and the condition to be avoided is actually caused by following this testing procedure. The authors recommend that the test for positive pressure (ASTM D923-07, Clause 7.2) be modified — or eliminated — to prevent air from entering the transformer with a negative pressure at the valve.

CONCERNS ABOUT VALVE TYPE If someone attempts to take an oil sample from a ball or gate valve using standard techniques and equipment, air bubbles could very likely enter the transformer. If you must sample from one, carefully review the procedure to ensure there is a path for the air to escape when the drain valve is opened. The globe drain valve was required by IEEE standards until the 1980s, when some customers started to require a full bore-opening valve to accommodate monitoring devices. Since many manufacturers’ standard drain valve is still the globe valve, with a positive pressure inside the tank, most transformers will not have these issues of air ingress.

OIL PRESERVATION SYSTEM AND TANK PRESSURE Test results show that we must address verification of the tank pressure. Therefore, let’s review the three oil preservation systems currently used to allow volume for the expansion and contraction of the transformer oil.

●● The sealed tank design has a blanket of nitrogen above the transformer oil. This design has a pressure/vacuum gauge and a pressure/vacuum bleeder to regulate the pressure inside the tank to a range of -8 to +10 psi. To ensure safe sampling, rely on the pressure gauges. ●● The inert gas pressure system uses a nitrogen bottle to supply pressure to the nitrogen blanket. Through adjustable regulators, it maintains the pressure in a range of approximately 3-8 psi. Alarms alert to high and low tank pressure and for low nitrogen bottle pressure. If the system is functioning, there will be a pressure above the oil. ●● The conservator tank mounts above the main tank allowing expansion of the oil. Usually, a rubber bag separates the oil from the oxygen and moisture in the atmosphere. With normal oil flow in and out of the conservator, static head pressure at the sampling valve is always present. If you cannot rely on the readings of the gauges and regulators, or a chance exists of a negative pressure in the main tank, the safest recommendation is to not take a sample.

INSTALLATION OF MONITORING SYSTEM COMPONENTS Similar tests confirm that installation procedures for some oil-contact monitoring products produce the same restricted case when the drain valve is opened, allowing ingress of air bubbles. Before installing a monitoring system on an energized transformer, investigate the possible results of the manufacturer’s installation procedures.

CONCLUSIONS Sampling should not be attempted if there is a negative gauge pressure inside the tank. The authors recommend that organizations publishing a sampling procedure should study this article, conduct their own experiments, and revise their sampling procedures as necessary. Even with a valid sampling procedure, a simple error of opening the wrong valve first could introduce air bubbles into the oil with serious consequences. The authors recommend that relevant IEEE standards should again require globe valves for drain valves as well as for any other valve specified for sampling access. The authors urge all transformer owners, operators, and service contractors to be cautious when performing oil sampling or installing monitoring devices on valves of energized transformers, and to review their existing procedures. Each worker should: ●● Be aware of the conditions that can lead to air entering a transformer. ●● Be able to identify the type of sampling valve. ●● Know how to determine the pressure inside the main tank. ●● Take all precautions to ensure that sampling can be done safely.

Insulating Oils For many workers, this will require new training, using a modified training program and revised sampling procedures. Donald W. Platts is a Senior Engineer with OMICRON Electronics Corp., providing technical support and training related to transformer applications and testing. He is the past Chair of the IEEE PES Transformers Committee. Dave Hanson is the President and CEO of TJ|H2b Analytical Services, Inc. He has been active in the field of insulating materials testing since 1978 and has been involved with the development of test methods and diagnostic criteria for high-voltage electric equipment. Dave’s experience extends to transformers, tap-changers, bushings, and gas- and oil-filled circuit breakers.

39

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

6

alabama 1

2

3

4

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

22

23

29

Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

26

27

28

Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

36

37

30

Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

46

47

48

49

Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

58

florida 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

missouri 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

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Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

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new york 139

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BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

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HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

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ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

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Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

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Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

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Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

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POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

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Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

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Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

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Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

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Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

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Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

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227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

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Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

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Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

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Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

54

Insulating Oils

VOLUME 1

MAINTENANCE

SERIES III

HANDBOOK

MAINTENANCE Vol. 1 HANDBOOK

SERIES III

Published By Sponsored by

Shermco Industries

Oil Analysis Services

from

Available 24 hours a day for emergency needs, Shermco’s analytics services include preventative maintenance and recommendations from three in-house analysts, who offer more than 60 years of experience with transformer oil analysis, testing and chemistry. The oil lab offers the electrical maintenance and testing industry a credible partner in insulating oil analysis. Further, Shermco can provide a timely turnaround and accurate testing of mineral, silicone and FR3 oils, including test values, trends and recommended repair.

Maintenance Services Furanic Compounds (cellulose degradation)

Specific Gravity

Degree of Polymerization of Insulating

Corrosive Sulfur Test

Passivator Inhibitor Test

Dissolved Metal Analysis

Particle Count Test

Polychlorinated Biphenyls (PCB) Analysis

Temperature and Viscosity Tests

Power Factor Tests at Both 25°C and 100°C

Wear Debris Using Analytical Ferrography

Essential Tests Acid Number

Dissolved Gas Analysis

Interfacial Tension

Dielectric

Color Comparison

Visual & Sediment Exam

Moisture

1.888.SHERMCO SHERMCO.COM

MAINTENANCE VOLUME 1

Published by

InterNational Electrical Testing Association

MAINTENANCE–Vol. 1 TABLE OF CONTENTS Dual Ground.................................................................................................... 5 Jeff Jowett

Maintenance Strategies and Their Applications..................................................... 7 Kerry Heid

Testing Rotating Machinery – Partial Discharge Interpretation.................................. 9 Vicki Warren

Technologies for Outdoor Substation and Switchyard Testing................................. 12 Don Genutis

Data Center Maintenance – Part 3 – Battery and Backup Generator Maintenance................................................................................... 14 Lynn Hamrick

Testing Rotating Machinery - Synchronous Rotor Winding Common Electrical Tests...................................................................... 18 Vicki Warren

Maintenance Testing of Wind Farm Distribution Systems....................................... 21 Don Genutis

Wind Farm Collector System – Predictive Maintenance Practices........................... 23 Paul Idziak

Wind Turbine Generator Electrical Failures......................................................... 27 William Chen

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

Up-Tower Electrical Testing of Wind Turbine Generator Stator and Rotor Main Windings................................................................................ 30

Kevin Alewine, Casey Gilliam

Electrical Power System Testing – A Quantum Change in our Field has Arrived........ 33 John Hodson

Synchronous Rotor Winding – Common Electrical Monitoring................................ 37 Vicki Warren

Switchgear Partial Discharge Location................................................................ 41 Don Genutis

VLF-MWT – How To Apply the New Way of Cable Condition Assessment............... 43 Martin Jenny, Alexander Gerstner, and Timothy Daniels

Detecting Common Power Quality Issues............................................................ 49

Andrew Sagl

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Maintenance Vol. 1

DUAL GROUND NETA World, Winter 2016 Issue By Jeff Jowett, Megger

Testing circuit breakers for contact resistance is a vital part of many electrical maintenance programs. It requires a high level of sophistication in the test equipment.

the resistance. The tester then measures the voltage drop between the two potential probes. It now has measured the test current and voltage drop. Ohm’s Law does the rest.

First, test currents, which are far more robust than those of ordinary multimeters, are necessary to ensure full working contact across the contact surface. Most utilities specify a 100 A test. Second, resistance measurements must be made to a level of accuracy and precision far beyond that of many common applications. Utility standards generally require no more than 100 μΩ.

But in testing installed circuit breakers, physical and electrical impediments abound. The test connections may be 20 feet in the air and require a bucket truck or other means of ascension. Prohibitively long leads and grounding cables increase time and effort on the job. If dual grounds are in place on opposite sides of the breaker, protection is at a peak. The line being tested is, of course, de-energized. But in power systems, live lines nearby can inductively apply thousands of volts to the adjacent line. Current may sometimes be minimal, but the voltage is still dangerous for its shock value, especially to anyone working at elevation. And this interference current, if directed through the tester, can seriously distort the measurement.

The formula: W = I 2R where watts equal current squared times resistance, indicates how even relatively small changes in resistance can have a profound effect upon energy, which, as heat, can be both wasteful and dangerous. It is obvious that effective testing requires a level of instrumentation above and beyond the familiar DMM. To ensure high accuracy, safety is a high priority along with rigor in instrumentation and measurement. Industry standards, safe working practices, and the effective employment of personal protective clothing and equipment are indispensable. Furthermore, where worker safety is concerned, redundancy is a valuable ally. When high-voltage circuit breakers are taken out of service for maintenance, safety and system protection rules make it very difficult to allow removal of the temporary ground leads from 20 feet in the air, with power lines nearby that are subject to dangerous events like lightning strokes. Maximum safety is achieved by grounding both sides of the breaker, but that introduces another problem: a parallel current path.

A standard test setup is illustrated in Figure 1. Current is injected by the tester on one side of the breaker and returns to the tester via the ground on the opposite side. Once the safety ground is lifted, all of the test current must pass through the breaker to complete a circuit. The two potential connections are made across the contacts and inside of the current clamps. The tester itself is grounded for safety but does not take part in the measurement circuit. Inductive interference can be picked up by the test circuit and influence the reading.

LOW RESISTANCE TESTING VS. INSTALLED CIRCUIT BREAKER TESTING A brief review of low-resistance testing is in order. To achieve the accuracy and precision necessary to test circuit-breaker contact resistance — where a single ohm is far too much and even a few micro ohms can represent an unacceptable deterioration in performance — the tester must not incorporate lead- and probecontact resistance into the measurement. This is accomplished by four-wire (Kelvin bridge) measurement. The tester injects a DC test current through the specimen being measured. It can accurately measure this current to provide a basis for calculating

Fig. 1: Traditional Breaker Test Employing Single Ground Applying a second ground (Figure 2) keeps the operator safe and effectively diverts interference currents, but at the cost of accuracy in the measurement. There is now a parallel current path through the earth from one ground to the other, bypassing the circuit breaker entirely.

6

Maintenance Vol. 1 Fig. 3: Aerial Test with Lightweight, Handheld Instrument Employing Duplex Leads The earth is part of the circuit, but all test current passes through the breaker. There is no alternate path. As substations are typically shut down for a maximum four-hour period and must go back on line, the time saved in not having to lift the protective ground is significant. While the operator remains protected, this configuration would not do for an on-line substation as interference current would travel on the dual ground and degrade the measurement. For a de-energized station, it’s fine.

Fig. 2: Typical Dual Ground Test Typically, ground resistance is at least 2 mΩ — about 20 times the maximum acceptable contact resistance — which introduces a serious error into the measurement. This error can be eliminated by use of a current clamp built into the tester. The current clamp measures the parallel current and subtracts it from the value used to calculate the contact resistance. Only the current passing through the circuit breaker contact is then part of the measurement calculation, and the parallel path is effectively eliminated as a source of error. Meanwhile, the parallel path keeps the operator safe and diverts the interference. Meeting the rigorous demands of a circuit-breaker contact test requires a current clamp of maximum quality, specially designed and interfaced with the tester. Do not try a jerry-rigged test with an ordinary clamp-on ammeter used in building wiring applications.

DUAL GROUNDING Dual grounding can also be applied successfully without the necessity of a specialized ohmmeter with built-in clamp. In situations where inductive interference is not ever-present, as in a de-energized substation shut down for maintenance, valuable time can be saved by testing with dual grounds in place that do not have to be lifted for the test. The operator is run up in a bucket truck, the tester connected across the test item, and the test conducted (Figure 3).

Contact resistance is a comparatively simple test in concept. Circuit breakers are also subjected to more sophisticated tests: timing, motion, and dynamic resistance measurement (DRM), and vibration. Timing is critical so that too much voltage does not develop across the contacts as the breaker opens; it is generally limited to 2 ms. The speed of the breaker’s motion must be sufficient to break the arc and prevent it from re-striking. It can be expressed in length, degrees, or percentage of movement, and generally takes from 10 to 20 ms (1 to 2 zero crossovers). DRM is also a measurement of contact resistance, but it is measured dynamically over an open or close operation. Vibration analysis can be made over one open-close operation. Corrosion and other metal-to-metal issues can affect the outcome of this test, so it is a good test to run after long standing in the same position. All of these tests can be performed with circuit-breaker analyzer systems available on the market, and with maximum operator safety and minimal test time using dual grounding.

CONCLUSION An additional safety consideration is in order. Because safety is the prime parameter in all electrical testing, some substations have two separate grounding systems, and this must be taken into account when setting up a circuit breaker test. Either the two systems must be connected with a temporary bond or the test instrument must be powered from an isolating transformer. If neither of these protective steps is employed, the test instrument’s protective ground becomes a connection between the two grounding systems. This could provide a path for high current through the protective ground leads for which the system is not designed. Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Ampfor electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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MAINTENANCE STRATEGIES AND THEIR APPLICATIONS NETA World, Spring 2013 Issue Kerry Heid, Magna Electric Corporation

Electrical equipment maintenance is crucial for a number of reasons. First and foremost, maintenance and testing of critical protection systems is required to ensure that worker safety is not in jeopardy. Also, electrical maintenance is critical in ensuring that uptime is maximized and that electrical power system equipment reaches its intended life cycle. Many approaches can be taken toward the various equipment and systems, and this article will take a look at five varying strategies and their applications.

Some disadvantages of preventative maintenance are that catastrophic failures are still possible. Also, this maintenance approach is labor intensive and often includes activities that are unnecessary.

REACTIVE MAINTENANCE

Predictive maintenance or condition-based maintenance uses measurements to detect failure at the onset of degradation. This allows for small issues to be eliminated or controlled prior to system failure. Predictive maintenance uses tools to determine maintenance task requirements based on quantifiable equipment conditions.

Reactive Maintenance is sometimes called run to fail and allows systems and equipment to operate with little or no maintenance. The advantage to reactive maintenance is that maintenance dollars will not be expended until something fails. This means while the equipment is running, a smaller maintenance staff will be required and equipment can operate without the need to organize maintenance outages. There are some disadvantages to reactive maintenance. When power system equipment fails, the failure is often catastrophic and usually requires much capital and labor hours including overtime to make the repairs. The failure often cascades into surrounding equipment as well. These failures can create a major disruption to production or uptime within the facility. It should be noted that reactive maintenance is not recommended for critical switching and protection schemes in electrical power system applications. Some application examples are noncritical systems or systems with built in redundancy.

PREVENTIVE MAINTENANCE Preventative Maintenance uses a time-based or machine run-based schedule to predetermine degradation with the aim of extending the useful life. Expending time and resources to increase the system reliability, control degradation, and extend equipment life are main goals. There are a number of advantages to the preventative maintenance approach. The equipment life will be extended if the manufacturer’s maintenance requirements are heeded. Also, timebased maintenance allows for maintenance work to be scheduled for flexibility in maintenance periods.

Preventative maintenance works well with a skilled maintenance staff and equipment that can be regularly shut down to perform the work.

PREDICTIVE MAINTENANCE

This type of maintenance has many advantages. This approach pinpoints what activities are required and then allows those activities to be scheduled. This increases uptime and reduces unnecessary maintenance while optimizing the operation of the equipment. Disadvantages are the initial costs associated with diagnostic equipment and training of maintenance personnel. Another disadvantage is that management may not see all the benefits in the initial investment of personnel and equipment. This has wide application in the electrical power system business. Transformer oil analysis and switchgear partial discharge analysis are just two of the many applications.

RELIABILITY CENTERED MAINTENANCE The approach to reliability centered maintenance (RCM) uses a number of factors including the probability of equipment failure and a combination of other maintenance practices including predictive maintenance. RCM provides a high level of reliability and cost effectiveness by using a systematic approach to the facility’s equipment and resources. There are many advantages to RCM. This approach recognizes that not all equipment in a facility is of equal importance. It also recognizes that some equipment is more reliable and requires a different methodology. RCM also strives to optimize the available personnel and financial resources. There are some disadvantages of the RCM method. The cost for training, equipment, and startup are significant before the real savings can be appreciated.

8 The RCM approach works best where a mix of philosophies will bring the most benefit to the facility’s budget and resource availability.

RISK-BASED MAINTENANCE Risk Based Maintenance (RBM) uses a process where risk can be quantified and prioritized so other types of maintenance can be established. Owners use risk assessment and criticality to manage the maintenance and inspection programs involving reactive, preventative and predictive philosophies. RBM has a few advantages particularly from a business perspective. This approach allows the asset owners to maximize the resources and can be the most cost effective manner to establish a maintenance program. Maintenance is based on risk factor and vitality. RBM requires special expertise to assess the risk. This process requires extensive data and failure calculations to effectively apply.

CONCLUSION Electrical maintenance is critical for worker safety, facility uptime, and for equipment to reach its full life cycle. Many approaches can be taken based on the availability of equipment outages, facility design, and the availability of resources. However, electrical power system equipment such as critical switching and isolation devices as well as protective relaying systems should always be given a high priority for maintenance as the safety of personnel depend on its correct operation.

Kerry Heid is the President of Magna Electric Corporation, a Canadian-based electrical projects group providing NETA Certified Test Technicians and related products and solutions for electrical power distribution systems. Kerry is a past President of NETA (Inter- National Electrical Testing Association) and has been serving on its board of directors since 2002. Kerry is chair of NETA’s training committee and is a Senior Certified Test Technician Level IV. Kerry was awarded NETA’s 2010 Outstanding Achievement Award for his contributions to the association. Kerry is the chair of CSA Z463 Technical Committee on Maintenance of Electrical Systems. He is also a member of the executive on the CSA Z462 technical committee for Workplace Electrical Safety in Canada and is chair of Working Group 6 on safety-related maintenance requirements as well as a member of the NFPA 70E – CSA Z462 harmonization working group. Kerry has performed electrical engineering, testing, maintenance, commissioning, and training activities throughout North America for the past 23 years with Westinghouse Service and Magna Electric Corporation. He resides in Regina, Saskatchewan, with wife Pam and sons Brendan and Colby.

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TESTING ROTATING MACHINERY – PARTIAL DISCHARGE INTERPRETATION NETA World, Spring 2013 Issue Vicki Warren, Iris Power LP.

Partial discharges (PD) are small electrical sparks that occur when voids exist within or on the surface of high-voltage insulation of stator windings in motors and generators. These PD pulses can occur because of the thermal deterioration, manufacturing/installation processes, winding contamination, or stator bar movement during operation.

PARTIAL DISCHARGE SENSORS Permanently mounted PD sensors block the AC power signal (50/60 Hz) but pass the high frequency PD pulses (50-250 MHz). The type of sensor installation and test instrument depends on the machine or equipment being monitored. The first step of PD detection is the placement of a sensor somewhere near the source of the PD. Two types of sensors referenced in IEEE 1434-2000 and IEC/TS 60034-27-2 are ●● Capacitive couplers, epoxy mica capacitors (EMC) - for motors, hydros, and small turbos. [Figure 1, Figure 2] ●● Stator slot couplers (SSC) - for large turbos (>100 MW). [Figure 3]

Fig. 1: EMC at Terminals

Fig. 3: SSCs in Turbo

PD DETECTION During normal operation, a continuous PD monitoring or portable PD instrument connected to the sensors separates noise and correctly classifies the PD. Until recently such an on-line PD test had been difficult to implement due to the presence of electrical disturbances that have PD-like characteristics. This can lead to healthy windings being misdiagnosed as deteriorated, which lowers confidence in the test results. “Noise is defined to be nonstator winding signals that clearly are not pulses.” [IEC/TS 60034-27-2] Electrical noise from power tool operation, corona from the switchgear and RF sources, etc., is easily confused with PD from the machine windings. “Disturbances are electrical pulses of relatively short duration that may have many of the characteristics of stator winding PD pulses – but in fact are not stator winding PD.” [IEC/TS 60034-272] Some of these disturbances are synchronized to the AC cycle, and some are not. Sometimes synchronized disturbance pulses can be suppressed based on their position with respect to the AC phase angle. A good on-line PD test reduces the influence of noise and disturbances, leading to a more reliable indication of machine insulation condition. Three methods of noise and disturbance separation include: ●● Band-pass filtering of PD between 50-300 MHz, whereas noise is less than 35 MHz. [Figure 4] ●● Separation based on direction-of-arrival to two sensors connected to a single phase [Figure 5, Figure 6]

Fig. 2: EMCs on Bus Bar

●● Separation based on pulse characteristics [Figure 7]

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Maintenance Vol. 1 other similar machines, this is an indicator that visual inspections and/or other testing methods are needed to confirm the insulation condition [IEEE 1434-2000].

TREND

Fig. 4: Band-Pass Filter 40-350 MHz

If the unit operating parameters – voltage, load, winding temperature, and gas pressure – are similar to those of the previous test, then a direct comparison can be made between the two test results. Environmental conditions such as humidity may have a very noticeable impact, especially if the surface contamination becomes to some extent conductive when damp, so it should be recorded from one test to the next. When a trend line is established for PD tests taken over a period of time, it will be obvious that most show small up and down variation between successive tests [Figure 8]; however, a sustained upward trend indicates developing problems.

Fig. 5: PD coming from Machine

Fig. 8: Typical PD Trend

COMPARE TO SIMILAR MACHINES

Fig. 6: PD coming from System

If the PD magnitudes by the same test method from several similar windings are compared, the windings exhibiting higher PD activity are generally closer to failure. Due to the influence of the test arrangement on the results, the test setup (sensors and test instrument) must be the same for all comparisons. One example is the statistical summaries of the peak magnitude, Qm, values based on the most recent Iris Power database that contains several thousands of test results. Each table shows the average, maximum, and the 25th, 50th, 75th, 90th, and 95th percentile ranks [Table 1]. The 25th percentile is the Qm magnitude for which 25 percent of the test results are below, similarly for the other percentiles. Normally, there is concern for a winding if the Qm in a machine is higher than the 75th percentile and increasing. Rated kV

6-9

10-12

13-15

16-18

25%

29

34

50

41

50%

70

77

113

77

ANALYSIS

75%

149

172

239

151

Although the magnitude of the PD pulses cannot be directly related to the remaining life of the winding, if the rate of PD pulse activity increases rapidly, or the PD levels are high compared to

90%

288

376

469

292

Fig. 7: PD Pulse Characteristics

Table 1: PD Statistics for Turbos and Motors (Qm in mV)1

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Maintenance Vol. 1 PD DISTRIBUTIONS

CONCLUSIONS

The pulse distribution with respect to the AC phase position in the 3D plots can assist in determining the source of any problems in the stator winding. Normal pulse distributions are Gaussian, negative pulses clustered between 0-90° and positive pulses between 180270°, and are indicative of spherical shaped voids within the slot section of the core [Figure 9].

When using a PD measuring system that adequately separates noise and disturbances, monitoring of the PD activity in a running motor or generator stator winding can be as simple as evaluating the trend, comparing to a statistical database, and evaluating the polarity predominance of the pattern. With this configuration, monitoring for most of the failure mechanisms common to stator winding insulation can be quickly and easily evaluated while the machine is subjected to normal thermal, electrical, ambient and mechanical stresses.

Fig. 9: Normal PD Distribution

Fig. 10: PD Polarity Predominance Due to space charge effects, a pulse will occur in a specific direction based on the proximity of the void to a metallic substance [Figure 10]. No polarity predominance is normally the result of internal delamination (overheating) of the insulation system that has forced the organic bonding material of the insulation to lose its adhesive strength. Negative PD predominance may be the result of voids created due to either improper manufacturing or thermal cycling that has stressed the bonds between the conductor and the first layers of insulating tape. Due to pulse behavior, positive PD predominance normally indicates PD originating on the surface of the insulation system, such as slot discharge, endwinding tracking, and gradient or semicon coating deterioration. Surface PD happens when a coil does not have intimate contact with the core due to shrinkage, improper installation, bar/coil movement, or perhaps degradation of the voltage stress control coatings.

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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TECHNOLOGIES FOR OUTDOOR SUBSTATION AND SWITCHYARD TESTING NETA World, Spring 2013 Issue Don A. Genutis, No-Outage Electrical Testing, Inc.

INTRODUCTION Nearly all utilities and many major facilities utilize open-bus outdoor substation equipment to distribute power. A combination of thermographic, ultrasonic, corona camera, and radio-frequency antenna technologies can be used effectively to detect various problems before they cause failure. This article will review the advantages of these technologies to help determine the best solution for finding problems.

REVIEW OF TECHNOLOGIES Although several no-outage technologies exist for outdoor equipment, the following short list summarizes the most popular and successful instruments used today. Thermographic – Infrared imaging is a very good tool for the detection of thermal problems, especially those related to poor connections (see Figure 1). This technology does well for detecting problems with high resistance under load but does not detect voltage (insulation) problems very well if at all. Fig. 2: Ultrasonic Detector with Parabolic Dish Contact Ultrasonics – Placement of ultrasonic sensors against oil-filled equipment tanks has been successful in detecting internal insulation problems. However, this technique is often unreliable due to noise created by normal mechanical vibration. Additionally, internal components may obstruct the signal so that it cannot reach the sensor. One approach to remove greater amounts of noise is to use higher frequency sensors. Another approach is to utilize multiple sensors to triangulate the PD source in order to obtain better location. Fig. 1: A thermal image of an overheated connection Airborne Ultrasonic – Listening to ultrasonic signals from substation equipment surfaces can help detect potential insulation problems. By adding a parabolic dish to concentrate the signals, distant objects can also be surveyed (see Figure 2). One difficulty with this technology is the inability to distinguish between serious insulation defects and benign corona occurring from sharp protrusions on conductors or hardware.

Corona Camera – This technology detects the ultraviolet light associated with surface partial discharge or corona and provides an image of the precise location of the activity (See Figure 3). Unlike airborne ultrasonic instruments, benign corona can be distinguished from more serious problems using the corona camera. These instruments are very directional, and defects can be hidden from detection if they occur underneath or on rear component surfaces. Therefore, airborne ultrasonics should be used to supplement corona camera surveys. Except for contact ultrasonics, none of the above instruments can detect internal defects.

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Smaller substations can be quickly scanned in minutes, often from outside of the fence, while large switchyards require briefly walking around the equipment in a pattern to ensure nothing is missed.

CONCLUSION By utilizing a combination of technologies, it is possible to identify all common types of equipment failure modes in outdoor substations and switchyards including thermal related, corona, surface tracking, and internal partial discharge defects. Reliability will be increased and operating costs will be reduced significantly by employing a condition-based maintenance strategy that implements these supplemental instruments. Fig. 3: The red cloud at the top of the center bushing represents ionized air as seen in this corona camera image. RF Antenna Technology - Antenna based instruments, such as the one shown in Figure 4 have been developed using a variablefrequency, wide-band, electromagnetic signal receiver connected to a unique directional antenna assembly to detect and pinpoint internal and surface defects in outdoor, open-bus substation and switchyard equipment. This instrument has helped fill some of the gaps left open by the other instruments by having the unique capability to detect internal problems. Used as a stand-alone technology or better yet in combination with the other technologies, a new level of reliability can be achieved.

Fig. 4: A variable-frequency, wide-band, electromagnetic signal receiver with a directional antenna RF antenna instruments are lightweight and relatively easy to use. To survey a substation, the technician merely walks through the yard while pointing the instrument at the various equipment while listening for partial discharge (PD) activity and observing the phase resolved display for PD activity patterns. In substations and switchyards where a lot of benign corona activity exists, a frequency can be selected above the level in which the majority of corona activity ceases. This allows the technician to only detect defects while ignoring benign corona.

Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

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DATA CENTER MAINTENANCE – PART 3 – BATTERY AND BACKUP GENERATOR MAINTENANCE NETA World, Summer 2013 Issue Lynn Hamrick, Shermco Industries This article is Part three of a four-part series on data center maintenance. Key electrical systems for most data centers are the UPS systems and their battery systems and the backup generation systems. The UPS systems are designed to provide primary power to downstream equipment with immediate switching to battery systems with loss of power. Failed or discharged batteries mean the data center’s UPS won’t be able to supply the temporary backup power needed in the event of a power sag or outage. Even though UPSs are not designed to keep the data center running during a long-term outage, they do provide the carry-over capability that accommodates a seamless transfer to an alternate power source like a backup generator. This article will focus on the key attributes of battery and backup generation maintenance and how they can affect data center reliability.

UPS BATTERY MAINTENANCE The battery is by far the most vulnerable and failure-prone part of a UPS system. Because of this, much time and effort is allocated to maximizing a battery’s reliability and life within the data center. At a minimum, annual testing, verification, and inspection of a battery system should be performed. As with all electrical systems, infrared thermographic surveys should also be performed on battery systems on at least an annual basis. Additional quarterly or semi-annual inspections should be performed if the age and condition of the battery warrant the activity. Watering is the single most important factor in maintaining a flooded lead acid battery. The frequency of watering depends on usage, charge method, and operating temperature. A new battery should be checked every few weeks to determine the watering requirement. This prevents the electrolyte from falling below the plates. Avoid exposed plates at all times, as exposed plates will sustain damage, leading to reduced capacity and lower performance. Battery charging is probably the second most important factor in maintaining a battery system. A correctly functioning battery charging system with a healthy battery condition will result in a fully charged and reliable battery system that is available when called upon for service. The following checks are a quick way of determining a correctly and fully charged battery: ●● Stabilized charging currents. ●● Stabilized charging voltage.

●● Consistent specific gravity. ●● Normal gassing. An excessive amount of charge results in high battery temperature and a reduced battery service life. To obtain maximum service life from a battery, it should be charged and operated within temperature ranges recommended by the manufacturer. Overheating can damage the battery and shorten its normal expected service life. The extent of the damage and service life loss depends on the higher temperature, how often the overheating occurs, and how long the batteries are subjected to high temperatures. A healthy battery charged on a correctly functioning charger will have a 10 to 20 degrees F rise in temperature when fully charged. This temperature rise is affected by several variable factors: ●● Battery age and condition. ●● Battery temperature versus ambient temperature. ●● Charger rate. ●● Charger voltage level. In support of good battery health, the electrical maintenance program for the battery system should include the following: ●● Visual inspection of the battery cells. ●● Verify battery charging performance. ●● Cleaning battery posts and connections. ●● Periodic electrical testing.

VISUAL INSPECTION OF BATTERY CELLS Batteries should be visually inspected under normal float conditions. ●● Inspect the electrolyte level. Flooded cells have translucent or transparent jars, so the electrolyte level can easily be compared to a recommended level that is marked on the cells. ●● Inspect the positive plates. The positive plates are typically the first to wear out and are located toward the center of the jar. They should be dark brown or black. Sparkle is evidence of sulfation or undercharge. Look for cracks, breaks, and pieces hanging on the side. This indicates that the cell may need to be replaced and that other cells may also have a similar problem.

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Maintenance Vol. 1 ●● Inspect the negative plates. The negative plates are thinner than the positive plates and sit toward the outside of the jar. These should have a clean lead color from top to bottom. Pink discoloration indicates copper contamination. ●● Look at the sediment. Inspection of the sediment should provide a general idea of the battery conditional trend from the last inspection. Accumulation of gray material under the negative plates accompanied by sparse black sediment is indicative of an undercharging condition. Excess black sediment under the positive plates with little negative sediment is indicative of an overcharging condition or excess temperature. If excess sediment covers the bottom of the jar, the battery has been cycled heavily or operated at high temperature. ●● Inspect the outside of the jar. A crusty trail or accumulation is evidence of electrolyte leakage. Signs of corrosion on the terminal connections, intercell connections, and racks are also indicative of electrolyte leakage. ●● Verify presence and condition of flame arresters. ●● Verify battery area ventilation is operable and that suitable eyewash equipment is present.

VERIFY BATTERY CHARGING PERFORMANCE There is more to verifying battery charging performance than just recording the voltage levels. ●● Measure each cell voltage and the total battery voltage. The cell voltage value should be in accordance with manufacturer’s published data. Low cell voltage is indicative of a problem with the cell. ●● Verify appropriate charger float and equalizing voltage levels. Charger float voltage is the typical voltage output for a normal charging process. This voltage should be in accordance with the manufacturer’s recommendations but may need to be increased as the battery ages or degrades. An equalizing charge is nothing more than forced overcharge. Applying an equalizing charge periodically brings all cells to similar levels by increasing the voltage to ~ 10 percent higher than the recommended float voltage. This process removes sulfation that may have formed during lowcharge conditions. One method of evaluating sulfation is to compare the specific gravity readings on the individual cells of a flooded lead acid battery. Only apply equalization if the specific gravity difference between the cells is greater than 0.030. During equalizing charge, check the changes in the specific gravity reading every hour and stop the equalizing charge when the specific gravity no longer rises. This is the time when no further improvement is possible, and a continued charge will cause damage. The battery must be kept cool and under close observation for unusual heat rise and excessive venting. Some venting is normal and the hydrogen emitted is highly flammable.

●● Test each cell for specific gravity and temperature. Specific gravity is useful in evaluating charger float voltage, as well as cell internal health. For most UPS-related battery systems, a specific gravity of 1.250 is typical for each cell. If the specific gravity drops by 0.015 to 0.020 from these values, it is usually indicative of inadequate charger float voltage or a problem with a cell holding a charge. Remember, specific gravity should always be adjusted for internal cell temperature differences from 25 degrees C at a rate of 0.001 for every 1.67 degrees C difference. Also, electrolyte levels should be taken into consideration when evaluating specific gravity. Cells with low electrolyte levels typically need water added and, therefore, will have a higher specific gravity.

CLEANING BATTERY POSTS AND CONNECTIONS Before cleaning, note the condition of posts and connectors. Except for a light coating of grease, these should look new. Consider the following colors: ●● Black. This is lead peroxide, indicating an acid leak around the positive post. ●● Green. This is corroded copper, indicating connectors need cleaning and close inspection — they may no longer be serviceable. ●● White. This is lead hydrate, indicating a leak around the negative post. The jars surfaces can be cleaned any time, but cleaning connectors and posts requires opening the battery circuit. If the cleaning requires that the battery be taken out of service without a parallel system, the UPS will not respond to a power loss. Therefore, cleaning should be coordinated with the operator. This following cleaning procedure should be performed when required. ●● Wipe the grease off the posts and connectors, and then neutralize them with a suitable solution like baking soda and water. ●● Clean with a scouring pad or brass brush until clean lead is exposed. Do not clean too vigorously or with a steel wire brush because it may remove too much lead. ●● Degrease the bolts, washer, and nuts. Neutralize electrolyte with a suitable solution. Replace corroded hardware. Replace lock washers, regardless of condition. Use only lead-plated or 316-stainless steel bolts, washers, and nuts. ●● Regrease posts and contact areas of connectors with a light layer of antioxidant grease approved for battery use. ●● Install washers with the sharp side facing away from the connector. If possible, install lock washers on the nut side, not the bolt side. ●● Retorque connections to manufacturer’s specifications. Turn the nut, not the bolt, if possible.

16 ●● Check post-to-post resistance with a micro-ohmmeter. If resistance is high, check the torque — overtorquing degrades the connection. If the torque is correct but the value is high, disassemble and inspect contact surfaces for correct polishing.

PERIODIC ELECTRICAL TESTING In addition to the periodic visual inspections and battery system checks discussed above, specific electrical tests should be performed. The addition of an occasional load test of the battery system should be considered as the battery system ages or other problems are identified. In support of this recommendation for load testing, there are some other more sophisticated testing methods that can and should be performed more regularly to accurately determine battery health. These methods measure the internal ohmic values of the battery or associated cells. Ohmic measurement using a DC voltage is one of the oldest and most reliable test methods for battery systems. A cell’s internal resistance provides useful information in detecting problems and can be used for indicating when a battery or battery cell should be replaced. However, resistance alone does not provide a linear correlation to the battery’s capacity. The increase of cell resistance only relates to aging and provides some failure indications. Rather than relying on an absolute resistance reading, service technicians take a snapshot of the cell resistances when the battery is installed and then measure the subtle changes as the cells age. An increase in resistance of 25 percent over an initial baseline (100 percent) or compared to similar cells indicates a performance drop to about 80 percent. Ohmic measurement using ac voltage is also a generally accepted test method for battery systems. From this method the batteries conductance is derived in terms of mhos, or siemens. A major benefit to using conductance is the ability to calculate a battery’s capacity without performing an extensive discharge or load test. A battery’s measured conductance correlates linearly with its ability to deliver current. As conductance declines, so does a battery’s ability to meet its specified capacity and supply energy. A decrease in conductance of 25 percent over an initial baseline (100 percent) or compared to similar cells indicates a performance drop to about 80 percent.

BACKUP GENERATORS Backup generators should be checked and tested periodically to ensure that they will function as designed and when required. As with the UPS batteries, this testing should include occasional load testing. Backup generators are usually stationary units that are interconnected into the data center’s electrical infrastructure. Automatic transfer switches (ATS) are the most common type of interconnection device used for these applications. An ATS can provide a signal for the generator to start and transfer the load from the normal supply to the generator.

Maintenance Vol. 1 Incorrectly or poorly maintained backup generator sets are more prone to failure and are more likely to fail when needed most. The most common engine failures can be attributed to the starting, cooling, lubrication, or fuel delivery systems. These types of failures can be minimized or prevented by implementing regularly scheduled, comprehensive, engine-generator maintenance and testing programs. The key components of a good backup generation maintenance program include: ●● Regular exercise of the engine generator. ●● Visual inspection of the engine generator, surrounding area, and fluid levels. ●● Fluid maintenance including changing the lubrication, coolant, and fuel on a regular basic. ●● Electrical system testing of the starting system, including the batteries.

EXERCISE THE ENGINE GENERATOR The engine generator should be run under a load on a periodic basis. During dynamic testing engine parts become lubricated, oxidation is prevented, old fuel is consumed, and overall functionality is ensured. Therefore, periodic operation of the generator at a load of at least 30 percent of the nameplate rating for no shorter than 30 minutes should be performed. The generator should be operated for a minimum of one hour at 100 percent of the nameplate capacity at least annually. When testing a stationary unit, testing should be done through the ATS to ensure the entire system works correctly. If it is not possible or practical to use a site load for the test, a load bank should be used. Sometimes problems only become noticeable during operation; therefore, it is important that maintenance personnel remain attentive for unusual circumstances, e.g. abnormal sights, sounds, vibration, excessive smoke, or changes in fuel consumption.

VISUAL INSPECTION The area around the engine generator should always be kept free of debris to ensure sufficient ventilation during operation; therefore, periodic inspections should be performed. The radiator should be cleaned regularly to remove any dust and/or debris, taking care not to damage the fins. These inspections should also be performed to ensure fluids, such as oil and coolant, are not leaking. Further, there should be inspections of the exhaust system, including the manifold, muffler, and exhaust pipe with all connecting gaskets, joints, and welds being checked for potential leaks. Also, check that the engine jacket water heater is operating correctly by monitoring the discharge temperature. The fuel delivery system should also be inspected periodically for leaks and correct pressure during exercise. This includes checking fittings and connections; tighten them as needed. Drain

Maintenance Vol. 1 and clean fuel filters on a regular basis. Where applicable, examine charge-air piping and supply hoses for leaks, holes, and damaged seals. The fuel system and charge-air cooler should also be free of dirt and debris.

FLUID MAINTENANCE Fuel maintenance is another important aspect of generator maintenance. Diesel fuel degrades over time, separating and even growing microbiological organisms. A fuel sample, taken from the bottom and from the supply line, should be visually examined monthly. The fuel should look like new fuel; otherwise it should be filtered or replaced. Fuel tanks should be sized so that the fuel is turned over on a regular basis. As a rule of thumb diesel fuel should be turned over or replaced on an annual basis. This maintenance should also include fluids, such as oil and coolant, are at the correct mix and levels.

ELECTRICAL SYSTEM TESTING Electrical connections should be tight and free from corrosion. Batteries should also be checked to make sure they are fully charged. The batteries must be tested under load. Simply checking the voltage is an inaccurate method of testing power, as batteries change internally over time. Where appropriate, check the specific gravity and electrolyte levels. All engine wiring should have tight connections and be free of corrosion or damage. Check with your generator manufacturer for their recommended battery and wiring practices, cleaning agents, and solutions.

SUMMARY Key electrical systems for most data centers are the UPS systems and their battery systems and the backup generation systems. The UPS systems are designed to provide primary power to downstream equipment with immediate switching to battery systems with loss of power. The UPSs and battery systems are typically designed to keep the data center running long enough for a seamless transfer to an alternate power source like a backup generator. The battery is by far the most vulnerable and failure-prone part of a UPS system. Because of this, much time and effort should be allocated to maximizing a battery’s reliability and life within the data center. At a minimum, annual testing, verification, and inspection of a battery system should be performed. Backup generators should also be inspected and tested periodically to ensure that they will function as designed and when required. As with the UPS batteries, this testing should include occasional load testing.

17 Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

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TESTING ROTATING MACHINERY SYNCHRONOUS ROTOR WINDING COMMON ELECTRICAL TESTS NETA World, Summer 2013 Issue Vicki Warren, Iris Power LP Since operating voltage of most insulated rotor windings is less than 1000 V, the recommend test voltage is 500 V DC. Per IEEE 43, the minimum acceptable values are 100 megohms for formwound armatures and 5.0 megohms for random wound types when corrected to 40 degrees C.

When the motor application requires low speed, power-factor control, high-operating efficiency, direct connection to lowspeed equipment or high horsepower, a synchronous motor may be appropriate. The primary difference between a squirrel-cage induction motor and a synchronous motor is the rotor construction. A synchronous rotor winding has insulated pole windings, and, if it has laminated poles, a damper winding embedded in the pole tips. The damper winding is similar to that of a squirrel-cage rotor type. It is used during starting to create asynchronous torque and to damp out oscillations from an unsteady load during normal operation. If the motor has solid steel poles the pole tips act as a crude damper winding for starting. The field winding is excited from a dc source, which in modern machines is a brushless exciter and provides additional electromagnetic flux to lock the stator’s rotating field to the rotor. The two most common types of rotor designs found in mediumto high-voltage synchronous motors are salient pole and round (or cylindrical) rotor. The round rotor design is used for two- pole motors because it has the ability to withstand the very high “g’ forces imposed on the rotor winding by centrifugal forces. On the other hand for four poles and above, the salient pole design is suitable for motor ratings up to at least 60 MW. This article describes some of the common tests used for salient pole rotor windings in synchronous motors.

INSULATION RESISTANCE This test should be performed in accordance with IEEE Std. 431 to confirm that the rotor winding is clean and dry and that there are no major flaws in its ground insulation on the coils and leads.

The test voltage should be applied for one minute, and the insulation resistance recorded at that time. It may take a number of cleaning and baking cycles to bring the insulation resistance up to an acceptable value. Carbon should be removed before performing this test. If a winding does not have an acceptable insulation resistance reading, it is inadvisable to perform electrical tests that can potentially stress the insulation (such as the growler, highpotential or surge-comparison tests). Caution: A successful 500V IR test between the rotor winding and shaft should be performed before conducting additional tests

FIELD WINDING RESISTANCE The resistance of the armature winding shall be measured between the leads to the brushgear assembly, with all brushes down. This measurement shall be taken with a resistance bridge, digital microhmmeter, or low resistance digital ohmmeter having four-digit accuracy. The recorded values shall be within 2.0% of the prerepair, or factory test values.

ROTOR VOLTAGE DROP The voltage drop test is used to identify shorts between turns in dc field coils of salient pole rotors. It can be performed by exciting the coils with AC or DC, then measuring the voltage between adjacent turns. The equipment required for this test is an AC or DC source and an accurate voltmeter (or millivoltmeter) and current meter. The energizing source must be capable of providing enough current to produce a measurable voltage between turns. For this reason an ac source is preferred. A low voltage (usually 120 V) ac voltage is applied across the complete winding and the voltage across each pole winding is measured. Since the impedance of a pole winding reduces much more than its resistance when a turn short is present, if there are turn-to-turn shorts, the ac voltage drop will be significantly less. If no shorted turns exist, the measured voltage across each coil should be within the tolerances given in Table 1.

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resonant damped sine wave response is stable as the test voltage is increased, the coil does not have any shorts. When the resonant response or ringing increases in frequency or decays very rapidly, a shorted turn is likely in the coil.

Fig. 1: Low-cycle Fatigue (Salient Pole) If the motor has brushless excitation, then the field winding has to be disconnected from the rotating rectifier for this test. One limitation of this test is that it may not detect turn shorts that are only present when operating centrifugal forces are present. This may be overcome by mounting the rotor horizontally and performing the test with it in four positions, 90 degrees apart. When there are significant differences in the iron distribution around the coils, the results of an AC drop test may be misleading. In those cases, a DC drop test is useful to determine whether the AC results are due to shorted turns or interaction with the iron. Using higher frequencies (120 hz to 400 hz) can be very beneficial in that the current requirements are greatly reduced. DROP TEST

TOLERANCE

AC

± 10% of the average voltage drop

DC

± 5% of the average voltage drop

Table 1: Voltage Drop Test2 When the condition of pole windings is being considered, an alternative test can be used where the power factor or losses in the coils are measured. This is a comparative test where the power factor or losses in each coil are compared. When a coil is identified with higher losses, it likely has a shorted turn. Equipment requirements for the power-factor test are a power supply and a watt meter or pentameter capable of measuring low power factors.

SURGE TEST FOR SHORTED TURNS The surge test may detect shorted turns, ground faults, and high resistance connections in salient pole and wound rotor windings. This test requires the same type of surge tester as is used to detect shorted turns in multi-turn stator coils. Since a complete winding will have a large number of turns to be effective, this test should be performed on individual coils. The test involves injecting fast rise-time pulses with a peak voltage magnitude indicated in Table 2 into each end of the coil and overlaying the resulting waveforms to check for similarity in accordance with IEEE Std 5221. The pulse rise time and repetition rate produce a resonant response in the coil. A series of pulses is injected into a coil, and if the

Fig. 2: Fatigue and Thermal Damage (Salient Pole) Comparison of surge voltage waveforms for all coils of the same type can be effective, but may not detect shorted turns if the impulse dissipates too quickly or only exist when under the influence of centrifugal forces during rotor operation. When comparison is made, the responses should match exactly if the coils do not have shorts. If there are differences in the waveform frequencies, an experienced operator can determine the type of fault present. WINDING TYPE

PEAK VOLTAGE

New

10 x Field Winding Rated Voltage

Refurbished or Repaired

6 x Field Winding Rated Voltage

Table 2: Surge Test for Shorted Turns2

HIGH POTENTIAL TEST This test should be performed on all new field windings and those that have been repaired. A 1.0 minute test shall be performed at the voltage levels indicated in Table 3. When a dc high potential test is performed, usually in voltage steps, the result of each step must be assessed (IEEE 954). This means plotting the curve of insulation resistance (or leakage current, in microamperes) versus applied voltage. If the plotted value at any step begins to trend upward, indicating excessive nonlinear current (or drop in insulation resistance in a nonlinear manner), the test should be aborted immediately.

Fig. 3: Mechanical Damage to Interturn Insulation (Salient Pole)

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AC TEST VOLTAGE

DC TEST VOLTAGE

1000 V

1700 V

New Windings > 240 Volts

1000 V + (2 Times Rated Winding Voltage)

1700 V + (3.4 Times Rated Winding Voltage)

Refurbished Windings > 240 Volts

600 V

1020 V

Refurbished Windings > 240 Volts

[1000 V + (2 Times Rated Winding Voltage)] x 0.6]

[1700 V + (3.4 Times Rated Winding Voltage)] x 0.6]

New Windings < 240 Volts

Table 3: Field Winding AC and DC High Potential Test Values2

REFERENCES 1 I EEE Std. 43-2000, IEEE Recommended Practice for Testing Insulation Resistance of Rotating Machinery 2 I EEE Std. 522-2004, IEEE Guide for Testing Turn Insulation Testing of Form-Wound Stator Coils for Alternating-Current Electric Machines 3 Electric Power Research Institute’s (EPRI’s) Large Electric Motor Users Group (LEMUG) Repair and Reconditioning Specification Guidelines for AC Squirrel-Cage and Salient Pole Synchronous Motors with Voltage Ratings of 2.3 to 13.2 kV Report 1000897 (dated July 2008) 4 I EEE Std. 95-2002, IEEE Recommended Practice for Insulation Testing of AC Electric Machinery (2300 V and Above) with High Direct Voltage. Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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MAINTENANCE TESTING OF WIND FARM DISTRIBUTION SYSTEMS A NO-OUTAGE APPROACH NETA World, Summer 2013 Issue Don Genutis, No-Outage Electrical Testing, Inc.

INTRODUCTION Wind farm electrical distribution system design is quite unique in comparison to typical power plants, and these systems, therefore, require a nontraditional maintenance testing approach. This article examines how a cost effective, no-outage testing program can be implemented to reduce failures and increase reliability.

SYSTEM DESIGN Wind farm distribution design can vary but in the US the typical design utilizes low-voltage wind turbines to generate power. The low-voltage output is connected to a pad-mounted, fluid-filled distribution transformer located near the base of each turbine tower which steps up the voltage to 34.5 kV. The output of the transformer is then connected to the next turbine transformer using a three-wire, direct-buried, underground cable segment. Molded-cable accessories are used to terminate the cables to the transformers. Additional transformers are successively cascaded on the same string, and the cable load increases as it makes its way towards the collector substation. The load continues to increase until the maximum standard cable size is reached. The last segment of the string is usually quite lengthy in order to reach the substation, since the strings are far apart physically and thus often require several splices. Several strings typically terminate into one large collector substation which then steps up the voltage to subtransmission or transmission voltages. These substations consist of various designs but can include 35 kV switchgear or substation breakers, large power transformers, lightning arresters, instrument transformers, and often high voltage breakers with sophisticated protective relaying.

PAD-MOUNTED TRANSFORMERS The transformers located at the base of each turbine are critical to the operation of the string. If the transformer located near the collector substation fails, the entire string is down until repairs can be performed which often requires replacement. If a spare is not available, it may be best to replace the damaged transformer with a transformer located as close as possible to the far end of the string, thus getting as many turbines as possible back in operation.

The best overall way to ensure the reliability of these transformers is to perform regular fluid testing in accordance with the NETA Standard for Maintenance Testing Specifications. These relatively routine tests reveal a great deal of information related to both the condition of the fluid and internal transformer components in a cost effective manner.

CABLES The medium-voltage cable system is next to be considered. Ideally, a robust acceptance testing program including partial discharge testing in accordance with the NETA Standard for Acceptance Testing Specifications would have been performed so that problems are much less likely. However, failures will occur because of many factors, and regular testing is essential to maintaining integrity. A cable failure near the collector substation can take down an entire string the same as a pad-mounted transformer failure can, but it is likely that the cable failure will take much longer to repair, especially if it occurs somewhere along the final lengthy segment route to the collector substation. Failures here usually occur at splices and require bringing in an outside specialty splicing contractor equipped with cable fault locating instruments to precisely determine the exact failure point. Once identified, excavation would be necessary before repairs can begin. Although regular on-line cable partial discharge testing may be effective for ensuring good cable condition, it may be better to consider using off-line VLF partial discharge cable testing to evaluate the condition of the segment nearest the substation as the long cable lengths can make on-line PD location difficult. Besides the splices, cable system failure is common at the terminations which connect to the pad-mounted transformers. The condition of these terminations can be determined accurately by on-line cable PD test methods using radio frequency sensors. Unfortunately the turbine output converter electronics create massive noise signals that interfere with the on-line PD test results, so it becomes necessary to temporarily take a string of turbines off-line while this test is performed. Performing online cable PD testing also has the advantage of testing the other components immediately connected to the terminations including the transformer bushing well inserts, surge arresters, the internal transformer switch and bus insulation, and the transformer itself.

22 Recent testing was performed at a major wind farm in Minnesota using handheld PD testing instruments equipped with transient earth voltage (TEV) sensors. The TEV sensor was placed on the outside of the pad-mounted transformer enclosure as shown in Figure 1 to obtain an immediate health condition indication. The TEV test data was then compared to parallel on-line cable PD test results and found to correlate very well as shown in Figure 2. These results are very encouraging because it proves that terminations and all other connected components within the enclosure can be routinely and efficiently tested nonintrusively using the TEV method. If a problem is detected using the handheld detector, additional testing using on-line or off-line testing methods can be used to pinpoint the precise defect location so that appropriate repairs can be planned well before complete failure occurs.

SUBSTATIONS Collector substations are usually similar to traditional generation substations, so typical no-outage testing technologies usually apply. Outdoor open bus connections should be inspected with infrared imaging equipment and RFI surveys should be performed with antenna-based instruments to detect partial discharge activity inside bushings, substation breakers, instrument transformers, lightning arresters and insulators. External insulation surface tracking can be detected using airborne ultrasonics, corona cameras or RFI techniques. Outdoor switchgear insulation condition should be surveyed using ultrasonic and TEV sensors, while infrared cameras should be used to inspect connection integrity. Finally, transformer fluid should be sampled and tested regularly, and high voltage SF6 breakers should have gas samples taken and tested regularly as well.

CONCLUSION Wind farm distribution system design offer some unique differences compared to traditional power plant design, and these differences present some unique maintenance testing challenges. Employing a maintenance program consisting of no-outage testing techniques will minimize outages and provide the owner with increased reliability. Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

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WIND FARM COLLECTOR SYSTEM – PREDICTIVE MAINTENANCE PRACTICES NETA World, Summer 2013 Issue Paul Idziak, Shermco Industries

Power generating facilities, and more specifically wind power generation facilities, avoid downtime to maintain consistent output of their prized product: electricity. Some of the facilities will stay on line for extended time frames skipping recommended maintenance cycles until an outage occurs. Within the wind farm owner’s key performance indicators, availability and production are at or near the top of the list. So how can wind farm owners perform necessary maintenance on their collector system and reduce downtime? How can wind generation sites develop an acceptable maintenance strategy using national consensus standards?

MAINTENANCE METHODOLOGIES Reliability-centered maintenance (RCM) and predictive maintenance (PdM) are two key maintenance concepts used to reduce downtime while providing the level of maintenance needed to keep generators on line and producing power. Developing a maintenance program based on these two concepts is not an easy task and will be revised constantly. A task that is even more difficult is finding the personnel with the needed skills and training to perform the maintenance. Figure 1 illustrates the issues the industry faces with a rapidly aging workforce. Where are skilled replacement workers going to come from?

process is to identify how the equipment is operated, define its purpose, and write a failure mode effects and criticality analysis (FMECA). The second part of the process is to determine the appropriate maintenance tasks for the identified failure modes in the FMECA. Once those tasks are identified for all elements in the FMECA, the resulting list of maintenance tasks is given specific maintenance intervals and bundled together. RCM reduces costs by concentrating on the monitoring and correction of root causes of equipment failures (also known as root cause analysis). This will help establish minimum levels of maintenance, point to required changes to operating procedures, and guide the development of capital maintenance regimens and plans.

Predictive Maintenance (PdM) PdM is the process of evaluating the condition of equipment by performing periodic or on-line continuous equipment monitoring. PdM is based on performing the right maintenance at the right time using on-line continuous monitoring techniques, whereas preventive (or phased) maintenance (PM) is performed strictly based on time. PdM is used as a part of a RCM program. One example of PdM is the use of partial discharge/acoustic emissions testing. The detection equipment is installed on cables or equipment and continuously monitors the system. Partial discharge (PD) is a localized electrical discharge that only partially bridges the insulation between conductors. PD is a phenomenon caused by imperfections inside cable insulation resulting from cable aging, thermal, mechanical, and electrical stresses, or manufacturing defects.

MAINTENANCE PLANNING Numerous factors need to be considered while developing an RCM program. Some of these factors include: ●● age of the electrical equipment ●● equipment condition ●● environment Fig. 1: Percentage of Workers by Age Range

Reliability Centered Maintenance RCM enables sites to monitor, assess, predict, and generally understand the working of their physical assets which are their generators, strings, and substations. The initial part of the RCM

●● loading ●● criticality ●● reliability ●● requirements of the power purchase agreement with local utility

24 Long-term trending, auditing, and staying current with changes in standards and methods of testing and evaluation must also be considered. These programs should be based on national consensus standards to bring credibility to the program. Sources such as NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, the InterNational Electrical Testing Association (NETA) MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, and several IEEE standards should be referenced. The NETA testing standard also offers guidelines for the frequency of maintenance tests within Annex B of the document. Figure 2 shows some available standards, although there are many more that should be consulted.

Maintenance Vol. 1 qualified contractor with an industry-recognized electrical testing accreditation such as NETA Accredited Companies will help ensure that a qualified and competent testing organization will perform the needed testing. Regardless of which contractor is chosen, due diligence to the testing contractor’s capabilities and qualifications is essential. The wind generation site’s owners and third party contractors need to be cautious of the arc-flash hazard particularly on padmount transformers, wear proper PPE, and employ a qualified safety backup, if necessary.

THE GENERATOR, COLLECTOR, COLLECTOR SUBSTATION AND INTERCONNECTION SUBSTATION Infrared scanning (IR) accurately identifies the presence of abnormal heat in electrical and mechanical systems which can help predict equipment trouble. The infrared (thermographic) survey gives a detailed thermal and photographic record of any problems detected, so action can be taken before breakdowns occur. Infrared inspections routinely discover issues with loose cable and control wire terminations, electrical connections, and electrical insulation. This same technology can be used in the turbine as well as the collector system to identify thermal issues involving electrical components such as the step-up transformer insulating oil flow/ level, collector cabling connections/terminations, and generator circuit breaker connections.

Fig. 2: NETA, NFPA and IEEE all have Standards that will Assist in Developing a Maintenance Program

IN-HOUSE OR CONTRACTED PERSONNEL? Monthly and quarterly checks on the collector system make up part of the PdM/RCM program. These tasks can be performed by in-house personnel if they are qualified or by a third party contractor if the work is beyond the abilities and training of the in-house personnel. On-line testing can present additional risks and hazards with which in-house personnel may not be familiar. However, the overall impact to operations is minimal, and typically outages and down-time are not required.

Infrared cameras have come down in cost significantly over the last few years, so many sites are purchasing cameras for in-house, routine scanning of the equipment. Training and qualifying the parttime thermographer is usually performed by the manufacturer’s representative in a few hours. Infrared scanning of these machines and collector equipment on at least an annual basis is extremely important. If the reliability requirement is higher than average an infrared survey can be performed more often. Biannual or even quarterly infrared surveys are often justified. Figure 3 is an example of an infrared image. ANSI/NETA MTS-2011 provides infrared guidelines in Table 100.18.

In order to have a successful PdM program the wind generation site must employ trend analysis of the data. By trending such factors as generator heat, vibration, and oil data patterns over time, it is possible to determine when issues are beginning and plan for the required maintenance long in advance of failure. This results in minimum downtime and disruption to generation.

QUALIFYING THE TESTING CONTRACTOR Technicians performing electrical tests and inspections should be trained and qualified to understand the hazards associated with operating, switching, and maintaining electrical power equipment. Utilizing an independent, third party contractor can provide the necessary expertise required to perform on-line testing, interpret and trend the data, and create an RCM program. Selection of a

Fig. 3: Infrared Image of a Pad-Mounted Transformer. Note the temperature variation between C2 and the other phases

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Maintenance Vol. 1 An infrared camera is unable to see electrical corona, which is the ionization of the air surrounding a high voltage component. Several factors can affect a conductor’s electrical surface gradient and its corona performance, including conductor voltage, shape, diameter, and surface irregularities, such as scratches, nicks, dust, or water drops. Corona cameras can detect insulation and connection issues associated with the higher voltage equipment in the collector substation and interconnection substation by detecting corona emissions. Annual corona scanning is the minimum recommended frequency for detection of corona issues. Corona scanning combined with any ultrasound and partial discharge analysis yields valuable data about the health of the insulation system.

Transformer Insulating Oil Sampling and Analysis The majority of power transformers in operation at wind generation sites are filled with mineral oil. The primary function of the oil is to provide a high dielectric insulating material and provide an efficient method of cooling to dissipate heat. The effectiveness of the oil as an insulating material is reduced as the moisture level increases, while cooling is reduced as the oil deteriorates. Paper insulation absorbs moisture from the oil. The balance of moisture between the oil and paper insulation is affected by temperature and is constantly changing. Oil quality and dissolved gas analysis (DGA) tests are tools to determine the suitability of the oil for continued service. DGA measures the levels and ratios of dissolved combustible gasses in electrical insulating fluids. It is a very effective tool to diagnose potential problems in the transformer caused by loose connections, overloading, arcing, hot spots, and case or seal leaks that let moisture or air into the unit. Transformer insulating fluid sampling, testing, and analysis is another inexpensive line item in the maintenance budget. The average cost for oil quality tests and DGA ranges from $150.00 to $250.00 dollars per sample plus the cost of obtaining the sample. The variance in prices is based on which tests are included in the testing program. It is recommended that collector transformers be sampled on an annual basis, while the substation transformers should be tested twice annually, and possibly even three times per year, based on the number of load tap-changer operations. Figure 4 shows a typical oil-filled, pad-mounted transformer.

THE COLLECTOR SYSTEM Partial Discharge (PD) Sampling and Analysis Because a significant percentage of cable failures are associated with partial discharge, cable systems are typically tested after installation for manufacturing defects, improper installation and other related problems that can cause partial discharge. On-line PD testing provides crucial information on the integrity of an electrical system on a continuous basis. Using the appropriate equipment and techniques, partial discharge can be located, measured, and recorded, identifying cables, switchgear, and transformers that are beginning to fail.

On-Line Partial Discharge Testing On-line PD testing is performed while the equipment is energized at normal operating voltages. At various times a snapshot sample is pulled and sent to a third party expert for analysis. The testing is conducted during real operating conditions, under typical temperature, voltage stresses, and vibration levels. On-line PD is a nondestructive test and does not use overvoltages that could adversely affect the equipment. On-line partial discharge testing is relatively inexpensive compared to off-line testing that requires interruption of service and production. PD is most often used to detect and locate accessory and cable defects, but it can also detect failures in other areas (i.e., switchgear and bus). Similar hazards exist as discussed earlier in the on-line generator testing discussion. Direct interaction of personnel with an energized and operating generation system is extremely hazardous and the qualifications of the testing contractor or employee cannot be overstated. Prior installation of PD sampling boxes or cable/equipment test access panels will reduce the risk of exposure and expedite the on-line testing program. These boxes allow the routing of the cable/equipment shields or RF current transformers leads outside the equipment and mitigates exposure to the electrical hazards. They create a low risk environment to perform the sampling.

SUMMARY Just like any power generating facility, electrical maintenance of the wind farm is essential to high performance. While it is difficult to create and implement a RCM program, national consensus standards such as ANSI/NETA MTS 2011 can guide the wind generation site owner. Implementing predictive maintenance strategies are important to reducing downtime and maintenance costs. Even more important is maintaining the RCM schedule and comparing results with baseline values. By performing a predictive maintenance plan, the generation site will be able to take minimum planned outages to perform maintenance instead of experiencing expensive, unplanned outages. A predictive maintenance plan will also ensure the

Fig. 4: Oil-Filled, Pad-Mounted Transformer

26 safety of the site’s personnel, along with maintaining compliance requirements on the site. A qualified third party contractor will be able to perform the required testing and provide recommendations for the equipment when in-house personnel do not have the expertise.

REFERENCES O’Neil, Jim, “Industry Trends Impacting Maintenance & Testing of Electrical Assets” Keynote address at 2013 NETA PowerTest Conference. Paul Idziak is the Director of Renewable Energy Services of Shermco Industries, a leader in maintenance and repair of electrical machines and electrical power systems in the renewable energy industry. Paul’s responsibilities include the promotion of safety and reliability-centered repair and maintenance practices of renewable energy systems to include wind, biomass, geothermal and wind energy generation, collection and substations. Paul is also a qualified electrical worker, trainer, and consultant working with OEM’s, O&M’s, and electrical construction contractors that provide reliability-centered construction and repair services.

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WIND TURBINE GENERATOR ELECTRICAL FAILURES NETA World, Summer 2013 Issue William Chen, TECO Westinghouse Motor Company

Utility scale wind turbines have been a growing part of the global landscape for 20 years or more, but the industry is still maturing. The application for the generator itself is demanding, and the conditions are varied and complex. A quantitative review of the failure modes of over 1200 wind turbine generators repaired or replaced from 2005 to 2010 has uncovered that fewer than half of the failures were electrical in nature and the majority of those were due to mechanical failures of the insulation support structure that probably would not have been located using traditional testing methods. Many of the failures appear to be of a serial nature due to inadequate original design of the machine and/or the insulation system. These generators are exposed, at least in some part, to the typical voltage irregularities and mechanical stresses of any machine that operates 100 meters in the atmosphere in a wide variety of weather conditions. However, they are also sometimes affected by poor power quality from the IGBT based converters used in most turbines. These failures could result from voltage stresses created by the converter in the turbine or from neighboring turbines or, as has been suggested, even from neighboring wind parks. Several common failure modes for these generators have been identified, many of which can be traced to identifiable root causes. However, many failures remain difficult to trace as minor failures can lead to catastrophic electrical failures not directly related to the root cause. Understanding the types of failures and how often they might occur in a fleet of turbines is instrumental to developing a proper maintenance procedure and testing regimen. By reviewing these failures, we have been able to isolate the electrical material failures from the pure mechanical failures. The study covered damaged generators from a wide variety of manufacturers and represented a fairly reasonable sample of the industry. Three categories were set up based on the nameplate rating of the machine. As turbines have generally gotten larger as the industry developed, it can be assumed the largest category represents the more current designs. The failure modes identified represent the best estimate of the initial failure, keeping in mind that the root cause might be varied. The modes collected were: ●● Rotor insulation damage (strand/turn/ground) ●● Stator insulation damage (strand/turn/ground) ●● Bearing failures

●● Rotor lead failures ●● Shorts in collector rings ●● Magnetic wedge failures ●● Cooling system failures ●● Other mechanical damage Earlier designed, smaller machines show a high number of failures in rotor insulation. These are due to both electrical and mechanical failure of the conductors and the failure of the banding as designed. Many stator winding failures were actually due to contamination and issues with under designed bracing. The occurrence of bearing failures in generators between one and two MW is dramatically illustrated. These generators are generally more robust than their antecedents, but proper installation and good maintenance practices are critical to good reliability. The root cause of the majority of these failures is improper maintenance, although early failures could have also resulted from transient shaft currents. Very few insulation failures were recorded, and most were due to overheating issues created by improper cooling system design. Most wind energy generators have output voltages of 550-690 V ac. Some in the 1.5-2 MW class are high voltage machines ranging from 12-13.8 kV ac, but no statistics are available regarding specifically HV related failures. Again, in the class of generators greater than 2 MW, the bulk of the failures are from bearings for the same reasons as the 1-2 MW machines, but there is a dramatic rise in stator failures resulting from the loss of magnetic wedges utilized to improve the size/ output functionality of the generator. Where this failure mode has been seen in industrial applications, it is almost a universal failure point across manufacturers in this class of turbines. Based on new, unpublished data being compiled by Dr. Peter Tavner and his team at Durham University, Durham, UK, bearing damage is the leading root cause of failure in both wind and industrial rotating electrical machinery. In fact, with these large studies, there is actually little variation in types of major failure, only in specific machine design areas of vulnerability.

COMMON INSULATION FAILURES Rotor Banding It is thought that many of the older wind turbines and generators were originally designed to operate at 50 Hz, but were placed in

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service in North America at 60 Hz without proper redesign based on the increased electrical and mechanical stresses. Catastrophic failures were very common. This has been rare in the newer generator designs, and several redesigns of the older machines appear to have alleviated the problem. For remanufacturing purposes, most have also been redesigned using additional banding and other reinforcing materials, and this failure is no longer common among remanufactured machines (see Figures 1 and 2).

loosely in the slot, the wedge is very dependent on the resin to hold it in place. The ferrous nature of these wedges allows for oxidation where moisture and especially corrosive salts are present, and this may have contributed to the bond failures (see Figure 3).

Fig. 3: Missing magnetic wedges

Cooling System Failures

Fig. 1: Rotor Banding Failure

Since most wind generators are typically enclosed inside a notso-spacious nacelle along with many other components, ventilation can be hindered. Both rotor and stator windings need adequate ventilation in order to keep them cool and functioning correctly, especially if air-cooled design is used. Poor ventilation might lead to higher winding temperatures which in turn reduces the service life of those generators. Therefore, in addition to proper design considerations, the cooling/ventilation system should also be inspected and maintained on a regular basis.

Bearing and Rotor Lead Damage

Fig. 2: Rotor Failures

Conductive Wedges The loss of conductive slot wedges results in both grounding failures due to the conductive nature of the wedge material as well as mechanical damage to the coils. Both penetration of the coil by shards of wedge material as well as loose coil damage have been observed as causes of immediate and dramatic failures. As a general observation, several additional styles of generators have surfaced with this problem since the statistics were gathered, and this is becoming a serious problem for the industry. It is assumed that since the wedges have a high ferrous content, they react to the revolving electrical fields and will vibrate or shift under the influence. All of the machines studied appear to be manufactured using very low viscosity epoxy or polyesterimide resins. If the coil dimensions and slot filling materials are designed to fit too

A characteristic design for the popular double-fed induction generators (DFIG) is that the power converter is connected directly to the rotor winding through lead wires that pass through the hollow rotor shaft over which the bearing inner housing is fitted. The coupling effects of these and other harmonics can create an electrical current that passes along the shaft and through uninsulated bearing creating premature bearing failures. Also, peak voltage spikes generated from converters can reach several times the rated voltage and could cause flashover at the rotor leads. These effects require that the shaft grounding system design be more robust than is normally required for machines designed for normal operating conditions. In addition, because the entire generator is mounted at an angle from the horizontal plane, additional thrust force might act on the bearing structures. All these lead to higher bearing temperatures, or even bearing failure, which create enough heat to severely damage rotor leads, leading to eventual generator failures. Improper lubrication and normal bearing failure modes can also create this type of failure.

Under-designed Materials and Systems Extreme hot or cold conditions can dramatically affect machine service life. Unfortunately, those temperature extremes are quite common in many areas of the world where the wind blows the

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Maintenance Vol. 1 strongest. In addition, as opposed to most traditional motor/generator operations, wind generators experience frequent load changes due to the very dynamic nature of wind. As a result, those generator windings are often subjected to higher thermal cycling and mechanical stresses. Insulation materials, winding structures (such as lead connection/crimping), carbon brushes, etc., all sustain higher stresses and require higher standards in order to maintain their design integrities during operation. Therefore, extra allowance for all those conditions must be taken into consideration during the design process.

Catastrophic Failure Due to Surges Voltage irregularities, either from traditional grid related sources or from converter failures have continued to create issues with the generators. Proper protection from these problems as well as effective grounding of electrical system is critical. These phenomena might also contribute to the loss of magnetic wedges described earlier. As mentioned previously, many wind generators are connected to the grid through power converters. Although the rated operation voltage of the rotor winding is generally low (such as 690 V for most DFIG machines), those power converters will generate much higher peak voltage spikes (up to 2.5 kV peak and several kHz switching frequency). These greater stresses affect rotor winding insulation (including turn-to-turn, phase-to-phase, and main insulation) significantly. Proper design allowance and adequate protection should be implemented in order to achieve the optimal service life.

Contamination Issues Typically, wind turbines are operated in remote and difficult-tocontrol environments, and they typically are not totally enclosed. At those high elevations (many towers are around 100 meters high) and with unpredictable wind directions, moisture, dust, and sand can penetrate into the nacelle or even inside the generator frame. As a result, failures will occur. Proper materials and processes should be selected during the design and manufacturing of these machines in order to reduce or even eliminate most problems. Of course, regular checkups and maintenance are key elements of strategies to prolong service life. Another issue to be addressed here is the effect of saline contaminated environments such as those of offshore or near shore. Those corrosive conditions are generally bad for materials with ferrous content such as the generator frame, steel core laminations, or even the magnetic wedges. If left unprotected, those oxidation processes might lead to possible problems or even rapid failures; therefore, an adequate protective coating should be used to help for protection. Proper maintenance is critical to all rotating machinery. However, from some industry sources, incorrect lubrication of bearings leads to more service calls and catastrophic failures than all other factors combined. Following the manufacturers’ suggestion to use the correct lubricant is quite important. In addition, all lubrication

equipment needs to be monitored, serviced, and properly adjusted on a regular basis to assure predictable performance. Although lubrication overflow on the windings may not be damaging on its own, it does attract other contaminates, including conductive particles that may shorten the expected life of the system.

CONCLUSIONS Several of the failure modes of wind turbine generators might be trended and predictable, but most seem to be immediate and catastrophic. New monitoring schemes and more advanced vibration testing or even visual inspections might be required to adequately predict potential failures in time to schedule repairs. As the size of wind turbine generators continues to grow from the current 3.0 MW to the proposed 10-12 MW offshore behemoths, new challenges will be encountered involving the design and execution of proper electrical insulation systems. Larger machines, although they seem to be more robust and reliable, actually suffer from different failure modes but not necessarily fewer failures. The mechanical stresses of the newer machines are higher than in the first few generations of turbines. Some of today’s 2.5 MW generators are not much larger than the 660 kW machines of five years ago. High-voltage, synchronous generators with output voltage of up to 13.8 kV will bring their own issues although they have had a long successful history in industrial and commercial applications. Whatever direction the industry takes in the next few years, predictive and proactive maintenance will be required to assure profitable operations. William Chen holds degrees in material science and chemical engineering from the University of Utah and the University of Texas at Austin, respectively. He joined TECO-Westinghouse Motor Company in 1996 and has extensive experience in several departments. He is currently an Advanced Insulation System Engineer at its R&D Headquarters. William specializes in insulation development, qualification, and testing for large motors and generators and is a member of several IEEE standards working groups.

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UP-TOWER ELECTRICAL TESTING OF WIND TURBINE GENERATOR STATOR AND ROTOR MAIN WINDINGS NETA World, Summer 2013 Issue Kevin Alewine and Casey Gilliam - Shermco Industries As the wind turbine fleet in North America ages and the equipment moves out of the manufacturer’s warranty period, owner/ operators are beginning to learn how to maintain the turbines to optimize their uptime performance. Wind turbines are, by their very nature, a series of mechanical and electrical components (see Figure 1). Although the root causes of many wind turbine generator failures are mechanical in nature (alignment, vibration, lubrication, etc.), some are electrical in nature, and normal end-of-life events nearly always result in dielectric breakdown of the electrical insulation or related supporting materials. Given the wide variety of generator types and sizes currently in use, it is difficult to establish predictable failure modes across the industry, but certain tests can be performed while the unit is in service (on and off line) that will prove useful to the maintenance crew in predicting and minimizing downtime in order to improve profitability.

Fig. 2: Tools, equipment, and technicians must all travel to the top of wind turbines to perform work

WHAT IS ACTUALLY BEING TESTED?

Fig. 1: The mechanical heart of the wind turbine: The Gear Box A standard insulation-resistance test is the normal protocol for the wind turbine technician, but what are they looking for and what do they do if they find it? In fact, is it even a helpful test on an operational wind turbine generator? And when you are 80-100 meters in the air, the electrical test results to determine overall health of the machine become even more important (see Figure 2). This article helps explain what testing might be performed as part of scheduled maintenance and what further testing can be done to determine whether the status of a generator is at a critical point. It is typically better to identify issues as early as possible and schedule a generator change out at a convenient time rather than undergo an unexpected and possibly spectacular generator failure. Let’s start with a quick review of what we are testing – the electrical insulation system of the generator.

Most wind turbine generators operate in the low-voltage range (less than 1000 volts). The windings of the generators come in two styles: random-wound (using many small, round conductors in parallel) or in form-wound coils where larger rectangular conductors are preformed and, normally, insulated with ground wall insulation before being inserted into the stator or rotor (see Figures 3 and 4). Random-wound machines normally use enamel insulated conductors which are wound into coils and inserted into slots which are already insulated with an appropriate high temperature paper or laminated material. Phase insulation of the same or similar material is placed between the coils in the slots as well as on the overhanging portions. The coils are then wedged into place, reinforced with cords and blocking materials, connected, and finally varnished with a high temperature resin. While most machines using this insulation system design are less that 1,000 kW, there are a few up to a rating of 2.0 MW that will use random-wound coils in the stator only. Almost all rotors above 660 kW are designed using form-wound systems.

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levels, and electrical surges. The basic concept of periodic electrical testing of the EIS is to monitor and/or trend the factors that lead to premature failures. Let’s consider the basic testing that can be done at regular maintenance checks.

UP-TOWER PERIODIC TESTING

Fig. 3: Wind turbine stator with form-wound coils

Firstly, safe work practices concerning electrical devices, whether in operation or under test, are paramount. All LOTO and arcflash rules should be carefully followed, and only qualified electrical workers should undertake this testing. Additional hazards may exist due to the small work space and close clearances with the turbine nacelle (see Figure 5). The InterNational Electrical Testing Association and National Fire Protection Association, as well as other organizations, have recommended guidelines for safely testing electrical components and should be consulted if there are any questions regarding safety.

Fig. 4: Wind turbine rotor and insulation system shown during assembly In a form-wound system the larger insulated conductors are often insulated with a mica paper/polyester film tape that is common in European and Asian designs for high voltage machines. In the USA, it is also common to use enameled conductors, sometimes with a glass filament covering. These conductors are shaped into coils, then additional layers of tape are applied over the bundled conductors to provide both phase and ground insulation. These tapes are normally a laminate of mica paper with some combination of polyester film, polyester fleece, or glass cloth. These finished coils are then inserted into the stator or rotor core with or without additional ground insulation. They are wedged into place, tied, and otherwise supported and then varnished, typically utilizing a vacuum and pressure cycle impregnation system. All of these insulation and conductor components (and there are actually many more ancillary materials utilized in the winding process) are designed to function together as an electrical insulation system (EIS) to provide long lasting, reliable performance at a designed and tested operating temperature. The thermal life expectancy is normally calculated for 20,000 operating hours and includes thermal cycling, vibration, and electrical stress testing. In normal end-of-life events, the insulation has broken down at some tiny point due to mechanical abrasion or thermal weight loss so that it is no longer functional. These natural and foreseeable failures can be accelerated by environmental conditions including moisture and chemical contamination, high machinery vibration

Fig. 5: The Nacelle often has close quarters and tight working conditions

Insulation Resistance Insulation resistance (IR) testing is one of the oldest maintenance procedures developed for the electrical industry and is covered in detail in IEEE Standard 43-2000. This test is fairly simple to perform and can provide information regarding the condition of the electrical insulation in the generator as well as contamination and moisture. It is recommended that this test be performed before energizing a machine that has been out of service or where heating elements have failed to keep the winding temperature above the dew point, which might have resulted in condensation on the windings. Insulation-resistance testing is also useful whenever there is doubt as to the integrity of the windings and before any overvoltage testing is performed. An accurate IR test requires a correction factor for the winding temperature to create useful data. The methods and expected result data for this test are listed in the IEEE standard. While the test results from IR testing are not normally trended, it is possible to do so to illustrate a gross degradation of the insulation systems. It is, however, very important that the duration of the test, the temperature of the windings, and relative humidity be consistent for the trend data to be meaningful.

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Polarization Index

WHAT’S AHEAD?

Another test described in IEEE Standard 43-2000 is the polarization index that is useful in some applications to identify contaminated and moist windings. In most modern machines, however, where the insulation resistance is above 5000 megohms, the test might not prove meaningful. Recently there has also been a consideration of collecting depolarization data as well as analyzing the shape of the polarization curve. Refer to the IEEE standard for additional applications and details.

Although power-quality testing can be performed for energy from the generator as well as excitation power to the rotor, in the near future, simplified on-line testing of electrical circuits will become more available, and acceptable standards of performance will be better defined. Based on either SCADA information versus industry standards or on actual measurements of power quality into and out of the generator, these tests will allow first line maintenance teams to monitor and trend data more effectively from the ground and provide more root cause failure information than is currently available. As most generators currently in use are double fed induction types, the quality of the power from the converter IGBTs feeding the rotor as well as voltage issues from the grid can be questionable, and either could be a major contributor to early insulation failure.

WHAT IF THE TESTS ARE INCONCLUSIVE? If the results gathered during a periodic testing cycle are inconclusive or out of the normal range, additional testing is recommended. Normally a generator specialist, either internal or from a consulting service company, is called in to perform these advanced tests as there are some possibilities of further damage to the windings if they are not carefully tested. Some electrical testing is by nature destructive and should only be performed for diagnostics reasons.

SURGE COMPARISON TESTING The normal advanced test for analyzing the insulation integrity is based on fairly innocuous testing performed by electrically stressing the insulation at a reduced voltage level and recording anomalies between phases of the insulation. This surge comparison testing can be performed manually; however, automated test equipment with digital reporting is available. This is not a trending test, nor does it answer all of the possible questions, but it provides a snapshot of the current condition that can support a decision to remove the generator for repair.

High-Potential Testing If testing is required to make an immediate decision regarding replacement of a generator, high-voltage testing, normally dc highpotential testing, is useful, but care should be taken as insulation weaknesses (cracking, contamination, carbon tracking, etc.) can be advanced to failure. Sometimes referred to as overpotential testing, the high-potential test is designed to stress the electrical insulation beyond its normal operating voltages to expose potential failures at a convenient time. The dc test methods are described in IEEE Standard 95. Trending is possible with this test, but it is considered a destructive test and probably should be used sparingly and only if the site is prepared to repair or replace the machine.

Most wind turbine generators operate at 575 or 690 V ac (a very few are in the 12 kV range) and do not normally generate partial discharges (corona) in the range to be monitored. However, in conjunction with the surge comparison test, there is auxiliary equipment available to ride the high-voltage impulse signal and collect PD information at the peak of the signal. In the future, this data might be useful as a trending tool to help predict normal end-of-life conditions or to identify damage too small for other detection methods. All good testing stratagems are designed to assure the profitability of the operation. Periodic electrical testing, vibration testing, and alignment of the drive train are time consuming operations and are sometimes difficult to perform on a regular basis. However, the cost of unplanned outages including cranes, staffing and emergency generator repairs can also dramatically affect the bottom line. Good planning, proper testing methods, and clear decisions regarding the condition of the equipment will always pay off with reduced overall maintenance costs. Kevin Alewine is currently Director of Renewable Energy Services at Shermco Industries with a focus on business development in the wind energy business sector. He has extensive global experience with the application of electrical insulation materials, systems, and processes for both the manufacture and repair of electrical machinery. Kevin is an active member of several IEEE and American Wind Energy Association working groups including chairing the AWEA Operations and Maintenance Working Group developing recommended practices for wind energy asset maintenance.

Step Overvoltage Test Using the same equipment as used for the high-potential test, the step overvoltage test stresses the insulation at rising levels of voltage over a set time scale. This is a very useful trending test and can be used in periodic predictive maintenance testing. The same concerns exist as for high-potential testing.

Casey Gilliam has thirteen years of experience in the mechanical industry that includes testing, maintenance and management. He has worked in both field and shop setting in his career. As a technician he has a background in quality improvement, troubleshooting, and repairs while mentoring and leading a team. Casey is currently the Sweetwater Service Center Manager at Shermco Industries.

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ELECTRICAL POWER SYSTEM TESTING – A QUANTUM CHANGE IN OUR FIELD HAS ARRIVED NETA World, Summer 2013 Issue John Hodson I look back over 30 years involvement in the electrical testing industry and realize that many changes have occurred that are now the accepted norm. It is quite similar in our normal day to day activities….I still marvel at the day my 21 year old daughter could not find the remote for the TV and suggested we needed to get a new remote (or TV)…. she had no idea a television could be turned on at the screen. Some of the lost skills or technology I remember as I reflect back in time:

Some of the new technology I have seen: ●● Relay sets that do not weigh 80 pounds (but need a laptop ●● Vacuum bottle interrupters ●● Something not needing to be done by yesterday ●● Test technicians without a specialty (testing was the specialty) ●● Test sets that do everything for you…. Simplified push button testing ●● Better stop…..could get confrontational…. Back to the Future -- Decade Two / Century 21….

Fig. 1: Good Ole SR51 Relay Test Set ●● Relay sets that did not require software, but a relay bulletin to figure out how to test it ●● Typewritten reports and invoices with carbons (way back) ●● Having to figure things out on site without the benefit of cell phones or (site phones) ●● Drawing coordination curves on log-log paper ●● Electronic [not microprocessor] relays ●● Hand taped rather than heat/cold shrink HV terminations

Many influences affect our present day life and future, arguably the most impactive may be our world of instant communication/ information, data storage and processing capability, and short description computers. Computers with email, calendars, appointments, and reminders have absorbed our life planning with web-based connectivity. It is a natural step then, as technology advances on all fronts, that we should find it becoming integral to the electrical industry. On point, the electrical industry is one of the most advanced and technically challenging based on the control and custody of a very powerful energy. Before we move forward we should review our electrical testing basics. I suggest that the main purpose of our work is to measure the performance and condition of power equipment. In addition, we bring our experience and knowledge to drive improvements and efficiencies, but in the final analysis the question to be answered is “Does the device do what it is supposed to, reliably, safely, and within design and application parameters?”

Fig. 2: The Generation of Microprocessor Relay Sets Fig. 3: ATS 2009 Cover

34 We, as NETA member companies, have a well-developed set of tests and a huge selection of test equipment to work with. The majority of these require the equipment be de-energized to allow the tests to be performed. This not only creates a set of concerns regarding safe access and re-energization but also takes the equipment out of its normal or dynamic state. Once we have the equipment in its deactivated condition the majority of our tests try to simulate the energized condition to evaluate performance. Some examples of this are conductivity, ratio testing, insulation testing, and power-factor testing. In many cases we are utilizing estimates and dc conversions to allow us to have equipment that is portable and more manageable regarding power requirements. Balancing electrical testing procedures with practicality has always led to some level of compromise. This has typically led to very good but not optimum diagnostics and with some room for error in evaluation of all conditions. With advances in technology, we now have the capability to not only monitor power systems for protection and control in upset condition but to actually evaluate equipment performance and serviceability. The first integration of microprocessors into metering and protection equipment has provided for waveform capture, harmonic analysis, voltage and current monitoring, and more. The key to this is the ability to digitize information and store massive amounts of data over long periods of time. [Perhaps I should have included pen chart recorders in my list of lost technology]. Much of this information was initially overlooked and the new instrumentation was underutilized as strictly a replacement for what now seem archaic, electromechanical relays and analogue meters. With improved communications the data can now to be centralized as a minimum for real time analysis review after upset. As we experience more and more smart relays, meters and now even networks and grids, the full potential is becoming much more evident. The availability of new devices that measure, monitor, and evaluate electrical power apparatus and accessories is growing monthly and exponentially. Devices to perform tests normally done in the laboratory on insulating oils are readily available at reasonable cost. ●● Breaker contact timing and wear evaluation measurements-available. ●● Real time temperature monitoring by direct contact with energized parts--available.

Maintenance Vol. 1 The following identifies some of the presently available technology.

Fig. 4: Advanced Diagnostic Waveform Analysis

ONLINE MAINTENANCE DIAGNOSTIC OPTIONS Temperature Monitoring ●● Oil / Liquid - Winding - Ambient - Contacts ●● Tank//Internal - External/Infrared Gas in Liquid Monitoring ●● Acytelene – Hydrogen – High Gas Fluid Chemical Analysis ●● Moisture - Acidity Pressure ●● Tank - Atmospheric - Gas – Loss of Gas Voltage / Current ●● Power Functions – Fault Current - Waveforms ●● Impulse – Harmonics DC Voltage ●● Level – Motor Signature ●● Trip / Close Coil Signature Digital I/O ●● Contact / Device Status – Timing Functions ●● System Operating Mode – Clock Functions ●● Equipment Mechanical Position - Travel Power Factor / Capacitance

●● Online partial discharge levels--available.

●● Transformer Busing Monitoring ●● Cable Monitoring

●● Online ultrasonic detection--available.

Partial Discharge

●● Battery condition monitoring--available.

●● Cable Accessories – Rotating Machinery ●● Switchgear

●● Rotating machinery vibration and winding diagnostics--yes available and the list grows.

Ground Resistance ●● GPR Under Fault – Ground Rod Condition

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Maintenance Vol. 1 Arc and Pressure ●● In Oil – In Air – In Enclosure Far from complete but certainly comprehensive this list will continue to grow monthly. Some existing and new startup companies are focusing on this area of real time diagnostics further driving advances. One very interesting field of experimentation is driven by light and fiber optic communication. It has been proven that light is affected in a measurable and consistent manner when exposed to certain energies such as heat, pressure, and electromagnetic fields. As light and fiber optics has no discernible conductivity, it is a perfect control and protection medium to be integrated into electrical power systems. As new products and monitoring devices are installed in our electrical systems and as their capabilities for diagnostics improve, it will be less necessary to shut equipment down to evaluate condition. The opportunity to operate equipment in a dynamic or operational state with online equipment measuring and storing all manner of data regarding performance is already here. One of the large inhibitors to this integration comes from a shortage of resources to manage the copious amounts of information gathered and what to do with it. There is also some push back in installing more equipment than necessary, as that becomes not only additional asset cost but also a further maintenance concern. The reality is that we need to balance benefits vs cost. I believe the tipping point has arrived and a paradigm change in how we do our work is imminent. The era of smart meters and relays has evolved into the smart grid and ultimately the smart transmission and distribution system. This has reinforced what we might call smart software which not only stores data but analyzes and reports on power system components and overall network reliability. These are operated via flexible historian software such as OS π, which when coupled with specialized and complex algorithms can evaluate condition on a continuous basis. Some systems are less complicated and are partnered only with specific products such as gas in oil measurements with tolerable limits for quantity and evolution rates. The full potential of real time diagnostics is realized when numerous devices input to a common register and all data is available in common format for input to extremely powerful custom algorithms. The most powerful of these analysis macros allows not only for the input of on line data from numerous devices but for input from off line test information gathered from FAT and through acceptance and commissioning and maintenance testing. As manufacturers specifications and safe limits are added to the equation for more precise and accurate determination of condition. When economics are to be added to the technical decision, coming back to benefit vs cost, many analysis formula include a risk factor of failure and process consequences related to monetary and safety impact. That is if a component and or system fails, what will be the impact on facility process or throughput be and for how long? In some cases

the risk analysis may indicate that a component is not critical at all and failure may be just an inconvenience until repairs are effected, this is often called run to failure or RTF. A sample situation may be a lighting transformer and panel. In many cases, monitoring of larger assets is easy to justify simply because of cost of asset and replacement. Exceptions are certainly possible whereby small components such as a lube oil pump can have catastrophic effect on much larger components and finally result in a massive impact on operations. The determination of equipment criticality is established by FMECA procedures comprising of failure mode modeling and impact analysis. This is usually supported by software of its own such as AMR and assigns a criticality value to equipment based on many criteria but typically very important is how likely is this to happen, how much are we doing to prevent it, and what is the worst case impact of failure. This topic really warrants a discussion on its own merits. The process of executing a complete electrical CBM/RBM program is significant. Certainly the most key component is an acceptance and change in attitude and understanding at all levels of management, operations, and engineering. This cannot be done in a short period of time and would typically take place over years and then be further enhanced by means of a continuous improvement plan. Critical components for switching from TBM to CBM include knowledge, usually via a competent and trusted electrical partner. Corporate acceptance and support at all levels and the resolve to see the project through. A budget to support the initial efforts, and then an ability to track and evaluate performance as the benefits are realized. The end goal is to show that the program pays for itself over time in more focused maintenance efforts and improved reliability and efficiencies.

Fig. 5: The CBM Process Many companies have taken the first steps towards CBM through necessary improvements in protection and control technology that are being carried out industry wide. Certainly the utility companies have seen the future with companies like Doble, GE, IBM and SKF working diligently to provide the next software platform for

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equipment maintenance. In many cases it is only necessary to start utilizing and processing the available information already available in your electrical system in a coordinated and effective manner. As these first steps show their value the addition of more sophisticated and powerful diagnostics can be added along with the required data storage and analytics to ensure the most comprehensive evaluation is available. Then based on indicated condition and criticality, the equipment can be scheduled for routine or emergency inspections and testing. The most advanced algorithmic analysis will even provide the recommended tests, estimated time to failure, and follow up monitoring and testing necessary to confirm corrective actions have been properly executed. This new frontier in electrical testing is just starting as many of us baby boomers are leaving the industry. The day of a daily/ hourly condition report based on a simplistic traffic signal with green indicating all is ok, yellow indicating potential concerns, and red indicating a serious problem are possible today. How long will it be until this is the operational norm-time will tell. It is fitting in many ways that generation X, raised on video games and iPads will be monitoring the health and condition of our electrical systems with apps on their iPhones.

Fig. 6: The CBM Traffie Lite = GO / INVESTIGATE / SHUT DOWN It is also fitting that until we come up with an app for turning a wrench, connecting a test lead correctly, or doing a proper cut back on the semiconductor there will still be a requirement for hands on field service technicians. John Hodson has spent over 30 years in the field service industry with Magna IV Engineering Ltd. He served as the NETA representative for Magna Group of Companies for several years. He is still active in the industry by mentoring, training, and working to promote advanced diagnostics hardware and software and their integration.

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SYNCHRONOUS ROTOR WINDING – COMMON ELECTRICAL MONITORING NETA World, Fall 2013 Issue Vickie Warren The rotor windings of synchronous motors and generators are usually very reliable. However, the turn insulation in such machines will eventually degrade and puncture due to thermal aging, load cycling and/or contamination. Although turn shorts do not directly lead to machine failure, they can lead to high bearing vibration, may damage synchronizing systems within brushless motors, and may limit output. Off-line tests are available to detect rotor winding shorted turns; however, they may be unreliable since the rotor is not spinning for the test. If only a few shorts are present, the shorts may disappear once the rotor is spinning (or vice versa). In the last edition of the NETA World, several of the common off-line electrical tests for synchronous rotors were described. This article will explain flux monitoring, which is a common on-line condition monitoring test for both round and salient pole synchronous rotors.

SHORTED TURNS Shorted turns are the result of failed insulation between individual windings in generator rotors. These shorted turns can cause: ●● Load sensitive vibration ●● Undetected local winding hot spots ●● Excessive excitation currents ●● Possible forced outages When an insulation system is exposed to overheating, the bonding material tends to lose its mechanical strength and the insulation layers delaminate. As the insulation bond weakens and the layers delaminate, the conductors can become free enough to move with respect to each other. This weakened bonding affects not only the mechanical stability of the field winding, but any vibration or movement will result in mechanical abrasion and may lead to strand/turn shorts and eventually ground insulation failure. Additionally, thermal aging can lead to shrinkage of bracing materials causing winding looseness. Insulation breakdown from simple thermal overheating may take years depending on the temperature and thickness of the insulation. Thermal deterioration can occur as a result of overloads, defective cooling, unbalanced phase voltages, overexcitation and poor design/manufacture. [Figure 1]

Fig. 1: Thermally Damaged Turn Insulation The following are the most common causes of thermal aging in rotor windings1: ●● Overloading leading to operating temperatures well above expected design values. Rotors always run hotter than the stator winding. ●● High cooling temperatures or inadequate cooling which can be general, e.g., insufficient cooling air or cooling water, or local dead spots (especially at the blocking between poles) due to poor design, manufacturing or maintenance procedures. ●● The use of materials that have inadequate thermal properties and consequently deteriorate at an unacceptable rate when operated within design temperature limits. ●● Over excitation of rotor windings for long periods of time. ●● Negative sequence currents in rotor windings due to system voltage unbalance, etc. Due to the different linear coefficients of thermal expansion for the materials in insulated rotor windings, one of the negative impacts of frequent changes to a machine’s load or starts and stops are the cyclical shear stresses placed on the insulation. As the copper linearly expands due to the increase in temperature from I2R losses, the insulation, which is bonded to the copper and wedged between the conductor and the pole body, tends not to follow the copper due to a lower coefficient of thermal expansion and lower temperature. This stress can cause a weakening of the bond between the copper and the insulation or between the pole body and the insulation. Relative movement between the two, over time, can lead to turn shorts or the field grounding to the rotor. [Figure 2]

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Fig. 2: Damage from Thermal Expansion When any kind of conductive contamination from moisture, oil, chemicals, dust/dirt pollutes a machine, or a mixture of these, it is possible for electrical tracking to develop between conductors and ground in salient pole and round rotor windings. Severe contamination and some chemicals can results in both turn and ground insulation failures from tracking as well as winding overheating. Abrasive particles such as coal dust, sand, and iron ore can enter the interior of motors with open enclosures. When these particles impinge on the rotor winding they wear away the insulation and can cause both turn and ground faults. Oil tends to dissolve and loosen insulation system components and can attract dust that reduces heat transfer from the winding surface and reduces insulation life. In open enclosure machines, oil in combination with dust can clog up rotor cooling air passageways to cause winding overheating. Salient pole rotor windings, especially the strip-on-edge type, can experience turn-to-turn shorts and ground faults from contamination that cause tracking. Also, if a salient pole motor has slip rings brush dust, which is conductive, it can contaminate both the stator and rotor windings.

FLUX MONITORING OF ROUND ROTORS Round (or cylindrical) rotor poles are used in large two-pole or four-pole synchronous motors and generators. The round rotor field windings have concentric windings made from rectangular copper strips with turn insulation consisting of strips of insulation such as Nomex™, fiberglass/resin laminate, flake mica sheets, or Kapton™ sheets. The slot ground insulation is usually molded “L” shaped pieces made from epoxy or polyester/glass. Flux probes have long been used to measure the voltage signal created by the flux surrounding each slot in each rotor pole on synchronous motors and generators rated 4160 volt and above2. The radial magnetic flux is detected by means of a flat coil (or probe) consisting of several dozen turns that is glued to stator teeth4. [Figure 3] As each rotor pole sweeps by the flux probe, a voltage is induced in the coil that is proportional to the flux from the pole that is passing the coil. By analyzing the waveforms and comparing them pole to pole, it is possible to identify slots with shorted turns. Any turn short in a pole

Fig. 3: Flux Probe Usually, coils that have peak-to-peak difference larger than 3 percent compared to the same coil on another pole, are considered to have shorted turns. [Figure 4]

Fig. 4: Flux Difference of Shorted Turn Historically, for a thorough analysis, it was imperative that flux data be collected at various output load conditions2. As such, it was often necessary for the data collector to invest long hours, often at odd times, to gather data during generator startup or shutdown. Recently, a second generation of rotor flux analyzers has emerged with the advantage that, in most cases, it is no longer required to maneuver the load from 0 to full power4. This makes the test much easier and cheaper to do. [Figure 5 and Figure 6]

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flux profile across each rotor pole depends on the MW and MVAr loading of the machine. After corrections for variations in the airgap, any change in the flux profile within a pole at a given load must be due to shorted turns6. Changes in the flux pattern and differences from those from other poles gives an indication of the presence and number of shorted turns.[Figure 9]

Fig. 5: Flux Data - Round Rotor

Fig. 7: Flux Probe for a Salient Pole Rotor

Fig. 6: Flux Data - Round Rotor

FLUX MONITORING OF SALIENT POLE ROTORS Salient pole rotors are used in machines with slow speeds that make cylindrical (round) rotors impractical. Each field pole consists of laminated steel core, which looks rectangular when viewed from the rotor axis. Around the periphery of each pole core are the copper windings. Each field pole is an electromagnet, and the rotor winding is made by mounting the poles in pairs on the rotor rim. The poles are then electrically connected to the dc supply (normally up to a few hundred volts) in such a way as to create alternating north and south poles around the rim. The inside shape of stacked turns conforms approximately to the width, length, and height of the pole body. The winding has turn insulation while pole body insulation may simply be air. Similar to the round rotor, rotor flux monitoring involves measuring the magnetic flux in the generator or motor air gap to determine if field winding shorts have occurred in the rotor poles. [Figure 7] As each rotor pole sweeps by the flux probe, a voltage is induced in the coil that is proportional to the flux from the pole that is passing the coil. [Figure 8] The voltage is measured by electronic instruments. In a salient pole machine, the radial magnetic

Fig. 8: Flux Measured in Salient Pole

Fig. 9: Shorted Turns in Poles 8 & 48

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REFERENCES G. Stone et al. Using Magnetic Flux Monitoring To Detect Synchronous Machine Rotor Winding Shorts IEEE PCIC 2011-17.

1



2



3

D. R. Albright Interturn Short-Circuit Detector for TurbineGenerator Rotor Windings, IEEE Transactions on Power Apparatus and Systems, Vol. PAS-90 Number 2, March/April 1971.  .P. Jenkins, D.J. Wallis Rotor Shorted Turns: Description M and Utility Evaluation of a Continuous On-line Monitor, EPRI Predictive Maintenance and Refurbishment Conference, December 1993.

4 M. Sasic, B. Lloyd, A. Elez Finite Element Analysis of Turbine

Generator Rotor Winding Shorted Turns IEEE Transactions on Energy Conversion, Vol. 27, Number. 4, December 2012

5

S. Campbell et al. Detection of rotor winding shorted turns in

turbine generators and hydrogenerators CIGRE A1_206_2010 6

M.

Sasic et al. Tools for Monitoring Generators, Hydro Review Worldwide, Oct 2009, pp 12-19.

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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SWITCHGEAR PARTIAL DISCHARGE LOCATION NETA World, Fall 2013 Issue Don Genutis, No-Outage Electrical Testing Inc.

More and more service companies are finding success with No-Outage field Partial Discharge (PD) testing and monitoring methods and as the use and awareness of these techniques continue to expand, it becomes important to determine the location of the PD source so that it can be eliminated. In this article, we shall review the three basic types of PD sensors used for switchgear testing and monitoring then discuss how probable PD location can be identified on-line and how it can be pinpointed off-line.

TYPES OF PD SENSORS Airborne ultrasonic sensors are the most sensitive type of sensor for detecting surface insulation PD. These sensors detect the minute pressure waves which are created from the PD "sparking" activity. Switchgear vents or openings must be present in order for the pressure wave to reach the sensor from outside of the enclosure. Ultrasonic sensors also cannot detect problems internal to components. Transient Earth Voltage (TEV) sensors detect electromagnetic signals created by internal PD activity through capacitive coupling. The TEV sensor consists of a metal plate assembly, which when placed against the switchgear, forms a temporary capacitor with the enclosure acting as the other plate of the capacitor. This test method compliments the ultrasonic sensor by allowing the detection of internal component PD flaws or detection of surface discharges that ultrasonic sensors cannot "see" due to inhibited airway access paths. Since the ultrasonic sensor is more sensitive to surface PD, the TEV sensor will often pickup when surface activity becomes more severe. High Frequency Current Transformer (HFCT) sensors consist of a split core ct with high frequency characteristics that detect conducted electromagnetic signals from cable PD by placing the sensor around the cable shield. This sensor detects PD at the cable termination and can detect PD further down the cable as well.

WHAT DO THE SENSORS TELL US ON-LINE? By examining Diagram 1 we can see what each sensor alone and collectively tell us in regards to PD location in switchgear. For this example, the sensors can be either permanently mounted, in the case of monitors, or temporarily mounted in the case of spot testing. The "H" circle represents the HFCT sensor, the "T" circle represents the TEV sensor and the "U" circle represents the Ultrasonic sen-

sor. Non-intersecting circles are straight forward to figure out: "H" by itself represents a cable problem, "T" by itself represents an internal switchgear problem and "U" by itself represents a surface switchgear problem. Moving along, where is the PD located if two sensors indicate a problem? Taking a look at Diagram 1 again, the area labeled "HU" displays a condition where both the HFCT ("H") and the Ultrasonic ("U") sensors pick up PD signals. This would be indicative of a surface cable termination problem. "HT" represents an internal termination problem and "UT" represents a severe surface switchgear problem - the surface tracking has reached a point where TEV signals are being generated as well as explained above. Finally, the "HUT" part of the diagram [Figure 1] indicates the condition of all three sensors picking up PD signals. This is likely related to a severe surface termination problem. It should be noted at this time that once any sensor picks up an abnormal signal, it should be investigated. Do not wait until multiple sensors alarm before taking action. This is especially true for the Ultrasonic sensor as surface PD damage can escalate rapidly and the signal path can be impeded by obstructions.

Diagram 1

HOW DO WE PINPOINT PD LOCATION OFFLINE? Very valuable information can be obtained when equipment is being shut down for maintenance and this applies to a much broader scope than just PD alone. For instance, obtaining breaker "first trip" condition allows valuable mechanical condition data to be recorded which also ties in protective device coordination and arc-flash compliance. Tripping medium voltage breakers from

42 protective relays can ensure proper function of the trip circuit, battery, wiring and associated components including the breaker trip coil and linkage. For pinpointing PD, an orderly shut down or "selective switching" can help rule out components by the process of elimination. Lets take a typical medium voltage switchgear assembly for instance, where PD has been located in one cell. First begin by tripping the breaker (don't forget to record the first trip data if possible), then check to be if the PD is gone. If so, the activity is located on the load side of the breaker which usually would involve cable terminations or load side bus insulation and could involve breaker load side connection insulation. If the PD persists, the next step would be to rack out the breaker using a remote breaker racking device to ensure personnel safety. Once the breaker has been racked out, check for PD activity. If gone, the problem is in the breaker. If the problem remains, it is associated with bus insulation or line side breaker connection insulation. After the switchgear has been completely deenergized, locked out, tagged out and grounded, visual inspections can proceed. Keep in mind that unless Ultrasonic signals where detected, the problem is likely to be internal to a component or deep in the switchgear where the airborne signals cannot escape. Look for surface tracking, the presence of white powder or other color powder buildup, discoloration, corrosion or other usual signs. If the problem is internal or if its difficult to visually locate a surface problem, carefully energize individual components using a PD-free a.c. Hypot and use the applicable PD sensor(s) to identify the faulty component through the process of elimination.

CONCLUSION Switchgear should operate PD-free and detecting the presence of switchgear PD activity is the first step in the process of ensuring reliability. The next step of the process is to locate the PD source on-line using information gleaned from the different types of sensors available. The next step is to perform "selective switching" to further locate the problem area by eliminating components through the process of elimination and the final step involves outage-based inspection and testing to pinpoint the faulty component. By utilizing this simple step by step methodology, PD can be detected, located, pinpointed and eliminated. Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

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VLF-MWT – HOW TO APPLY THE NEW WAY OF CABLE CONDITION ASSESSMENT PowerTest 2013 Martin Jenny, Alexander Gerstner, and Timothy Daniels

INTRODUCTION Operators of medium voltage networks and distribution networks worldwide are facing similar challenges: Existing cable systems must be maintained most economically and investments in new lines must be secured while maintaining or improving the quality of the network. Many operators today use diagnostic procedures to resolve the conflicts in these objectives in the best manner from technical and economic perspectives. Simple cable testing is a common method described in various IEC, IEEE, CENELEC and other national standards. Various test levels and times are used which depend on the voltage type (Direct Current DC, Very Low Frequency VLF, 50/60Hz). Faulty locations are forced to breakdown by application of a test voltage higher than nominal voltage (x*Uo). The wide acceptance of this method and the years of testing experience have also shown its limitations. The simple “passed” or “failed” statement allows no estimation about the remaining lifetime of the cable. This circumstance has led to a broader acceptance of cable diagnostics, which provides information on the cable's condition. As [1] indicates, VLF testing, tan-delta measurement and partial discharge measurement have become established methods for this.

VLF CABLE TESTING – A FIELD PROVEN METHOD VLF (Very Low Frequency) was introduced to test the insulation of Medium Voltage (MV) underground cables after new installations, after repairs or as a routine measure at regular intervals. It became important when it was recognized, that testing of PE/ XLPE-insulated cables with DC voltages is ineffective in detecting hidden defects in XLPE insulations. It was found, that DC testing could induce trapped space charges in the polymeric material. After successfully passing the DC voltage test, these cables would breakdown shortly after being re-energized. This behavioural pattern was observed for medium voltage cables failures. [4] The reasons for voltage testing are according to [5]: ●● Detection of weak points which put reliable operation at risk using low test voltage levels ●● Conversion or evolution of conductive inhomogeneous defects (water treeing) at low test levels into first partial discharge channels (electrical treeing) ●● Bringing partial-discharge defects rapidly to breakdown by means of high channel growth speeds

Evaluation of single measurement results and the combination of tan-delta and partial discharge (PD) measurement provides the operator with important information about the condition of a particular cable. Although cable diagnostics provides more relevant information for decision-making than a simple cable test, it cannot reveal how the cable would respond to the application of an increased test voltage over a longer period (15 minutes to an hour). Section 3 shows a practical example of how this can lead to misinterpretations in specific cases. Up to now, cable testing has lacked the ability to adapt the test duration to the condition of the cable and thus reduce overstress by the increased test voltage and save time and money. To avoid the disadvantages of these individual methods, the National Electric Energy Test, Research and Applications Centre (NEETRAC) developed the VLF Monitored Withstand Test (MWT). A combination of VLF cable testing and diagnostics enables the measurement limitations described to be compensated in the best manner and significant additional value to be generated through additional information with a flexible test period.

Fig. 1: Development of electrical tree out of a water tree By comparing different voltage sources (VLF Sinus, VLF Cos-Rect, 50/60Hz AC, Oscillating Voltage) it was found, that especially the VLF Sinus voltage is suitable for testing medium voltage- and especially PE/XLPE cables. The combination of a low PD incipient voltage, high channel growth speed and the

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capability to perform diagnostics must be considered [5]. These are the preconditions, to convert inhomogeneous defects and to bring partial-discharge defects rapidly to breakdown.

The tan-δ is ratio between the resistor current and the capacitor current. If the resistor current is 0 due to a perfect insulation material, the tan δ also becomes 0.

A typical VLF withstand test is performed with voltages between 2 and 3*Uo for the maximum time of one hour. Due to the representation in different standards (IEC60060-3 (horizontal standard), CENELEC HD620/HD621, IEEE 400.2) and the easy application on site, VLF cable testing became a widely adopted method worldwide.

It is also possible to measure different tan-delta values at different voltage stages (e.g. 0.5, 1.0, 1.5 and 2.0*Uo)

But voltage withstand testing has its limitations. The simple result (Pass/Fail) only offers the statement that the cable was ready for operation or damaged at the time of testing. But it provides no estimate of how long the cable can remain in operation nor when the next check should be performed. That’s the reason, why diagnostic methods like tan-delta- or partial discharge measurement became more popular in the last few years.

VLF TAN-DELTA DIAGNOSTICS – MORE VALUABLE INFORMATION The tan-delta measurement is an important extension to the simple withstand test, because more information about the cable condition is available. This can be used, to optimize the maintenance strategy of a utility.

●● MTD: Mean tan-delta: Average or mean value of tan-delta values at constant test voltage ●● ΔTD: Delta tan-delta: Change in tan-delta with changing test voltage ●● SDTD: Stability or standard deviation of tan-delta values at constant test voltage The measurement of these values allows an interpretation of different types. A high MTD value is an indicator of the presence of water trees. If the ΔTD is high (increasing TD over test voltage), this could be an indicator for partial discharges or also for water trees. A negative ΔTD (decreasing TD over test voltage) could be an indicator for a vaporisation effect, e.g. in terminations. And the SDTD (stability at a voltage level) is another helpful indicator. A low SDTD indicates that the cable is in a good condition. An increasing SDTD indicates the presence of partial discharges. High SDTD values are an indicator for water ingress in joints.

The tan-delta method is an integral measurement which can be adopted for all cable types and gives a statement about the condition of the whole cable line. Although there is no location information available, the interpretation of various tan-delta parameters allows differentiating between different types of defects of the cable line. These measurements allow the system operator to define followup measurements like partial discharge- or cable sheath testing. With the combination of these methods it is possible, to interpret and locate different types of defects.

THE MONITORED WITHSTAND TEST (MWT) – AN INGENIOUS COMBINATION

For modelling, the cable insulation system is simply represented by a capacitor (representing the cable with a perfect insulation material) and a resistor (representing the defective insulation).

●● No estimate can be made of how well the cable test was passed nor whether the cable will fail in an hour or in ten years.

Before describing the MWT, let us examine the disadvantages of simple cable testing once again. As [2] explains, there are essentially three disadvantages: ●● No estimate of the cable line's quality can be made before the test voltage is applied. ●● The duration cannot be adapted to the condition of the cable.

Combining VLF cable testing and VLF tan-delta diagnostics can avoid these limitations. It makes sense, to perform the MWT in two stages: ●● a “ramp-up”- and ●● a "MWT"-or "hold" stage

Ramp-up stage Fig. 2: Equivalent Cable Circuit When a voltage is applied to the cable, the total current is the sum of the capacitive- (Ic) and resistive current (IR) through the cable. (Figure 2) The measured angle δ increases with decreasing value of R, which represents the imperfections of an insulation material.

Non-destructive tan-delta measurement as described before is performed prior to the actual MWT stage. Continuous monitoring of the measurement values (mean tan-delta, tan-delta stability, delta tan-delta) enables an initial estimation of the cable's condition to be made. As Figure 3 shows, tan-delta measurements are performed typically at 0.5xUo, 1.0xUo and 1.5xUo.

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Fig. 3: Sequence of the ramp-up stage Various tan-delta indicators are determined and evaluated at each stage:

RAMP-UP STAGE INDICATOR

CALCULATION

tan δ stability (SDTD)

Standard deviation of 6-10 measurements at Uo

delta tan δ (ΔTD)

Difference of the average values at 1.5 Uo and 0.5 Uo

mean tan δ (MTD)

Average value of 6-10 measurements at Uo

Table 1: Indicators during the ramp-up state The advantages of the ramp-up stage are apparent: ●● An initial assessment of the cable line's condition is enabled. ●● Excessive stress from high test voltages on aged cable lines can be avoided by an initial condition evaluation. ●● Tan-delta measurement is an established, commonly used method. Application experience and limit values are available.

INDICATOR

CALCULATION

tan δ stability (SDTD)

Standard deviation of 6-10 measurements at Uo

mean tan δ (MTD)

Average value of 6-10 measurements at Uo

Change in tan δ vs. time (tΔTD)

The difference in the tan δ value from 0 to 10 minutes.

Table 2: Indicators during the MWT stage Continuous evaluation of the measurement data from the rampup and MWT stages enables the optimum test duration for the cable line to be determined during testing. The user can adapt the time to the cable's condition based on the measurement results or the test system can suggest optimal test duration. In addition to the time saved, shorter tests have the advantage of exposing the cable to the higher test voltage only for the time actually necessary. But the user can also extend the test to cause existing weak points in the insulation to break down. The benefits of the MWT stage can be summarized as follows: ●● The condition of the cable line can be evaluated. ●● The test duration can be adjusted to the cable's condition ●● The influence of the higher test voltage on the cable can be assessed. ●● MWT is a useful combination of established, accepted methods.

CASE STUDY

MWT or Hold Stage

Here is a practical example of why monitored withstand testing represents an important advance of previous testing and Cable testing and diagnostics are combined in the MWT stage. diagnostic measurements. According to [2], the MWT is only passed if: The cable tested (11 kV) has a total length of 234 metres and ●● No breakdown occurred during the MWT. is composed of various cable types (in other words, a mixed ●● The tan-delta values determined prove to be stable cable line). (i.e. have a low standard deviation). ●● The average tan-delta value is low.

Fig. 5: Structure of the cable line tested prior to the first repair in June 2010 In June 2010, there was a cable fault in an XLPE-insulated cable line produced in 1989 (first generation). Cables produced during Fig. 4: Sequence of the MWT Stage this period are known to develop water trees. An 11 metre section Figure 4 shows the sequence of the MWT stage. Various tan- of this line was replaced by an XLPE cable of a newer type. delta measurement values are also determined and evaluated during application of the voltage. (See Table 2.)

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Fig. 6: Structure of the cable line tested after the first repair in June 2010 Diagnostic measurements (VLF tan-delta and partial discharge measurement) were performed after the repair. The tan-delta results showed that the cable line was heavily aged by service. (See Figure 7). Although the measurement values were below the TD limits for mixed cable lines, for the section of line at risk for water trees, the delta tan-delta (DTD) limit for XLPE cable was applied (DTD > 1.0E-3 as high operating risk). Here L2 and L3 showed a strong rise with increasing voltage, indicating water

The PD measurement data show partial discharges at the transition joints (on the PILC cable line) at 199 and 224 metres. Evaluation of the partial discharge and tan-delta measurement revealed that the high tan-delta values were caused by water trees. This is indicated by higher TD standard deviations for L2 and L3 at voltages below 1.0xUo and the increasing trend of tan-delta without partial discharge. Moreover, the partial discharge level is of an order of magnitude which does not affect the delta tan-delta. Afterwards, a 15 minute VLF cable test was performed at 2xUo. The result was that all three conductors passed the test despite the high tan-delta values. So the cable was put back into operation. Four days later there was a cable fault at 125 metres, i.e. in the section endangered by water trees. Severe water tree damage was found in this part of the line (Figure 10).

tree damage to the cable.

Fig. 10: Cable line severely damaged by water trees This example shows quite clearly how a VLF Monitored Withstand Test would have been helpful at this location to avoid the cable fault shortly after restoration of service. Fig. 7: Tan-delta measurement after repair

The TD standard deviations (SDTD) for L1, L2 and L3 were also used to assess the situation (Figure 8).

●● The 15 minute VLF test made the water trees more severe, but at the end of the test the progress could not be determined. Here a VLF sinusoidal MWT would have indicated by the progression of the mean tan-delta (rising TD values) and tan-delta standard deviation that the faults had been exacerbated. ●● The test duration could have been extended during the measurement (to 30 minutes, for example). The weak points (water trees in this case) would have grown worse and finally led to breakdown.

Fig. 8: SDTD – tan-delta standard deviation for conductors L1-L3 In Figure 8 it can be seen that the SDTDs for L2 and L3 increase. This indicates the presence of water trees. Partial discharge measurement was carried out afterwards (Figure 9).

●● Thus the MWT could have shown the influence of the test voltage on the cable. ●● It would have been possible to estimate the "margin" of passing from the condition of the cable at the end of the MWT. ●● Tan-delta measurement and cable testing as described in the example would have been possible in a single automated run.

APPLICATION

Fig. 9: PD measurement result

It is important for the application of the VLF MWT, that the measurement is simple and automated. This requires a VLF sine voltage, because this voltage shape allows a precise and combined tan-delta measurement. Additionally it is possible to perform the tan-delta measurement at a constant frequency, where limits are available and where a comparison of different measurement results

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Maintenance Vol. 1 is possible. This fact allows the electric utility system operator to gain the experience with cable diagnostics. As seen from Section V, it is useful to split the MWT into two stages: Ramp-up and MWT (or hold). For an easy application in the field it is necessary to automate the whole measurement sequence. An example of how these requirements can be implemented is the portable VLF truesinus® generator with an integrated tan-delta measurement like frida TD from BAUR (Figure 11). Fig. 13: Application example: Collection and consideration of unwanted surface currents

CONCLUSION AND OUTLOOK The Monitored Withstand Test (MWT) is being promoted in North America and has already found a place in various standards.

Fig. 11: MWT application with the BAUR frida TD Here an integrated tan-delta measurement function enables the same connection to be used for cable testing and tan-delta diagnostics. This facilitates fully automated measurement runs without additional external devices. It is also important for the various measurement results to be displayed clearly and continuously so the user can make decisions (for example, regarding the length of the MWT) during measurement. An example can be seen in the screenshot in Figure 12. The evaluation of results is also displayed continuously (with smileys) along with the details of individual measurement results.

The latest revision of IEEE400-2012 [3] (the IEEE Guide for Field Test and Evaluation of the Insulation of Shielded Power Cable System Rated 5kV and above) defines and describes the Monitored Withstand Test. The IEEE400.2-2004 standard (IEEE Guide for Field Testing of Shielded Power Cable Systems Using Very Low Frequency (VLF)) is also currently undergoing revision, and MWT will play a role in it as well. A key factor for evaluating the condition of various cable types is comparison with defined limit values (see the examples in Section VI as well). Limits for various types of cable are shown in [2]. These were developed recently for the North American region and will probably be included in the latest version of IEEE400.2. The prerequisites for using the tan-delta MWT have been met. The first versions of the standards and the necessary measurement technology are available. Now it is a matter of using tan-delta MWT in the field and applying the experience from this in future discussions of limit values, also for various regions.

REFERENCES

Fig. 12: Screen display during MWT measurement (BAUR frida TD) frida TD also allows to consider surface currents in open terminations (subject to pollution, humidity and mechanical damage) during the tan-delta measurement. These unwanted surface currents can heavily influence the tan-delta result, especially for XLPE cables.

1

 iagnostic Testing of Underground Cable Systems (Cable DiD agnostic Focused Initiative, CDFI), December 2010

2

 letcher, Hampton, Hernandez, Hesse, Pearman, Perkel, Wall, F Zenger: First practical utility implementations of monitored withstand diagnostics in the USA, Jicable 11, A.10.2

3

IEEE400-2012 IEEE Guide for Field Testing and Evaluation of the Insulation of Shielded Power Cable Systems Rated 5kV and Above

4

 .C. Moh: Very Low Frequency Testing – it´s effectiveness in S detecting hidden defects in cables. CIRED 17th international Conference on Electricity Distribution, Barcelona 2003

48 5

Maintenance Vol. 1  ach: Testing and Diagnostic Techniques for assessing mediB um-voltage service aged cables and new cable techniques for avoiding cable faults in the future.

Martin Jenny was born in Austria in 1972 and is Product Manager for Cable Testing & Diagnostics.Martin is leading the product management for BAUR’s cable testing and diagnostics product portfolio since more than four years. BAUR’s portable VLF testers were one of the innovations that Martin drove forward in the last years. He has more than ten years of experience in testing and measurement in different industries. Alexander Gerstner was born in Germany in 1969 and is the Head of Global Marketing and Product Managementat Baur in Austria. Alexander is an Electrical Engineer with more than 16 years of experience in Product Management and Product Development for technology products in global markets. For more than four years he is responsible for BAUR’s innovation initiatives, Product Management and global customer communication. His special focus is on customer value focused solution design, User Experience, Communication and Information Technology. Timothy “Tad” Daniels is currently the HV Sales and Marketing Manager for HV TECHNOLOGIES Inc. in Manassas, VA. Tad has worked in the Electric Utility Industry since 1984 with McGraw Edison, Cooper Power Systems, SPX Transformer Solutions formerly Waukesha Electric, and Weidmann Electrical Technology. Tad holds a BSEE from Tulane University. He is a member of the IEEE and is active in ICC IEEE PES and IEEE Transformers Committee Standards Groups.

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DETECTING COMMON POWER QUALITY ISSUES PowerTest 2013 Andrew Sagl

VOLTAGE SAGS AND SWELLS Voltage sags and swells are two of the most common power quality events. Voltage Sags and Swells cannot be prevented on the power system. As impedances change during the course of a day the voltage will momentarily change as well. The goal of power quality is to limit the number of sags and swells as well as the magnitude of these events such that they do not cause equipment malfunction or failure. The malfunction or failure of this equipment can cause large financial losses to various manufacturers. This paper will define the various types of Voltage Sags and Swells that occur and the effect they have on various types of equipment. Voltage Sags and Swells are defined in different manners based on their individual characteristics.

Voltage Swells are typically due to large loads turning off. This causes a sudden change in load impedance which can cause the voltage to swell. These loads can include such things as large motors, arc furnaces and large welders. In addition switching of capacitor banks and network sections can also cause voltage sags and swells. In addition intermittent loose connections can also cause voltage sags and swells. There are also events that are referred to as Long Duration Variations; these are voltage sags and swells that last for more than 1 minute. Voltage variation disturbances can cause equipment to malfunction such as computers locking up or data getting garbled. Process equipment can trip off line and breakers can trip. Commercial electronics can trip off line, clocks can get reset and electric arc lighting can trip off. These are just some examples of some of the problems that can be caused by voltage variations. There are many types of Power Quality Analyzers that will allow operators to program various limits and perform high resolution recordings to capture these types of voltage variations. The challenge is how do we determine if the recorded voltage variation is causing the condition that the customer is reporting and how do we locate the root cause?

Instantaneous Sag is a short duration voltage variation that will last from 0.5 cycles to 30 cycles. The voltage during an instantaneous sag will vary from 10% to 90% of nominal. An interruption is a short duration voltage variation that will last from 0.5 cycles to 3 seconds. The voltage during an interruption will fall to less than 10% of nominal. Momentary Sag is a short duration voltage variation that will last from 30 cycles to 3 seconds. The voltage during a momentary sag will vary from 10% to 90% of nominal. A temporary interruption Instantaneous Sag is a short duration voltage variation that will last from 3 seconds to 1 minute. The voltage during will fall to less than 10% of nominal. Short duration voltage variations are typically caused by large loads that draw high inrush current. These high inrush currents will cause the voltage to sag.

One of the tools available to help determine if a measured voltage variation is causing equipment to malfunction is the ITIC (CBEMA) Curve. This curve was published by the Information Technology Industry Council (formerly known as the Computer & Business Equipment Manufacturer's Association). The ITIC (CBEMA) Curve describes an acceptable AC voltage window that can be tolerated by most Information Technology Equipment (ITE).

50 The ITIC (CBEMA) curve describes several ranges for voltage variation events. The voltage variation can be plotted on the graph as a point. The magnitude of the event as referenced to the nominal voltage is the X coordinate and the duration of the event in either cycles or seconds is the Y coordinate. Once the point is plotted it is easy to see if the event could be the cause of information technology equipment malfunction. (Computers, Faxes, routers, modems, internet, televisions...etc.)

Maintenance Vol. 1 sag. In the case of voltage swells this would mean the current is sagging. (Opposite the voltage which is swelling) This means that there has been an increase in load impedance such as a large load turning off that is causing the voltage to swell.

Another type of curve is the SEMI F47 curve. This curve was developed by the industry association for the semiconductor industry known as Semiconductor Equipment and Materials International (SEMI). This curve was developed to place standards on semiconductor processing, metrology, and automated test equipment. The SEMI F47 curve defines a region of acceptable voltage variations on the AC power line of semiconductor processing equipment. The equipment should be able to tolerate voltage variations within this region. They must be able to tolerate sags to 50% of equipment nominal voltage for durations of up to 200 ms as well as sags of 70% for up to 0.5 seconds, and sags of up to 80% for up to 1.0 second.

If the current is in the same direction as the voltage, then the event is coming from the source side. In the case of a voltage sag this would mean the current is sagging. (The same as the voltage which is sagging) This means that there has been a reduction in the voltage on the source side and the reduced difference of potential across the load has reduced the current. In the case of a voltage swell this would mean the current is swelling. (The same as the voltage which is swelling) This means that there has been an increase in voltage on the source side and the increased difference of potential across the load has increased the current.

These types of curves can be a great asset in helping determine if a measured voltage variation is causing equipment to malfunction. When reviewing recorded events it is also important to try to determine the direction the fault is coming from. The fault can either be coming from the load side or the source side. In order to determine this it is required to analyze the voltage magnitudes during the fault as well as the current magnitude that occurred during the fault. A good rule of thumb to follow when trying to determine the source of a voltage sag or swell examine the minimum voltage recorded during the event against the maximum current recorded during the event. If the current is in the opposite direction from the voltage then generally the event is coming from the load side. In the case of voltage sags, this would mean the current is swelling. (Opposite the voltage which is sagging) This means that there is a reduction in load impedance such as a large load turning on that is drawing an inrush current that is causing the voltage to

When problems are found that cause equipment malfunction or equipment failure there are several simple possibilities that should be examined before resorting to expensive conditioning equipment. A common cause of voltage sags and swells is loose or poor connections. Before investing in conditioning equipment it is wise to check for loose or poor connections. Poor connections will have higher impedance, so they will have a larger voltage drop across them. A larger voltage drop across these connections will generate more heat. A quick way to search for poor connections is to look for this heat using an infra-red camera. A common cause of equipment tripping off line is an incorrect nominal voltage being applied to that equipment. These incorrect voltages can include 230 volt equipment being fed from 208 volts or vice versa as well as 460 volt equipment being fed from 480 volts.

Maintenance Vol. 1

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Since incorrect nominal voltages are applied to the equipment, relatively small voltage variations could cause controllers to trip the equipment off line.

extremely fast transients they are rapidly damped out by just a few meters of distribution wiring. Standard line filters, included on almost all electronic equipment, filter EFT's.

Note: Some 460 volt equipment have over-voltage, undervoltage and phase loss relays. When 460 volt equipment gets to 10% or about 506 volts it causes an over-voltage trip or alarm. A utility voltage can be at the upper limit of 504 volts and when a utility cap comes on the voltage may go to 508 for less than a cycle and cause an over-voltage trip.

Transients can be responsible for various component failures. These components can include fuses, surge protectors, automatic transfer switches, cables, switchgear, CT’s or PT’s etc. Transient voltages caused by lightning or switching operations can result in degradation or immediate dielectric failure in all classes of equipment. High magnitude and fast rise time contribute to insulation breakdown in electrical equipment. Repeated lower magnitude transients can cause slow degradation and eventual insulation failure, decreasing equipment mean time between failures.

In addition the grounding methodology used can affect the performance of sensitive equipment.

TRANSIENTS A transient is defined per IEEE 1159 as a phenomenon or a quantity which varies between two consecutive steady states during a time interval that is short compared to the time scale of interest. A transient can be a unidirectional impulse of either polarity or a damped oscillatory wave with the first peak occurring in either polarity. Transients are responsible for many power quality related malfunctions and failures. Transients can cause component to fail such as fuses, surge protectors, automatic transfer switches, cable switch gear, CT’s and PT’s. Transient voltages can result in degradation or immediate dielectric failure in all classes of equipment. High magnitude and fast rise time contribute to insulation breakdown in electrical equipment like switchgear, transformers and motors. Repeated lower magnitude application of transients to equipment can cause slow degradation and eventual insulation failure, decreasing equipment mean time between failures. Transients can cause back up UPS systems to turn on and off excessively. This can reduce the life span of a UPS system. Generally there are two different types of transient over-voltages: low-frequency transients and high-frequency transients. Low Frequency transients have frequency components in the few-hundred-hertz region and are typically caused by capacitor switching.

High-frequency transients have frequency components in the few-hundred-kilohertz region and are typically caused by lightning and inductive loads There is also the phenomenon known as extremely fast transients, or EFT's. Extremely fast transients have rise and fall times in the nanosecond region. They can be caused by arcing faults, such as bad brushes in motors. Due to the rapid rise and fall times of

Transients can damage insulation because insulation, like that in wires has capacitive properties.

Both capacitors and wires have two conductors separated by an insulator. If a transient pulse with a high enough frequency reaches a component, the capacitance of that conductor - insulation junction will present a path. If the transient pulse has enough energy it could damage that section of insulation. Transients can cause the insulation to break down in motors and transformers.

When a transient reaches the coil of a motor or a transformer it will dissipate the majority of its energy in the first few coils. Each successive coil presents more resistance and capacitance to the transient. This will reduce its magnitude and increase its period, reducing the energy. Since the majority of the energy is transferred to the first few coils, this is where the damaged insulation will typically appear.

52 In motors, fast-changing PWM voltage pulses can interact with the distributed inductance and capacitance of motor leads. This can result in an amplified peak voltage at the motor terminals. This peak voltage further stresses and degrades the insulation around the stator winding of the motor. The peak voltage magnitude at the motor terminals depends on the motor lead characteristics and the surge impedance of the motor; the smaller the motor and longer the leads, the greater the peak voltage. This is for this reason that it is recommended to avoid long motor leads.

Transient voltages can cause computer equipment to lockup and data to get garbled or even damage computer equipment. When a transient strikes your computer, it can cause internal noise spikes that can disrupt data. If the transient has sufficient energy, it can cause an arc within the internal components of the computer.

Transients can also affect fluorescent lighting. A fluorescent light illuminates because the gas inside of the light is ionized when voltage is applied across the electrodes. Transients can produce excessive energy that can displace the material within the electrodes. This will eventually reduce the amount of light given off by the fluorescent light and reduce the efficiency of the light. The reduced efficiency will reduce the life of the fluorescent light. Some of the common causes of transients include lightning, load switching, capacitor switching as well as loose wiring.

Maintenance Vol. 1 Lightning is the leading cause of power-line disruptions and outages. If facilities are not properly equipped, lightning can cause millions of dollars in damage and downtime of critical equipment. A bolt of lightning can be over 5 miles long, and reach temperatures in excess of 20,000 degrees Celsius. The currentcarrying capability of a lightning bolt can be upwards of 90,000A. Lightning can affect distribution equipment causing the equipment to burn out, catch on fire, or even explode. Direct lightning strikes or high electromagnetic fields produced by lighting can induce voltage and current transients in electric power lines and signal carrying lines. These will typically be seen as unidirectional transients, either positive or negative. When an inductive load is turned on or off a transient is produced. Transformers can also produce large transients when energizing. The transient is produced as a result of the collapse of the magnetic field of the coil.

Capacitor banks are switched in and out on circuits to compensate for reactive power caused by inductive loads. When the capacitor bank is switched into the circuit there is an initial inrush of current. The added capacitance causes a phase shift. This will cause a lowfrequency transient that will have a characteristic ringing. These types of transients are referred to as oscillatory transients. These types of transients can cause sensitive equipment to trip out and cause UPS backup systems to turn on and off multiple times. This can reduce the life of UPS systems. Since capacitor banks are used to compensate for reactive power caused by large inductive loads, they are switched on and off frequently. This makes oscillatory transients a very common power quality phenomenon. Transients are one of the leading causes of equipment malfunctions and failures. Understanding the cause of transients and how they affect various types of equipment will allow companies to improve quality and reliability of their equipment. Monitoring of incoming power, using Power Quality recording devices, can help identify potential power quality problems before they cause costly malfunctions.

UNBALANCE Unbalance refers to the asymmetrical components of a polyphase network. An ideal 3 phase system will have perfectly symmetrical components as shown below. All phases would have the same magnitude with proper phasing.

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Maintenance Vol. 1

sequence and the ratio of the zero sequence to the positive sequence. The benefit of this method is it takes into account both the magnitude and the phase shift of the poly-phase system. Typical limits on voltage unbalance range from 1% to 3% pending the application. Some standards to reference include EN50160 as well as IEC61000-2-4 and IEEE1159.

HARMONICS

Unbalanced phases will have asymmetrical qualities such as variations in magnitude or deviations in phasing. Voltage unbalance can cause heating in transformers. In general, utility supply voltage is maintained at a relatively low level of phase imbalance since even a low level of imbalance can cause heating effects on the generation, transmission, and distribution system equipment.

Harmonics are another power quality phenomenon that can cause equipment to malfunction. Harmonics are a sinusoidal component of periodic waves that have frequencies that are multiples of the fundamental frequency. Harmonics can cause computer equipment to lock up or cause the data to become garbled as well as causing transformers, motors and neutral lines to overheat. Linear Loads such as incandescent lights draw current equally throughout the waveform. Non-Linear loads such as switching power supplies draw current only at the peaks of the wave. It is these non-linear loads that cause harmonics.

Voltage unbalance more commonly emerges in individual customer loads due to phase load imbalances, especially where large, single phase power loads are used, such as single phase arc furnaces. In these cases, overheating of customer motors and transformers can readily occur if the imbalance is not corrected. There are generally three ways in which unbalance is measured, the NEMA method, the IEEE method and the IEC method. The NEMA method calculates the average of the line voltages then compares each individual line voltage to the average. This method assumed that the average voltage is equal to the rated value. In addition it does not take into account phasing.

If your fundamental frequency is 60Hz then the second harmonic would be 60Hz x 2 = 120Hz. The third harmonic would be 60Hz x 3 = 180Hz, and so on. Typically current harmonics will not propagate through a system. Voltage harmonics will propagate through a system, as they can pass through transformers. When non-linear loads get high enough they will cause harmonics in the voltage.

The IEEE method calculates the average of the phase voltages then compares each individual phase voltage to the average.

The IEC method of unbalance transposes the waveforms into 3 sets of symmetrical components based on phase rotation. These symmetrical components are the positive sequence rotation, negative sequence rotation and the zero sequence. The unbalance is then defined as the ratio of the negative sequence to the positive

Harmonics orders are characterized in different sequences, based on the rotation of their magnetic field. Positive sequence harmonics creates a magnetic field in the direction of rotation. NOTE: The fundamental is considered a positive sequence harmonic. Negative sequence harmonics develop magnetic fields in the opposite direction of rotation. This reduces torque and increases the current required for motor loads.

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Zero sequence harmonics creates a single-phase signal that does not produce a rotating magnetic field of any kind. These harmonics can increase overall current demand and generate heat. In three phase systems, the fundamental currents at any instant will always add up to zero in the neutral. The presence of zero sequence harmonics, such as the third harmonic on one phase will be in phase with the other phases of the 3 phase system.

Since they are in phase, rather than canceling each other (as is the case with the fundamental), they will sum together and can lead to high neutral currents. To determine the sequence of different harmonic order is relatively simple. Positive, Negative and Zero sequence harmonics repeat in a sequential order. (Positive, Negative then Zero) Since the fundamental frequency is positive this means the second order harmonic is a negative sequence harmonic. The third harmonic is a zero sequence harmonic. Below is a table of harmonics.

Although, Total Harmonic Distortion (THD) can be calculated for both current and voltage it can be misleading when analyzing current harmonics. This is because THD is referenced to the amplitude of the fundamental value. This does not typically cause any issues when analyzing voltage THD since the fundamental is always present in non-fault conditions. However, the same is not true for current. The current amplitude will fluctuate with the loads impedance. As loads turn off the fundamental current amplitude decreases. If the Current draw is very low (near zero) the THD value could appear to be quite high. This is deceiving because the current THD levels can be high while there is little to no current draw. Therefore, it is recommended that the Total Demand Distortion (TDD) measurement should be used for total current harmonic measurements. The Total Demand Distortion (TDD) references the total root-sum-square harmonic current distortion, to the percent of the maximum demand load current. (This is based on either a 15 or 30 min demand interval per IEEE 519). Therefore the reference value is the same throughout the test interval and it is a valid value. The power quality industry has developed certain index values to assess the distortion caused by the presence of harmonics. The two values most frequently indexed are total harmonic distortion (THD) and total demand distortion (TDD), although individual harmonic values are also indexed in different specifications, such as IEEE 519 and EN50160.

Problems associated with harmonics. Neutral Wires Overheating: Neutral Wires will over heat in 3 phase systems generally when the 3 phase system is unbalanced or there is an excess of Harmonic Triplens. (Harmonics divisible by 3 / Zero Sequence Harmonics) Zero sequence harmonics do not cancel out, instead they add together on the neutral. This can cause neutral currents that exceed the line current. This is commonly seen in single phase systems that are dedicated to electronic loads.

Zero Sequence harmonics will also be referred to as triplens at times. This is because zero sequence harmonics are always multiples of 3. One measure of harmonics is called THD, or Total Harmonic Distortion. THD is a measure of the harmonic components of a distorted waveform. THD can be calculated for either current or voltage. Total harmonic distortion is the RMS sum of the harmonics, divided by one of two values: either the fundamental value, or the RMS value of the total waveform. This is typically represented as a percentage of the fundamental.

Motor Overheating: Excessive voltage harmonics can cause motors to overheat. The rotation of the rotor depends on the torque produced by the phase sequence of the applied 3-phase power. Positive-sequence frequencies work to push the rotor in the proper direction. Negative-sequence frequencies oppose the direction of the rotor's rotation. Excessive of negative-sequence harmonics on a three-phase AC motor will result in a decreased performance and potential overheating. Higher-order harmonics tend to be attenuated more by system inductances and magnetic core losses; the primary harmonic of concern is the 5th, which is 300 Hz in 60 Hz power systems and 250 Hz in 50 Hz power systems. Zerosequence harmonics do not have a major effect on the rotor's torque; however they can cause increased current on neutral lines.

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Maintenance Vol. 1 Transformer De-rating: Waveform distortion can also cause heating in transformers. Harmonic current injection from customer loads into the utility supply system can cause harmonic voltage distortion to appear on the utility system supply voltage. The heating effect of harmonics is proportional to the square of the current and the square of the harmonic. In other words, an amp of 13th harmonic current creates far more heat than an amp of 5th harmonic current.

INTER-HARMONICS Inter-harmonics are defined as non-integer multiples of the fundamental frequency. The order of the inter-harmonic is defined as the ratio of the inter-harmonic frequency to the fundamental frequency. For example is the inter-harmonic frequency is 100Hz on a 60Hz system then the order of the inter-harmonic is 90 / 60 o r 1.5. If the inter-harmonic frequency is below the fundamental frequency then this may also be referred to as a sub-harmonic. Sources of inter-harmonics can include arcing loads, such as arc furnaces and welding machine, variable drives, static converters and power line signaling. Rapid changes in voltage or phase angle can generate inter-harmonics. These can changes can be highly depended on rapid load changes which can make inter-harmonics random in nature. Renewable energy sources can also cause rapid voltage changes that can generate inter-harmonics. This is because of their inconsistent output due to the random changes in the conditions that drive them. Some of the problems that can be caused by inter-harmonics include incandescent lamp flicker, low frequency oscillations in mechanical systems, fluctuations in the output of fluorescent lamps, interference with control and protection signals in power supply lines, telecommunication interference as well as thermal effects in equipment

grid line voltage. The same is true of wind energy. Wind energy output will vary with the amount of wind present. The intermittent nature of these energy sources can cause rapid voltage changes on the grid. Besides the power quality implications, renewable are causing some energy costing issues. The use of privately owned photovoltaic cells is causing a costing issue. They are connected to the grid so they use the grid almost as a battery. When they are producing electricity they supply voltage to the grid but when they are not producing power they pull power from the grid. This can lead to the charge to the customer being near $0. However they are still utilizing the grid 24 hours. Per European standards, low voltage systems rapid voltage changes generally do not typically exceed 5 % of nominal, however short duration changes of up to 10 % may occur sometimes.

FLICKER Flicker is a very specific problem concerning the human perception of the light variation emitted from incandescent light bulbs. It is not a general term for voltage variations. Humans can be very sensitive to light flicker that is caused by voltage fluctuations. Studies have found that voltage fluctuations in the frequency range 5-15 Hz is visible to the human eye. The peak sensitivity occurs at approximately 8 Hz. A light flicker modulation of just 0.25% at 8Hz can be noticeable. Modulations around 1% can be irritating. Human perception of light flicker is almost always the limiting criteria for controlling small voltage fluctuations. The figure below illustrates the level of perception of light flicker from a 60 watt incandescent bulb for rectangular variations. The sensitivity is a function of the frequency of the fluctuations and it is also dependent on the voltage level of the lighting.

RAPID VOLTAGE CHANGE (RVC) A rapid voltage change is a quick transition in RMS voltage between two steady-state conditions. The voltage during a rapid voltage change must not exceed the voltage sag or swell threshold. If it does then it would be considered as a voltage sag or swell. The characteristic parameter of the rapid voltage change is the difference between the steady- state value reached after the change and the initial steady-state value. Any load that has significant cyclic variations can cause voltage fluctuations. Arc furnaces are the most common cause of voltage fluctuations on the transmission and distribution system. Other causes of rapid voltage change include inconsistent renewable energy sources, such as solar energy and wind energy. With the expansion of photo-voltaic cells on roof tops voltage regulation becomes a greater problem. The intermittent output nature of the photo-voltaic cells will cause an intermittent rise and fall in the

In general today, flicker is measured using the IEC 61000-415 method. In this method we take the instantaneous voltage and compare it to a rolling average voltage. The deviation between these two is multiplied by a weighted curve. This curve is based on the sensitivity of the human eye at 120V 60Hz or 230V 50Hz. The end value is called a percentile unit. The percentile units go through a statistical analysis in order to calculate 2 values.

56 Short Term flicker or Pst; based on a 10 minute interval. Long Term flicker or Plt; based on a 2 hour interval. The basic criteria are simple. If the Pst is less than 1.0 then flicker levels are good. If Pst is greater than 1.0 then the flicker levels could be causing irritation. A couple of important things to remember about Flicker are it applies to incandescent lighting ONLY. Fluorescent lighting cannot be tested in this manner in this manner until weighted curves are developed for them. Since it uses a weighting curve it applies only to 120V 60Hz and 230V 50Hz.Voltages outside this range must be normalized to 120V at 60Hz or 230V 50Hz in order to analyze flicker based on the IEC61000-4-15 method. Common Causes of Flicker can include Source voltage variations, Inrush/surge currents as well as inadequate wiring and inter-harmonics. In general power quality plays an ever increasing role in today’s modern society. As technology advances maintaining a good power quality will become even more important. New renewable energy sources such as solar and wind in addition to new technologies such as EV automobiles present new challenges in maintaining good power quality. Understanding how different power quality events affect different types of equipment is essential in today’s world. Andrew Sagl has worked with Megger for 12 years. He is currently Product Manager, Power Quality and Battery Testing, and a specialist in power quality and battery testing technology and application. Andrew develops and supports power quality equipment, writes power quality and battery publications, and teaches training and seminars courses. He has a degree in Electronics and is a member of the IEEE Power Engineering Society and Battery Standards Group.

Maintenance Vol. 1

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

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arizona

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

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ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

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ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

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ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

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Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

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Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

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Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

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Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

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Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

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Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

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Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

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Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

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Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

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Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

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Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

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Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

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RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

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Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

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Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

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RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

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CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

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CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

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Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

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Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

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Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

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Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

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Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

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High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

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Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

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Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

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C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

missouri 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

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152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

173

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

164

oklahoma

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

182

183

184

185

186

187

188

189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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199

200

201

POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

206

207

208

209

210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

242

243

244

Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

Circuit Breaker Services

from

For Circuit Breaker Maintenance Solutions, Shermco Industries offers fast turnarounds, reliable repairs and state-of-the-art upgrades performed by knowledgeable, NETA certified technicians at multiple locations. From high voltage substations to industrial distribution needs, our comprehensive services and a “zero defects” approach assures trouble free operation and reliable performance. Our new mobile services include on-site reconditioning and remanufacturing for most breaker styles and our SF6 and oil processing trailers can get you up and running faster than fast.

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(be_this_guy!) Train with the Experts. Train with Shermco. www.shermco.com 888-SHERMCO

VOLUME 2

MAINTENANCE Vol. 2 HANDBOOK

SERIES III

HANDBOOK

Published By

MAINTENANCE

SERIES III

MAINTENANCE VOL. 2

Published by

InterNational Electrical Testing Association

MAINTENANCE VOL. 2 SAFETY HANDBOOK TABLE OF CONTENTS Testing Rotating Machinery: Dielectric Characteristic AC Test...................................... 5 Vicki Warren

Why You Should Use the Guard Circuit................................................................... 8 James White

Testing Rotating Machinery Polarization/Depolarization Current (PDC)...................... 11 Vicki Warren

The NFPA 70B – One of the Industry’s Best-Kept Secrets........................................... 14 Ron Widup and Jim White

The Benefits of Applying High Resistance Grounds for an Ungrounded Power System..................................................................................................... 18 Jim Vermeer

Best Practices for Impact Bump Testing Stator End Windings..................................... 21 Vicki Warren and John Letal

64S Protection Guide Theory, Application, and Commissioning of Generator 100 Percent Stator Ground Fault Protection Using Low Frequency Injection................ 24 Steve Turner

Get the Most Bang for Your Buck: Top Five Tests for Best Return on Investment............. 32 Don Genutis

Avoiding Metal-Clad Switchgear Failure Through Use of Partial Discharge Detection............................................................................................ 34 Tony McGrail, Jay Garnett, Matthew Lawrence

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Testing Rotating Machinery: QA Tests for MV GVPI Stator Windings...................... 38 Vicki Warren

Role of On-Line Condition Monitoring for Power Transformer Operation and Maintenance............................................................................. 42 Kenneth Elkinson and Tony McGrail

Smaller Commissioning Assignments Require Great Detail.................................... 45 Brian S. Moores

Deploying Thermal Cameras to Your Utility’s Best Advantage: A Tow-Pronged Approach................................................................................. 50 Brad Risser

Influence of the Test Voltage Wave Shape of the PD Characteristics of Typical Defects in Medium-Voltage Cable Accessories.......................................... 55 Hein Putter, Daniel Götz, Frank Petzold, Marco Stephan, Henning Oetjen

Optimize Stator Endwinding Vibration Monitoring with Impact Testing.................... 61 John Letal and Vicki Warren

Process Analysis – Your Path to System Knowledge.............................................. 67 Noah Bethel

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Maintenance Vol. 2

TESTING ROTATING MACHINERY: DIELECTRIC CHARACTERISTIC AC TEST NETA World, Spring 2014 Issue Vicki Warren, Iris Power LP Generators and motors typically enjoy 20 years or more of operation in utility and industrial applications before either the rotor or stator windings need to be replaced. However, if the machine is overloaded or subjected to a polluted environment, or was poorly constructed, failure may occur in just a few years due to premature aging. Over the past several years, off-line direct-voltage (dc) and alternating voltage (ac) tests have been used to locate and determine the severity or risk of failure and whether repairs are possible. Off-line tests have the advantages of accessibility, noise-free environments, ease of repair, and test variety. The disadvantages are that there are abnormal mechanical, thermal, and electrical stresses, and that they require a machine outage which can be timeconsuming. With dc, the voltage distribution is based on insulation resistance, while with an ac, the voltage distribution is based on capacitance. Therefore, dc tests are suitable for locating cracks and contamination, whereas ac tests are used to evaluate how well the insulation system is consolidated during manufacturing and the impact of thermal aging. A thorough condition-assessment evaluation should include dc and ac testing as well as a visual inspection.

DIELECTRIC CHARACTERISTIC AC TESTS Capacitance Insulation systems are by design a capacitor with a dielectric of organic resin, glass, and mica that separates the copper conductors from the core iron. As an insulation system ages, the organic resin is slowly replaced with air-filled voids that change the dielectric constant, or capacitance, of the insulation system. In pre-1970 machines, the change in the dielectric constant was often significant enough that it was possible to detect the effects of aging by measuring the total capacitance of a winding. Though still possible on severely deteriorated newer windings, the change in capacitance is often so subtle that until the winding is nearing failure it is difficult to observe any changes. The capacitance can be measured at a low voltage and best done with a bridge that will eliminate the effect of the stray capacitance of the test supply.

Fig. 1: Thermal Delamination Fig. 2: Contamination A variation on the capacitance test is the capacitance tip-up test, which is performed on complete windings or preferably individual winding phases with an accurate capacitance bridge. At a relatively high voltage, the gas within voids ionizes to produce sufficiently high conductivity to short the void out causing partial discharge. This produces an increase in capacitance between low- and highvoltage tests. The capacitance Clv is measured at 0.2E where E is the rated phase-to-phase voltage and Chv is measured at line-toground voltage which is about 0.58E. The capacitance tip-up is: ΔC = (Chv – Clv)/Clv The higher ΔC is, the more voids there are in the winding groundwall. For a well bonded groundwall insulation:

ΔC < 1% for modern epoxy mica insulation ΔC < 3 or 4% for older asphaltic mica windings ΔC = (Chv – Clv)/Clv ΔC = (690 – 688)/688 = 0.3%

●● Delamination ⇒ capacitance decreases (1% change) [Figure 1] ●● Moisture contamination ⇒ capacitance increases (5% change) [Figure 2] Fig. 3: Capacitance Tip-Up (W-phase is notably lower than the other two phases indicating minor delamination on this phase)

6

Maintenance Vol. 2

It should be noted that if the coils have semiconducting and grading voltage stress control layers, these influence the results of this test. At the higher voltage, the grading layers of silicon carbide material conduct to increase the effective surface area and thus the capacitance of the sections of winding being tested, and so may give a false indication of high void content. However, if the results are trended against time, an increase in ΔC may give a true indication of increased void content in the groundwall insulation.

DISSIPATION FACTOR/POWER FACTOR Dissipation Factor (DF or tan δ) Like the capacitance test, the dissipation factor test also looks for changes in the insulation system of the winding. This test, however, is done at high voltage steps that increase from zero to normal line-to-ground voltage. The test compares the real power loss (IR) due to the presence of voids in a delaminated insulation as a ratio to the capacitance power (IC), or the tangent of δ (IR / IC) as shown in Figure 4. The absolute value of the dissipation factor is also useful in determining the extent of curing in a new insulation system.

DF = tan δ = mW / mVar = IR / IC

●● Delamination ⇒ tan δ increases ●● Moisture contamination ⇒ tan δ increases

DFepoxy ≤ 0.5%



DFasphaltic ≤ 3 to 5%.

Trending the results against time makes the best use of this test. As with the Δ capacitance test, voltage stress coatings can lead to ambiguous results obtained at high voltage.

IC = capacitance current IT = total current IR = resistive current DF = Tan d = IR / IC PF = Cos q = IR / IT

it possible for comparing the results to other machines. This is a valuable test for determining the extent of curing in new coils or winding. Because the presence of the voltage stress control in a complete winding greatly affects the results, tests on complete windings can be ambiguous.

PF = cos Ѳ = mW / mVA = IR / IT

●● Delamination ⇒ cos Ѳ increases ●● Moisture contamination ⇒ cos Ѳ increases

PFpolyethylene ≤ 0.01%



PFepoxy ≤ 0.5%



PFasphalt ≤ 3 - 5%

TIP-UP TESTS The tip-up test (Δ tan δ or Δ cos θ) done at two voltages, one below the inception of partial discharge activity (25% line-toground) and one at line-to-ground voltage may provide some information regarding the integrity of the stator insulation system [Figure 5]. The intention of the test is to observe the increase in real power loss (ΔIR) due to partial discharges within voids of a delaminated insulation, and therefore investigate the quality of the resin bond. This test is widely used by manufacturers of resin rich and individual VPI coils as a quality check. As with the capacitance tip-up test, the results of this test are influenced by the presence of voltage stress coatings on the coils, since at high lineto-ground voltage currents flow through it to produce additional power losses. Because this test method measures total energy it is only sensitive to widespread delamination and not how close the winding is to failure (worst spot). - Tip-up = DF/PF high - DF/PF low (typical results: 0.5% for epoxy) - High at 100% line-to-ground rated voltage (above partial discharge inception voltage - PDIV) - Low at 25% line-to-ground rated voltage (below PDIV) ΔDF=(1 - 0.74)/0.74 = 35%

Fig. 4: DF and PF Tests

POWER FACTOR (PF OR COS Ѳ) Similar to the dissipation-factor test (tan δ) the power factor (cos Ѳ) test is looking for any changes in the insulation system of the winding. The test compares the real power loss (IR) due to the presence of voids in a delaminated insulation as a ratio to the total power (IT), or the cosine of qq (IR / IT) as shown in Figure 4. The test is normally done at a specific applied voltage that makes

Fig. 5: Dissipation Factor (DF) Tip-Up

7

Maintenance Vol. 2 OFF-LINE TEST EFFECTIVENESS AC VS DC Voltage

11 kV

KVA

1 to 7 ms

Insulation Class

F

Cooling

Air/water

Date Manufactured

208

The winding is global VPI design meaning that the winding was placed in the core in a green or resin free-state and then the entire winding and core subjected to a vacuum-pressure-impregnation process to consolidate the winding insulation layers and anchor the winding in the core. As shown in the table below, the dc test results for the IR/PI and dc insulation tests were acceptable, but both the power-factor and tip-up tests were elevated. A visual inspection of the winding revealed notable damage to the voltage stress coatings (Figure 6) as well as possible areas of coil overheating (Figure 7). This suggests dc tests were not adequate to fully evaluate the condition of the winding and the need for ac dielectric characteristic tests. 2013 Results

Test

Insulation Resistance (IR) at 5 kV

Polarization Index (PI) at 5 kV

DC Insulation Test at 25 kV

Power Factor at 2 kV

Power Factor Tip-UP (2 kV to k kV)

U

17 GΩ

V

17.2 GΩ

W

17.1 GΩ

U

5.01

V

5.04

W

4.26

U

Pass

V

Pass

W

Pass

U

1.00%

V

0.99%

W

0.98%

U

0.65%

V

0.66%

W

0.65%

Fig. 6: Voltage Stress Coating Damage

IEEE reference (acceptable limit)

IEEE 43 - 2000 (100 MΩ)

IEEE 43 - 2000 (>2)

IEEE 95 - 2002 (Pass)

IEEE 286 - 2002 (0.5%)

IEEE 286 - 2002 (0.5%)

Fig. 7: Overheated Coil

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

8

Maintenance Vol. 2

WHY YOU SHOULD USE THE GUARD CIRCUIT NETA World, Spring 2014 Issue James White, Shermco Industries, Inc.

WHAT’S IN A NAME? Every field technician knows what a megohmmeter is. Usually we just refer to it as a megger, although that’s like calling all tissue paper Kleenex or all copiers Xerox machines. The correct name is megohmmeter as Megger is a trademark. Whatever you want to call it, megger, insulation resistance test set, or megohmmeter, it is the most commonly-used insulation test set in the field. Small, lightweight, and relatively easy to use, various models of megohmmeters produce voltages from 250 to 15,000 volts so that the quality of insulation can be measured and trended. One of the problems in the common use of this little wonder is that the third terminal on the test set, known as the guard circuit, is rarely used because many people do not understand its function. Figure 1 shows a typical megohmmeter with a range from 500 volts to 5,000 volts. It is suitable for testing smaller insulation systems including motors, control wiring, instrument transformers, and small dry-type power transformers of up to about 15 kV, depending on the mass of the insulation system. A megohmmeter can also be used on larger transformers and liquid-insulated transformers, but typically an insulation power-factor test set is also used.

Fig. 1: Typical Megohmmeter with a guard circuit marked as Terminal G

VERIFYING INSTRUMENT FUNCTION At a customer’s site we were preparing to perform field testing of a small transformer as part of the training. The customer brought out his megohmmeter which looked as if it had been run over by a pickup truck. When asked if it worked, he proceeded to operate it, causing sparks to fly to the extent that I started looking for a fire extinguisher.

I suggested we try a simple test to see if it really worked. The megohmmeter, of course, had no output. The customer exclaimed that they had been using it for years and had always gotten good readings; no wonder! The test described below takes only a few minutes and will prove whether the megohmmeter actually works, and if it does, what its output voltage is. By the way, many thanks to Mark Lautenschlager for showing me this little trick many years ago. This test requires a volt/ohmmeter, such as a DVOM or even an analog VOM. I often use a Fluke or Simpson 260. The actual meter does not matter, but the input impedance should be known. All meters of this type use a resistor behind the input terminal. Less expensive meters may have an input impedance of just a few thousand ohms, while more expensive meters may have input impedances of 10 megohms to 20 megohms. Meters with high input impedances limit current flow through them, preventing problems when troubleshooting. In the example shown in Figure 2 the megohmmeter is connected from the “-“ terminal (marked as LINE) to the “-“ terminal of the VOM. The “+” (marked as EARTH) terminal on the megohmmeter is connected to the “+” terminal on the VOM. Those of us in our declining years remember using megohmmeters marked LINE and EARTH and assumed EARTH was the negative terminal. Actually, the negative terminal should be connected to the conductor under test and the positive terminal should be connected to ground.

Fig. 2: Megohmmeter test circuit figure courtesy American Technical Publishing from “A Technician’s Guide to Low- and Medium-Voltage Circuit Breakers” By James R. White A typical Fluke DVOM has an internal resistance of 10 megohms, while a Simpson 260 has 20 megohms. Connect the megohmmeter to the highest voltage terminal on the DVOM/VOM and set the megohmmeter output voltage to match. Do not exceed the DVOM/VOM’s

9

Maintenance Vol. 2 maximum voltage or you will get a brand new meter – at a cost, of course. In the example shown in Figure 2, a Simpson 260 is being used with a 1,000-volt maximum voltage rating. The megohmmeter’s output voltage is set to 1,000 volts and turned on. The DVOM/VOM should read 1,000 volts and the megohmmeter should read 20 megohms (or whatever the input impedance should be). As a double-check, reduce the output voltage from the megohmmeter to 500 volts. The DVOM/ VOM should read 500 volts, but the megohmmeter should still read 20 megohms. The input impedance will not change unless the terminal is changed to the 500 V input terminal on the DVOM/VOM as there is a different resistor behind that terminal. In the case of a Simpson 260 the 500 V terminal has a 10 megohms input impedance. Be aware that line and battery-powered megohmmeters will have voltage outputs close to their ratings, but hand-cranked megohmmeters will not. This is due to the clutch used on hand-cranked megohmmeters to limit their output. They will often have an output voltage of 90 percent to 95 percent of their rating. This does not affect the test, but can cause some concern if you are not ready for it.

WHAT DOES THE GUARD DO? The guard circuit is a means to eliminate unwanted return currents from the measurements being taken. It is very similar to the unmetered return on dc high-potential test sets. Any test current that returns via the guard terminal bypasses the measurement circuit. This allows a much more accurate measurement to be taken. There are two ways a guard can be used, by dividing the insulation system into smaller pieces and by eliminating surface leakage.

Fig. 4: Guards Daisy-Chained In Figure 4, not only are the bushings guarded from surface leakage, but the guard is also being used for testing the transformer. Multiple Guards can be tied together and any return current from the guard circuit is routed above the metering and not measured. At this point, you should be slapping yourself in the forehead and making a Homer Simpson-like sound. Circuit breakers can also benefit from using the guard circuit. When performing the dc overpotential or insulation resistance tests when humidity is high, using the guard can provide more accurate results. Figure 5 shows the guard circuit used when testing a circuit breaker. The guard collars are placed just below the primary disconnect (on the insulator), daisy-chained, then connected to the guard terminal. On a high potential test set, this would be the unmetered return terminal.

ELIMINATING SURFACE LEAKAGE Another very practical use for the guard circuit is to eliminate the effects of surface leakage on bushings. Figure 3 shows a bushing with a guard connected to a conductive collar located beneath the top petticoat. Any surface leakage current is now diverted above the meter by the guard. By daisy-chaining the collars around the bushings on the energized winding, all of the bushings can be guarded against surface leakage and a more accurate test can be made (see Figure 4). The conductive collars do not have to be the rubber collars included in the Doble® insulation power-factor test sets. Tie wire, screw-type hose clamps, or, in a pinch, aluminum foil, can be used. However, the closer the guard collar conforms to the surface of the bushing, the better.

Fig. 5: Using the Guard Circuit on a Circuit Breaker

SMALLER SECTIONS OF INSULATION EQUALS BETTER TEST RESULTS A two-winding transformer can be tested with or without using a guard. The standard test connections for testing a two-winding transformer are: ●● HV winding to LV winding and ground ●● LV winding to HV winding and ground Fig. 3: Guard Being Used to Eliminate Surface Leakage

●● LV winding and HV winding to ground

10

Maintenance Vol. 2

Note that the untested winding is connected to ground, not left floating. Why not leave the untested winding ungrounded? The energized winding will induce a charge into the untested winding and could present a safety hazard or affect the test results by discharging at some point during the test. Always ground the untested winding. When using a guard the connections are somewhat different. Any leakage current returning through the guard circuit is routed around the metering and is not measured. Figures 6, 7, and 8 illustrate the connections for using a guard when testing a twowinding transformer.

Fig. 8: High-voltage to low-voltage, ground guarded

THERE ARE GUARDS, AND THEN THERE ARE GUARDS

Fig. 6: High-voltage winding to low voltage and ground

There are two types of guard circuits that may be found on megohmmeters, the hot guard and the cold guard. The hot guard terminal on the megohmmeter is at or near line voltage, while the cold guard terminal is at or near zero volts. Why does this matter? The hot guard cannot be connected to ground, since it shorts out the meter. This means the high-to-low, ground guard test cannot be performed with a hot guard megohmmeter. The easiest method for determining whether your megohmmeter has a hot or cold guard circuit is to connect the guard to ground and turn on the megommmeter. If your meter goes to zero, you have a hot guard. An open meter reading (or one of these ∞) indicates a cold guard. Cold guard circuits require the use of an isolation transformer, so they will not be found on inexpensive megohmmeters.

SUMMARY

Fig. 7: Low-voltage winding to high-voltage and ground In Figure 6, the leakage current has two paths: from winding-towinding and then winding-to-ground. The guard is connected to the low-voltage winding, and any current to that winding is routed above the metering and is not measured. Only the current from the high-voltage winding to ground is measured. In Figure 7 the low-voltage winding is energized and any leakage current from the high-voltage winding is routed above the metering by the guard and is not measured. Figure 8 shows the winding-to-winding test. The guard is connected to ground, and the transformer is tested from the high-voltage winding to the low-voltage winding. Everything seems to be going swimmingly, but when the guard is connected to ground the meter reads zero. What’s up with that?

Guards are useful for testing most types of insulation systems. The next time an insulation resistance test is needed, think about the return paths and see if the guard can cut that insulation system into smaller pieces. If you are measuring lower insulation resistance values than you think should be read, use the guard to eliminate leakage from affecting the measurements. The guard can make your insulation testing a little easier and more accurate. James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

11

Maintenance Vol. 2

TESTING ROTATING MACHINERY POLARIZATION/DEPOLARIZATION CURRENT (PDC) NETA World, 2014 Issue Vicki Warren, Iris Power LP The insulation resistance (IR) and polarization index (PI) tests [IEEE Std. 43-2000, ANSI/NETA ATS/MTS], should be done prior to application of any high voltage tests or return to service to assure that the winding is not wet or dirty enough to pose a risk of failure that might be averted by a cleaning and drying-out procedure. IR/ PI is a useful indicator of contamination and moisture on the exposed insulation surfaces of a winding, especially when there are cracks or fissures in the insulation. These tests are easily done (see NETA World Winter 2011 and Spring 2012 issues). Since squirrel cage induction motor rotor windings are not insulated, these tests are not appropriate. Resistance testing is principally a pass/fail criterion and cannot be relied upon to predict the condition of the main insulation except when the insulation has already faulted. Experience has shown that IR/PI is a useful indicator of contamination and moisture on the exposed insulation surfaces of a winding, especially when there are cracks or fissures in the insulation. However, as discussed in IEEE 43, the IR/PI test does not seem to be sensitive to many other stator winding insulation problems such as: ●● Loose coils in the slot that lead to insulation abrasion

THEORY The new draft standard (IEEE Std. 43 draft revision 2012) has an annex that deals with additional information that can be obtained by applying a stable dc voltage to a complete stator winding or individual phases for 1000 to 2000 seconds and recording the polarizing current IP versus time. The voltage is then removed and the discharge current ID is monitored as a function of time using a suitable discharge circuit. When the voltage is removed, reverse current flows and the molecules in the insulation become disorientated and the space charge dissipates. This discharge current ID has two main components: a capacitive discharge current component, which decays nearly instantaneously, depending upon the discharge resistance; and the absorption discharge current, which will decay from a high initial value to nearly zero with the same characteristics as the initial charging current but with the opposite polarity. Normally, neither the surface leakage IL nor the conduction current IG affects the discharge current. Differences in the IP and ID [Figure 1] may indicate winding lack of curing, moisture absorption, surface contamination, damage to the voltage stress coatings, or severe thermal deterioration of the bulk of the insulation.

●● Delamination of the insulation due to operation at high temperature ●● Separation of the copper from the groundwall insulation due to load cycling ●● Deterioration of the stress relief coatings ●● Partial discharge (PD) between coils in different phases due to insufficient spacing in the endwindings AC tests, such as partial discharge (described in NETA World Winter/Spring 2013) are effective in finding these issues, but are cumbersome to do in an offline configuration due to the need of a large ac power supply; therefore, more sophisticated dc tests that some have proposed may detect more kinds of problems than the simple IR/PI test. Included in the NETA World spring 2012 issue was a section about the dielectric response analysis (DRA) or polarization/depolarization current-measurement (PDC). This measures the charging and discharging currents of the winding insulation of stator or rotor winding. Reportedly, the results of the measurement provide information about the condition of machine insulation (cleanliness, humidity, ageing, corrosion, resin decomposition, and similar characteristics).

Fig. 1: Charging and Discharging Curves

EXAMINATION OF THE PDC TEST Since the IEEE 43 standard suggests that the PDC test is valid for testing windings for thermal deterioration, tests were done on a motor stator rated 13.2 kV, 6000 HP known to be thermally aged, but clean and dry. Both the PDC test and the ac offline partial discharge test were done, as the latter has proven to be effective for evaluating insulation delamination. The stator had an asphaltic mica

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insulation system and was several decades old. The three phases in the stator could be isolated from each other to facilitate testing of each phase.

POLARIZATION/DEPOLARIZATION TEST For these tests, a PDTech DRA 3 was used to record the polarizing and depolarizing dc currents. It applies a positive dc voltage to the test object at a selected voltage (usually 5 or 10 kV for these experiments) and for a selected time (usually 1000 s – about 16.7 minutes), while measuring the charging current. The dc supply is then removed from the test object and the test object is grounded. The discharge current-to-ground is then measured for the same amount of time. Software records these currents, inverts the discharge current, and displays both the charge and discharge currents in the same plot against time, with the plot time origin starting from either the start of the charge cycle, or the start of the discharge cycle (Fig. 2). The difference in the charge and absolute value of the discharge current can also be displayed. The instrument also calculates the IR and PI. All tests were done at 20°C.

Fig. 3: LF PD plot for phase A, which had the highest PD at 8 kV. Note that the polarity of the PD plotted between 0 and 180 degrees has been inverted. The linear scale ranges from 0 to 11 nC.

Fig. 2: PDC plot for A-phase with a 10 kV charge cycle (other phases were identical). The charge current is the upper line and the discharge current is the bottom line. The logarithmic vertical scale goes from 0.1 μA to 1000 μA and the horizontal axis ranges from 1 to 1000 seconds.

Fig. 4: PD response from stator phase A, which had the highest PD at 8 kV.

PARTIAL DISCHARGE TEST

CONCLUSION

Partial discharge tests were conducted using a conventional IEC 60270 PD detector, a PDTech DeltaMaxx, working in the low frequency (<3 MHz), broadband range. This instrument automatically converts the measured pulse magnitude in mV into pC, per the procedure in IEC 60270. The PD was also measured in the VHF range (30—300 MHz) range with an Iris Power TGA-B, more typically used for on-line PD monitoring. This device does not perform an automatic normalization, instead it reports the PD magnitudes in mV. The PD tests were performed at rated line-toground voltage, and the data was recorded after stabilization at the test voltage for 10 minutes. The low frequency (LF) and VHF phase-resolved PD plots for the worst phase (A-phase) are shown in Figures 3 and 4, respectively.

Table I shows a summary of the test results for each phase of the winding. PDC plots for each phase are shown in Fig. 2. When all three phases are super-imposed, all the charge currents and all the discharge currents overlap completely. Test Configuration

IR

PI

(GΩ)

VHF PD (mV)

LF PD (nC)

DF (@2 kV)

Tip-Up

Qm+

Qm+

Qm

(%)

(%)

A

5.1

3.4

1066

888

9.7

4.7

0.79

B

5.2

3.4

275

330

3.7

4.6

0.73

C

5.0

3.4

433

440

2.9

4.8

0.80

Table 1: Summary of diagnostic results for the motor stator winding

Maintenance Vol. 2 It is clear from Table I that A phase has the highest PD in both frequency ranges. Since the positive and negative PD is about the same (within +/- 25%), then based on normal PD interpretation rules (see IEEE 1434 or IEC 60034-27), one suspects the PD is due to groundwall delamination, and when compared to the instrument manufacturer’s database would be ranked as Very High. PDC has been proposed as an off-line tool that can detect issues besides contamination and moisture absorption, such as something that can be used to confirm the diagnosis of insulation condition obtained from on-line PD testing, without having to use a large ac transformer to energize the winding for an offline PD or tip-up test. The comparison tests described here did not produce consistent results. Clearly more tests are required to determine its efficacy.

REFERENCES IEEE Recommended Practice for Testing Insulation Resistance of Rotating Machinery, IEEE std. 43-2000 ANSI/NETA Standard for Acceptance Testing Specifications for Electrical Power Distribution Equipment and Systems 2009 edition ANSI/NETA Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems 2007 edition Stone, G., and Sasic, M., Experience with DC PolarizationDepolarization Measurements on Stator Winding Insulation, Electrical Insulation Conference (EIC), Ottawa, Ontario, March 2014. IEC 60034-27, “Off-line partial discharge measurements on the stator winding insulation of rotating electrical machines” Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in mediumto high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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THE NFPA 70B – ONE OF THE INDUSTRIES BEST-KEPT SECRETS NETA World, Spring 2014 Issue Ron Widup and Jim White, Shermco Industris As NETA members, we are all familiar with the ANSI/NETA Standard for Maintenance Testing Specifications. The current edition of the MTS was published in 2011 and is due for revision in 2015. While many NETA members may have heard of NFPA 70B, and some even involved with its periodic revision, all should be intimately familiar with it, what it contains, and how it can augment the ANSI/NETA MTS. NFPA 70B, Recommended Practice for Electrical Equipment Maintenance is a document every NETA Accredited Company should have on its shelves. While the ANSI/NETA MTS does an excellent job of covering the electrical testing and maintenance requirements for virtually every piece of electrical equipment in an electrical power system, by design it is a what to do specification and not a how to do it document. That is where NFPA 70B comes in to help bridge the gap on electrical maintenance requirements. NFPA 70B covers maintenance philosophies, short-circuit studies, power quality, testing and test methods, maintenance of electrical equipment including recommendations on frequency of maintenance, recommendations on maintenance for electrical power system equipment such as switchgear, circuit breakers, transformers, UPS, and rotating equipment, vibration. It even has sections on portable electric equipment and equipment located in classified areas. Other chapters include how to implement a reliability-centered maintenance (RCM) program, electrical disaster recovery (new), photovoltaic systems (new), electric vehicle charging equipment (new), and wind power electric systems and equipment (new).

ORIGIN OF DEVELOPMENT OF NFPA 70B [Note: this information is taken verbatim from the latest version of NFPA 70B, the 2013 edition] In the fall of 1967, the Board of Directors of the National Fire Protection Association authorized the formation of an Ad Hoc Committee on Electrical Equipment Maintenance to determine the need for the development of a suitable document on this subject. The purpose of the document would be to give recommendations on the maintenance of various types of electrical installations, apparatus, and equipment usually found in industrial and large commercial-type installations. A diversified group representing various interests and organizations was invited to participate. At a meeting of the Ad Hoc Committee held January 10, 1968, in New York, with 31 representatives attending, it was pointed out that several requests had been made to the National Electrical Code Committee to include maintenance recommendations in the National Electrical Code®. The subject had been discussed by the Correlating Committee of the National Electrical Code Committee, and the decision was made that the Code was not the proper document in which to cover the maintenance of electrical equipment. However, the committee recognized that “lack-of maintenance” frequently resulted in serious injuries and fatalities as well as high monetary damage. Electrical equipment maintenance was a subject requiring attention.

Whew! That’s a bunch! There are also sixteen annexes that contain information on conducting walk-through inspections, NEMA configurations, RCM, and energy efficiency of motors…. just to name a few.

Fig. 1: Preparing for maintenance and checking for the absence of voltage

Fig. 2: The testing of a large power transformer

Maintenance Vol. 2 It was noted at that time that electrical safety information broke down logically into four main subdivisions: (1) design or product standards, (2) installation standards (as covered by the National Electrical Code and the National Electrical Safety Code), (3) maintenance recommendations, and (4) use instructions. The NFPA had not yet started work on NFPA 70E®, Standard for Electrical Safety in the Workplace. The problem was to explore whether something more should be done in the interest of electrical safety on the maintenance of electrical equipment and what form activity in this field should take. It was recognized that much had been done to enunciate maintenance needs for specific types of equipment by the equipment manufacturers, and that guidance was available on the general subject from a number of sources. Therefore, it was determined that bringing together that guidance in the form of general guidelines in a single document under the NFPA procedure was advantageous. The stature of the document would be enhanced by becoming associated with the National Electrical Code. To this end, a tentative scope was drafted for presentation to the Board of Directors of the National Fire Protection Association with a recommendation that an NFPA Committee on Electrical Equipment Maintenance be authorized.

Fig. 3: VLF testing of a medium-voltage cable On June 27, 1968, the NFPA Board of Directors authorized the establishment of an NFPA Committee on Electrical Equipment Maintenance with the following scope: “To develop suitable texts relating to preventive maintenance of electrical systems and equipment used in industrial type applications with the view of reducing loss of life and property. The purpose is to correlate generally applicable procedures for preventive maintenance that have broad application to the more common classes of industrial electrical systems and equipment without duplicating or superseding instructions that manufacturers normally provide. Reports to the Association through the Correlating Committee of the National Electrical Code Committee.” The committee was formed, and an organizational meeting was held December 12, 1968, in Boston. Twenty-nine members or representatives attended. The Recommended Practice for Electrical Equipment Maintenance represented the cumulative effort of the entire committee.

15 The development of NFPA 70B follows the standard NFPA process, with committee members from different interests and industries. NETA members to the committee are Dave Huffman (Power Systems Testing Company), who officially represents NETA on the committee, and Jim White and Ron Widup who represent Shermco as an installer/maintainer member of the committee, independent of NETA.

Fig. 4: Medium-voltage breaker maintenanceduring an outage The technical committee reports to the same oversight committee as the NFPA 70E and is considered to be a sister document to the 70E. This is due to the fact that, as NFPA 70E states in section 130.5 IN No. 1, “Improper or inadequate maintenance can result in increased opening time of the overcurrent protective device, thus increasing the incident energy” and Section 200.1, Scope states, “(3) For the purpose of Chapter 2, maintenance shall be defined as preserving or restoring the condition of electrical equipment and installations, or parts of either, for the safety of employees who work where exposed to electrical hazards.” Electrical power systems and equipment cannot be considered to be safe unless they are properly installed and maintained. Even more emphasis will be placed on maintenance in the 2015 edition of NFPA 70E.

Fig. 5: Without local indication when was it last tested or maintained?

16 CONDITION OF MAINTENANCE How Do I Determine if the Equipment I am About to Work on Has Been Properly Maintained? One of the sticking points during the revision for the 2015 edition of NFPA 70E was how to verify condition of maintenance. When a technician or engineer enters a facility to perform testing or maintenance or to operate an electrical power system, how can he know when the last maintenance was performed? How can that same worker determine its condition of maintenance? One answer is to request the report from the last maintenance shutdown or PM that was performed. This may not be a very satisfactory answer as those records are not always available and, really, who has the time to pour through a huge stack of documents? A better solution was added to the 2013 edition of NFPA 70B in Section 11.27, Test or Calibration Decal System. Tim Crnko of Cooper-Bussmann proposed this system, and it is based on one that Shermco and other NETA-Accredited Companies have used for years.

Maintenance Vol. 2 Simply put, there are three color-coded labels: red, yellow and white. Red indicates there is a major defect and the equipment should either not be placed into service or should be removed immediately from service. Yellow means there is a minor defect that does not directly affect the serviceability or safety of the equipment, but it should be addressed as soon as possible. White means there were no defects found and the equipment is fully ready for continued service. Figure 1a and 1b show how the labels look in NFPA 70B and in the field. Since NFPA 70B is printed in black and white, the labels are in gray-scale, not color.

11.27 states, “11.27.1. General. After equipment testing, device testing, or calibration, a decal on equipment, in conjunction with test records, can communicate the condition of electrical equipment to maintenance and service personnel. This can be important for assessing the hazard identification and risk assessment for electrical safety procedures as well as the condition of electrical equipment. 11.27.2 Decal. After a piece of electrical equipment or device is tested and/or calibrated, a color-coded decal should be attached on the exterior enclosure to that particular equipment. The decal should include the following: ●● Date of test or calibration ●● Person or outside company who performed the testing or calibration ●● Color coding indicating the service classification as described in 11.27.3.” Fig. 7: Low-voltage circuit breaker maintenance We have only heard one negative comment when this system is discussed with others. That person said, “You mean you put a label on every piece of equipment? That would mean hundreds of labels!” Actually, it can be thousands of labels in a large shutdown. These are small, unobtrusive labels and do not interfere with the larger safety-oriented labels that may be required by manufacturing standards, OSHA, and NFPA 70E.

Fig. 6: Overall equipment condition varies from site to site

The biggest advantage to the three-color labeling system is that it allows instant verification of the state of equipment maintenance and when that maintenance was performed. Wading through reams of paper or databases is not needed to determine if the electrical device has been maintained within recent and reasonable time frames, which then helps the worker determine if it is safe to proceed with that test or to operate that piece of equipment.

Maintenance Vol. 2 However, it does not eliminate the need for common sense! Just because a label is in place and indicates the equipment was safe for continued service when it was applied does not relieve the worker from correctly assessing the current state of the equipment or to do a proper JHA. There is no autopilot mode when working on or near energized electrical equipment. Shermco has used this labeling system for years with great success. Our customers appreciate being able to quickly determine the electrical power system’s condition and work with our technicians during shutdowns and turnarounds to make their personal notes on what equipment needs immediate attention and which will need further work at another time. If the equipment cannot be repaired during the shutdown, the labels provide a reminder system that encourages that the defects be addressed as soon as possible. It is a great customer-service feature that all facilities and test and maintenance companies should employ. Its inclusion into NFPA 70B provides access to all companies and its [soon to be] reference in the 2015 NFPA 70E (Chapter 2, Section 200.1, Scope, Informational Note) should encourage more companies to demand it.

SUMMARY NFPA 70B is one of the best how-to maintenance references a company can have. It is a great companion to ANSI/NETA MTS and covers information that is not in the ANSI/NETA standard. As new types of electrical systems and new requirements for maintenance are being added, NFPA 70B grows ever larger. There are 283 pages stuffed full of maintenance techniques, safety cautions, and forms. The 2006 edition was 227 pages, so it is easy to compare how much new information has been added in the last two editions. NETA Accredited Companies as well as industry will benefit from using NFPA 70B, as it does not merely repeat the contents of ANSI/NETA MTS, but provides differing and expanded views of maintenance and testing requirements which can assist in tailoring services to the customer and provide insight on newer technologies and systems. NETA’s customers can benefit from NFPA 70B by learning what PM, PdM and RCM are used for and how they are best implemented. NFPA 70B has an inherent value and purpose for the NFPA. The NFPA’s primary mission is to reduce the worldwide burden of fire and other hazards by providing and advocating consensus codes and standards, research, training, and education. By implementing and executing the electrical power system tests as specified by NETA, coupled with the guidance for maintenance and safety provided by NFPA 70B and NFPA 70E, the owners, users, and workers of electrical equipment are in a better position to manage the challenges associated with all of it. And that is truly a win-win situation.

17 Ron Widup and Jim White are NETA’S representatives to NFPA Technical Committee 70E (Electrical Safety Requirements for Employee Workplaces). Both gentlemen are employees of Shermco Industries in Dallas, Texas a NETA Accredited Company. Ron Widup is President of Shermco and has been with the company since 1983. He is a Principal member of the Technical Committee on “Electrical Safety in the Workplace” (NFPA 70E) and a Principal member of the National Electrical Code (NFPA 70) Code Panel 11. He is also a member of the technical committee “Recommended Practice for Electrical Equipment Maintenance” (NFPA 70B), and a member of the NETA Board of Directors and Standards Review Council. Jim White is nationally recognized for technical skills and safety training in the electrical power systems industry. He is the Training Director for Shermco Industries, and has spent the last twenty years directly involved in technical skills and safety training for electrical power system technicians. Jim is a Principal member of NFPA 70B representing Shermco Industries, NETA’s alternate member of NFPA 70E, and a member of ASTM F18 Committee “Electrical ProtectiveEquipment for Workers”.

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THE BENEFITS OF APPLYING HIGH RESISTANCE GROUNDS FOR AN UNGROUNDED POWER SYSTEM NETA World, 2014 Winter Issue Jim Vermeer, Shermco Industries

Power system grounding is provided to improve safety and minimize equipment damage during a fault condition. This article discusses some of the options that are implemented for power system grounding. Furthermore, a case study is provided to support the implementation of a high resistance grounding system for ungrounded power systems.

SOLIDLY GROUNDED SYSTEM The most commonly used grounding configuration for industrial, commercial, and institutional power distribution systems is the solidly-grounded system. From IEEE 142 – 2007, IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems, a solidly grounded system is defined as a system that is “connected directly through an adequate ground connection in which no impedance has been intentionally inserted.” Article 250 of the NEC goes to great lengths to define and describe an adequate ground connection, so the reader should use that as a reference for further research for the implementation of grounds in a solidly grounded system.

Fig. 1: IEEE 142 Cover

In lieu of a solidly grounded system, many industrial power distribution systems have implemented an ungrounded system. Also from IEEE 142 – 2007, an ungrounded system is defined as a system “without an intentional connection to ground except through potential indicating or measuring devices or other very high-impedance devices.” An ungrounded system can be implemented where service continuity is a prime concern and tripping the power distribution system off-line due to a ground fault cannot be tolerated. This type of system is allowed by the NEC if there are no line-to-neutral loads (i.e., single phase loads) within the ungrounded power system. As stated, an ungrounded system is one in which there is no intentional connection between the conductors and earth ground. However, as in any system, a capacitive coupling exists between the system conductors and the adjacent grounded surfaces. Consequently, the ungrounded system is, in reality, a capacitivelygrounded system by virtue of the distributed capacitance. Under normal operating conditions, this distributed capacitance causes no problems. In fact, it is beneficial because it establishes, in effect, a neutral point for the system. As a result, typically the phase conductors are stressed at only line-to-neutral voltage above ground. However, if a ground fault exists on one phase, a full line-to-line voltage will appear on the ungrounded phases. Thus, a voltage 1.73 times the normal voltage is present on all phase-to-ground insulation of the ungrounded phases in the system when one line is faulted to ground. This situation can often cause failures in older motors and transformers, due to insulation breakdown. The interaction between the faulted system and its distributed capacitance may also cause transient overvoltages (several times normal) to appear from line-to-ground during normal switching of a circuit having a line-to-ground fault (short). These over voltages may cause insulation failures at points other than the original fault. In addition, a second fault on another phase could occur before the first fault can be cleared. This can result in very high line-to-line fault currents, equipment damage, and disruption of both circuits. To mitigate the potential harm of a ground fault in an ungrounded system, it is typically recommended that the ground faults should be cleared within a short time period (i.e., within 24 hours). Unfortunately, ungrounded systems complicate locating faults. Fault location involves a tedious process of trial and error: first isolat-

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Maintenance Vol. 2 ing the correct feeder, then the branch, and finally, the equipment at fault. The result is unnecessarily lengthy and expensive downtime, which ultimately may not improve service continuity. An ungrounded system, despite the drawbacks, does have one main advantage. After the first ground fault, assuming it remains as a single fault, the circuit may continue in operation, permitting continued production until a convenient shut down for maintenance can be scheduled.

RESISTANCE GROUNDED SYSTEM An alternative to an ungrounded system is a resistance-grounded system. From IEEE 142 – 2007, a resistance-grounded system is “designed to limit ground fault current to a value that can be allowed to flow for an extended period of time, while still meeting the criteria of R0<XC0, so that transient voltages from arcing ground faults are reduced. The ground-fault current is usually limited to less than 10 A, resulting in limited damage even during prolonged faults.” For informational purposes, R0 is the per phase zero-sequence resistance of the system and XC0 is the distributed per phase capacitive reactance to ground of the system. Resistance grounding protects a system against transient overvoltages caused by arcing ground faults and provides adequate fault current for selective ground-fault detection and coordination. Resistance grounding may be either of two classes, low-resistance or high-resistance, distinguished by the magnitude of ground-fault current permitted to flow. Although there are no recognized standards for the levels of ground-fault current that define these two classes, in practice there is a clear difference. Low-resistance grounding employs a neutral resistor of lower ohmic value and is designed to limit ground-fault current to a range between 100A and 1000A, with 400A being typical. Lowresistance grounding has the advantage of facilitating the immediate and selective clearing of a grounded circuit. This requires that the minimum ground-fault current be large enough to positively actuate the applied ground-fault relay. One method of detecting the presence of a ground fault uses an overcurrent relay, 51G. The general practice is to consider that the full system line-to-neutral voltage appears across the grounding resistor. Low-resistance grounding finds application in medium-voltage systems of 15 kV and below, particularly where large rotating machinery is used. By limiting ground-fault currents to hundreds of amperes, instead of thousands of amperes, damage to expensive equipment is reduced. High-resistance grounding employs a neutral resistor of high ohmic value. Typically, the neutral resistor is selected to limit the fault current to 10A. High-resistance grounding usually does not require immediate clearing of a ground fault since the fault current is limited to a very low level. The protective scheme associated with high-resistance grounding is usually detection and alarm rather than immediate trip out. High-resistance grounding is generally employed in low voltage applications where there are no line-toneutral loads and as a retrofit of previously ungrounded systems

where it is desired to reduce transient over-voltages potentially caused by ground faults.

Case Study An industrial customer installed power monitors for the monitoring and allocation of power consumption by department. Due to motor insulation issues within the plant, there have been concerns associated with grounding and ground faults in the plant electrical power distribution system, which is an ungrounded system. This power system was ground fault tolerant. But the ground faults have had detrimental impact to insulation systems in cabling and motors. Accordingly, the monitors were programmed to capture trend and triggered data. A power quality investigation was in process in an effort to determine the frequency and impact of the ground faults on their system. During this investigation, an actual ground fault transient was captured. A plot of the voltage transient is provided below.

Time in Milliseconds

Fig. 2: Ground fault Wave Form As can be seen with the plot, the peak phase-to-ground voltages are on the order of 400 volts (nominal 277 volts rms). It should be noted that this waveform is typical of what would be expected with a 480 volts power system. The actual measured phase rms voltages were 262 volts, 257 volts, and 314 volts. At the onset of the ground fault transient, there was a peak voltage of ~900 volts on C-phase which had the ground fault. The actual peak voltage was probably higher due to the limited resolution of this meter. This level of voltage would be detrimental to insulation systems associated with motors, cabling, etc. Further following the transient, the ground fault was still present. On an ungrounded system, a ground fault condition for one phase can be present and yet the system can continue to operate for an indefinite period. In an attempt to remedy this possible ground-fault related, transient voltage issue, this industrial customer implemented a high resistance grounding (HRG) system on the transformer’s 480 volt secondary. As part of the commissioning activities associated with the HRG system, a ground fault was applied through a testing configuration which included a fused circuit from A-phase to ground. Below is a plot of the associated ground fault transient after the HRG system was installed.

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Fig. 3: Ground fault Wave Form with HRG As can be seen on the plotted wave form, prior to the ground fault, the typical peak phase voltages are as expected. The actual measured phase rms voltages were 278 volt, 272 volt, and 277 volt, which suggest an improved voltage balance for the power system with the HRG system in place. At the onset of the applied ground fault, the power system did not experience the voltage transient which includes excessive voltage spikes. Following the transient, the ground fault is still present.

SUMMARY There are many options to consider when implementing a grounding system for any power distribution system. Most applications include the implementation of a solidly grounded system. However, many industrials have implemented an ungrounded system for improved continuous operations. Unfortunately, with an ungrounded system, when a ground fault is present, the associated voltage transient could be detrimental to the affected insulations systems. With the implementation of a HRG system for ungrounded power systems, these voltage transients can be mitigated. Further, the benefit of continuous operation during a fault condition as well as an additional benefit for improved power system voltage balancing should be realized. Jim Vermeer has a degree in physics from Central College in Pella, Iowa, and works as a project engineer ith Shermco Industries. His specialty is industrial medium- and low-voltage power distribution systems and power quality. Jim is also a Level III NETA Certified Electrical Testing Technician.

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BEST PRACTICES FOR IMPACT BUMP TESTING STATOR END WINDINGS NETA World, Summer 2014 Issue Vicki Warren, and John Letal, Iris power, LP

Common off-line tests of stator windings, IR/PI, dc high potential, PD, power factor, etc. overlook one large aspect of the stator winding: the overhang winding from the slot exit to the end caps or the stator end winding.  Because stator end-winding problems are a result of excessive motion, common off-line electrical tests are not suitable for evaluation, and vibration testing on the bearings and shaft are not usually sensitive to problems in the stator end-winding area. As machines age, the end-winding support materials loosen resulting in components being more prone to vibration problems. In extreme cases the end-winding support structure may be in a resonant condition resulting in excessive vibration amplitudes that can be catastrophic if left uncorrected.  This is unfortunate, since most end-winding problems can be identified early and by using nonintrusive measures can be corrected.  Determining which stator end windings may be at risk of deterioration due to vibration can be assessed with impact (or bump) and modal testing. The goal is to establish the end winding structure natural frequencies and determine if they may be resonant during operation causing amplified vibration levels. This amplification can result in insulation fretting (Figure 1), greasing, high cycle copper conductor fatigue, and series connection failure.

Definitions ●● Vibration frequency – rate at which the component vibrates ●● Natural frequency – frequency at which a structure will vibrate if deflected and then let go ●● Operational forcing frequency – frequency of the electromechanical forces of a generator determined by power frequency and rotational speed; vibration of a generator will tend to be at frequencies related to these. ●● Resonant condition – when the operational forcing frequencies of the generator influence the natural frequency of the end-winding structure ●● Force hammer – device calibrated to exert a known force ●● Accelerometer – device used to measure the frequency response (rate of vibration) during operation or due to a force hammer ●● Frequency response function – transfer function of acceleration to applied force ratio expressed in the frequency domain ●● Modal analysis – measuring motion at various points of a structure when it is excited by some driving force

Part 1 of this article discussed theory and equipment used for impact testing on stator end windings. NETA World – Winter 2013 PART 2 – TEST PROCEDURES The goal of impact testing is to establish a dynamic signature for the structure by doing Fourier analysis. There are two impact test procedures that can be used to determine the natural characteristics of a stator end-winding structure: driving point and modal analysis.

Driving Point

Fig. 1: Insulation Fretting

In the driving point test, the force hammer and the accelerometer are at the same location. This localized test can be used to identify components with maximum deflection. The result is a measured response at the excitation point or frequency response function (FRF). This transfer function is expressed in the frequency domain, Figure 2.

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The phase relationship between the force input and the acceleration output will be between 0 and 180 degrees or 180 and 360 degrees and be ~90 degrees at a natural frequency. To identify a natural frequency, two observations are required. As the driving frequency approaches an undamped natural frequency, 1) the magnitude approaches a maximum and; 2) a phase shift crosses through 90°, Figure 2.

Fig. 2: Natural Frequency Example The critical bands of natural frequencies for a motor or turbine generator are around rotational speed frequency and twice line frequency. Therefore, applied forces in the end-winding structure of a two-pole, 60-Hz generator are at rotor rotational frequency, 60 Hz and at alternating load current electromagnetic forces, 120 Hz. Frequency bands are used to assess the risk of vibration amplification when the natural frequencies influence these operational forcing frequencies. In service the natural frequencies may drift into the bands due to temperature, aging, and other variable factors. Thus, an acceptance band should be defined with these factors in mind. Acceptance criteria are based on the magnitude of the acceleration over force through these critical bands, for example the maximum accelerance limit can be 0.44m/s2/N between 54-72Hz and 108-144Hz.

●● Passive – The response is due to the measured forces. It is best to perform impact testing when background/operational forces are a minimum. An end-winding structure can be modeled with a circular ring. When the structure takes certain shapes at similar frequencies to a force, the resonant condition amplifies the vibration on an end winding. For a two-pole machine, the shape for twice supply frequency deflection is oval, Figure 3. This shape is not the only mode that can be excited by forces within the rotating machine. Other modes such as cantilever modes, Figure 4, or breathing modes, Figure 5, could also become resonant. However, the oval mode shape in Figure 3, for two-pole machines is the most critical for vibration analysis of the stator because it is naturally driven by the rotor forces during operation. It is critical that natural frequencies for the mode shapes into which the end winding can be deformed are far away from the driving frequencies (60 Hz and 120 Hz) to avoid the results of excessive motion, Figure 1.

Fig. 3: Oval Mode Shape

The impact test should not be considered as a stand-alone test or replacement to a modal analysis test.

Modal Analysis Modal analysis consists of measuring motion at various points of a structure when it is excited by a driving force. Practically this test can either be performed using one force input location and multiple acceleration response locations or vice versa. The pattern of motion usually takes certain shapes which are related to the natural frequencies of the structure. This provides a model of structural characteristics through curve fitting techniques to generate a shape table that closely represents the dynamics of a structure, that is, the global tendency of motion.

Assumptions: ●● Linear – The response will be proportional to the input force. This can be checked by performing a driving point test with different sizes of force hammers and obtaining the same FRF ●● Invariant – The parameters are constant during testing. Ambient and winding temperature should be recorded through impact testing and not fluctuate significantly.

Fig. 4: Cantilever Mode Shape

Maintenance Vol. 2

23 tion systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group. John Letal is a rotating machines engineer at Iris Power responsible for supporting rotating machine mechanical monitoring initiatives including stator endwinding vibration. Prior to Iris, he spent most of his career as a field service engineer troubleshooting large rotating equipment using such tools as vibration analysis, force response measurements, and modal analysis. He was also involved in the implementation and execution of vibration analysis programs. John holds a Bachelor of Science degree in Manufacturing Engineering from the University of Calgary and is registered as a professional engineer.

Fig. 5: Breathing Mode Shape Modal data should be collected at locations on the stator overhang where the end windings are most responsive, that is, near the end caps and between each ring of blocking. Also, it is useful to collect data on the core. For each ring enough points must be measured to resolve the mode shape of interest. In general, for twopole machines, 12 points are sufficient to define the oval mode shape. Quite often though, it is of interest to identify the shape of the modes near the electromagnetic force during operation, so the mode shape above 120 Hz should have sufficient resolution in order to avoid misinterpretation.

SUMMARY Impact testing is an off-line test that can be used to assess whether stator end windings are likely to vibrate in resonance with operational forces. A driving point test procedure is used to identify local natural frequencies of a particular component of a structure whereas modal analysis is used to identify the global tendency of motion for a complex structure. Both can be used in conjunction to evaluate the condition of a stator end-winding support structure and determine the likelihood for excessive motion during operation due to resonance. Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in mediumto high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insula-

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Maintenance Vol. 2

64S PROTECTION GUIDE – THEORY, APPLICATION, AND COMMISSIONING OF GENERATOR 100 PERCENT STATOR GROUND FAULT PROTECTION USING LOW FREQUENCY INJECTION NETA World, Summer 2014 issue Steve Turner, Beckwith Electric Company, Inc. This paper covers practical considerations for proper application and commissioning of this special protection. The total capacitance to ground of the generator stator windings, bus work and delta-connected unit transformer windings is a very important factor as will be shown. This protection can:

●● Vibration sparking, inadvertent damage during maintenance ●● Wet insulation due to strand header water leak, bar vibration in the slot

Examples of Category #2 failures:

●● Detect a stator ground when the winding insulation first starts to break down and trip the unit before catastrophic damage occurs

●● Fracture of stator bar copper conductors due to high cycle fatigue associated with vibration

●● Be set to trip in the order of cycles since the 20 Hz signal is decoupled from the 50 or 60 Hz power system

●● Fracture of bar copper due to gross overheating of the copper

●● Detect grounds close to the machine neutral or even right at the neutral thus providing 100 percent coverage of the stator windings

●● Failure of a brazed or welded joint

●● Detect grounds when the machine is starting up or offline ●● Reliably operate with the generator in various operating modes such as, synchronous condenser and at all levels of real and reactive power output. Special steps should be taken in the design of this protection as there are cases when it is difficult to distinguish between normal operating conditions and an actual ground fault. The protection must reject fundamental frequency (50 or 60 Hz) voltage and current signals that are present during ground faults on the stator windings. A real-life example for a pump storage facility is included.

●● Core iron melting, failure of a bolted connection ●● Failure of a series or phase connection Category #1 failures are typically benign, unless a second ground occurs, in which case there is massive arcing. Category #2 failures are always highly destructive to the generator. Current will temporarily continue to flow uninterrupted within the stator bar ground wall insulation (i.e., welding arc) when a conductor breaks and the heat generated is extremely high. This current will flow inside the insulation until it is mechanically destroyed. Experience has shown that the copper is vaporized for perhaps 8-12 inches before the internal arcing breaks through the insulation wall and arcs to ground as shown in Photos 1-3.

STATOR GROUND FAULTS ROOT CAUSES In-service stator winding failure to ground is a common generator failure and there are many possible causes such as mechanical damage to the ground insulation (Category #1) and fracturing of the current carrying conductor which results in the ground wall insulation burning away (Category #2).

Examples of Category #1 failures: ●● Ground insulation wear-through from a foreign object or loose component ●● Fracture of the ground wall due to a sudden short circuit ●● Deficient ground wall insulation system ●● Partial discharge combined with vibration

Fig. 1: Typical winding damage resulting from broken stator winding conductor

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Maintenance Vol. 2 APPLICATION

Fig. 2: Typical core and winding damage resulting from a burned open bar in a slot

Fig. 3: Burned away copper fractured connection ring Conventional neutral overvoltage protection (59N) cannot detect grounds in the last 5-10 percent of the stator winding. If a failure occurs in a lower voltage portion of the winding near the neutral a generator trip will not typically occur until some other relay protection detects there is a problem; e.g., arcing becomes so wide-spread that other portions of the winding become involved. There is recent experience with four such failures in large generators that demonstrate the lack of proper protection can be disastrous. Each of the four failures caused massive damage to the generator, and collectively had a total cost, including repair and loss of generation, close to $500,000,000 [1]. This demonstrates that failure of stator windings in the last 5 percent of the winding is not uncommon. One hundred percent stator ground fault protection is provided by injecting a 20 Hz voltage signal (64S) into the secondary of the generator neutral grounding transformer through a band-pass filter. The band-pass filter passes only the 20 Hz signal and rejects out-of-band signals. The main advantage of this protection is it provides 100% protection of the stator windings for ground faults―including when the machine is off-line (provided that the 20 Hz signal is present).

Fig. 4 illustrates a typical application. A 20 Hz voltage signal is impressed across the grounding resistor (RN) by the 20 Hz signal generator. The band-pass filter only passes the 20 Hz signal and rejects out-of-band signals. The voltage across the grounding resistor is also connected across the voltage input (VN) of the 64S function. The current input (IN) of the 64S function measures the 20 Hz current flowing on the secondary side of the grounding transformer and is stepped down through a CT. It is important to note that the relay does not measure the 20 Hz current flowing through the grounding resistor; it measures the 20 Hz current flowing into the power system. The 20 Hz current magnitude increases during ground faults on the stator winding and an overcurrent element that operates on this low frequency current provides the protection.

Fig. 4: 20 Hz injection grounding network

20 Hz Voltage and Current 64S Relay Measurements The following method shows how to calculate the 20 Hz voltage and current measured by the 64S function.

Grounding Transformer Turns Ratio (N) Assume that the turns ratio of the grounding transformer is equal to:

Capacitive Reactance The total capacitance to ground of the generator stator windings, bus work and delta connected transformer windings of the unit transformer is expressed as C0. Generator step up transformers have delta connected windings facing the generator so capacitance on the high side is ignored. The corresponding capacitive reactance is calculated as follows:

26 Assume the capacitance to ground is 1 microfarad:

Reflect the capacitive reactance to the secondary of the grounding transformer:

Maintenance Vol. 2 Grounding Network These are all of the elements needed to mathematically derive the grounding network and determine the 20 Hz signals measured by the 64S function. Fig. 5A shows the insulation resistance and the stator windings referred to the primary of the grounding transformer. Fig. 5B shows the insulation resistance and the stator windings reflected to the secondary of the grounding transformer.

Grounding Resistor (RN) The ohmic value of the grounding resistor can be sized as follows so as to avoid high transient over-voltage due to ferroresonance2:

Fig. 5A: 20 Hz grounding network – referred to grounding transformer primary

A value of 2.5 ohms secondary is used for this example.

20 Hz Signal Generator and Band-pass Filter Characteristics The 20 Hz signal generator output is 25 volts RMS and the band pass filter has a resistance equal to 8 ohms.

Stator Insulation Resistance (RS) RS is the total insulation resistance from the stator windings to ground. A typical value for non-fault conditions is 50,000 ohms primary. Reflect the insulation resistance to the secondary of the grounding transformer.

Current Transformer The current input (IN) of the 64S function measures the 20 Hz current flowing on the grounded side of the grounding transformer and is stepped down through a CT.

Fig. 5B: 20 Hz grounding network – reflected to grounding transformer secondary XC = total capacitance-to-ground

VN = voltage drop across RN

Rstator = stator insulation resistance to ground

IN = current from system

RN = neutral resistor RFilter = band pass filter resistance

IBANK = current flow in RN IT = IBANK + IN

20 Hz Current (IN) Measured by 64S Function The current input (IN) of the 64S function measures the 20 Hz current flowing in the secondary of the grounding transformer and is stepped down through a CT. As noted previously the relay does not measure the 20 Hz current flowing through the grounding resistor. Total 20 Hz Current Supplied by Signal Generator―The 20 Hz signal generator looks into the band-pass filter resistance (RBPF) which is in series with the parallel combination of the following: ●● ZC0 ●● RS ●● RN

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Maintenance Vol. 2 Therefore, the total loop impedance of the 20 Hz grounding network can be expressed as follows:

The total 20 Hz current supplied by the signal generator is determined as follows:

Table 1 summarizes the 20 Hz current measured by the relay for non-faulted and faulted conditions. Often the 64S protection can detect the ground for insulation resistance is much higher than 5,000 ohms primary.

RS (primary)

|IN| (secondary)

50,000 Ω

9.779 mA

5,000 Ω

13.486 mA

1,000 Ω

26.640 m A

Table 1: 20 Hz current measurements The 64S function can easily distinguish between non-fault and stator ground faults for this example. Set the pickup of the 64S 20 Hz tuned overcurrent element above the current measured during normal operating conditions but below the current measured for a stator ground fault equal to 5,000 ohms primary.

PRACTICAL CONSIDERATIONS 20 Hz Current Measured by 64S Function (IN) during Non-Faulted Conditions The 20 Hz current measured by the 64S function is the ratio of the total current that flows into the primary side of the grounding network (ZC /RS): 0

Here are three important aspects to consider when applying 100% stator ground fault protection by 20 Hz injection: ●● Slight change in fault current measured by relay ●● Rejection of fundamental frequency (50 or 60 Hz) voltage and current signals ●● Under-frequency inhibition

Slight Change in Fault Current A very large capacitance to ground (C0) coupled with a small value for the grounding resistor (RN) can result in very little margin between the fault and non-fault current measured by the 64S function. Generator windings and iso-phase bus work are both sources of high capacitance to ground (ex., a long run of bus from the generator to the step-up transformer).

20 Hz Current Measured by 64S Function (IN) during Ground Fault on Stator Windings A typical value to represent the insulation resistance of the stator windings when it is breaking down during a ground fault is 5,000 ohms primary. If the calculations for Equations 7 through 9 are repeated for a fault resistance equal to 5,000 ohms primary (4.5 ohms secondary), then the 20 Hz current measured by the relay is as follows: |IN| = 13.486 mA (5,000 ohm primary ground fault) If the calculations for (7) through (9) are repeated for a fault resistance equal to 1,000 ohms primary (0.9 ohms secondary), then the 20 Hz current measured by the relay is as follows: |IN| = 26.640 mA (1,000 ohm primary ground fault)

Fig. 6: Iso-phase bus work

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Maintenance Vol. 2

Fig. 7 illustrates why there is not a significant change in the magnitude of the total neutral current when there is high capacitance. If the capacitive reactance is low enough then only a small portion of the total neutral current flows through the insulation resistance. To overcome this challenge, calculating the real component of the total neutral current can reliably detect a stator ground fault for such a system.

Fig. 8: Current flow in secondary network

20 Hz Current Flowing through the Grounding Transformer

20 Hz Voltage Drop Across the Grounding Resistor

Fig. 7: Primary side current distribution Consider the following grounding network parameters:

Determine the 20 Hz current measured by the 64S function for non-faulted and stator ground fault conditions using the equations presented in the previous application section.

RS (primary)

|IN| (secondary)

50,000 Ω

12.465 mA

5,000 Ω

12.465 mA

1,000 Ω

12.863 mA

Table 2: 20 Hz current measurements for high capacitance The 64S 20 Hz tuned overcurrent element pickup cannot be set such that it reliably discriminates between non-faulted and stator ground fault conditions. The solution is for the relay to calculate the real component of the 20 Hz current with respect to the neutral voltage. To do so, first determine the 20 Hz voltage measured by the relay voltage input (VN). The 20 Hz voltage is equal to the drop across the grounding resistor due to the portion of the total current flowing through this branch of the grounding network (i.e., IBANK).

Real Component of 20 Hz Current Measured by 64S Function Calculate the real component of the relay current based upon the angle between the relay neutral voltage (VN) and current (IN).

RS (primary)

|IN| (secondary)

Re (IN)

50,000 Ω

12.465 m A

0.198 mA

5,000 Ω

12.096 m A

0.900 m A

1,000 Ω

12.863 m A

8.001 m A

Table 3: 20 Hz current measurements for high capacitance including real component A 20 Hz tuned overcurrent element that operates on the real component of 20 Hz current measured by the 64S function can reliably distinguish between non-faulted and stator ground fault conditions when there is high-capacitive coupling to ground on the stator winding. A good rule of thumb is if C0 is greater than 1.5 microfarads and the grounding resistor is less than 0.3 ohms secondary consider using the real component of 20 Hz current for sensitive protection. The user can follow the commissioning instructions that appear at the end of this paper to determine the total capacitance to ground (C0). If the values for RN and C0 do not clearly fall under the category defined by this rule of thumb then use the equations provided earlier in this paper to determine if use of the real component of neutral current is necessary.

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Maintenance Vol. 2 NOTE

Table 4 provides a description of each channel and the magnitude.

If the 64S function uses the real component it should also use the total neutral current as a backup for the case of a solid short circuit located right at the machine neutral (i.e., the real component equals zero for this case since there is no reference voltage).

Fault Location

VS

IN

IS/CTR

100% (phase side)

110 V

(110 V)/0.32 Ω = 343.75 amps

4.297 amps

90%

99 V

(99 V)/0.32 Ω = 309.375 amps

3.867 amps

80%

88 V

(88 V)/0.32 Ω = 275 amps

3.438 amps

70%

77 V

(77 V)/0.32 Ω = 240.625 amps

3.008 amps

60%

66 V

(66 V)/0.32 Ω = 206.25 amps

2.578 amps

50%

55 V

(55 V)/0.32 Ω = 171.875 amps

2.148 amps

40%

44 V

(44 V)/0.32 Ω = 137.5 amps

1.719 amps

30%

33 V

(33 V)/0.32 Ω = 103.125 amps

1.289 amps

20%

22 V

(22 V)/0.32 Ω = 68.75 amps

0.859 amps

10%

11 V

(22 V)/0.32 Ω = 68.75 amps

0.430 amps

0% (neutral side)

0

0

0

Rejection of Fundamental Frequency (50 or 60 Hz) Voltage and Current Signals Fundamental component voltage and current present at the relay measuring inputs during stator ground faults can cause the 64S function to not operate properly unless they are well rejected. Note that these signals are not eliminated by the band-pass filter since they are due to the fundamental voltage drop across the secondary of the grounding transformer. Fig. 9 illustrates the fundamental voltage drop (50 or 60 Hz) across the grounding resistor as a function of the ground fault location along the stator windings. Table 4 shows the voltage drop as the fault location moves from the neutral side of the stator windings to the phase side. The grounding transformer is rated 110 volts secondary, the grounding resistor is sized 0.32 ohms secondary and the CT ratio is 400:5 (80:1). The corresponding fundamental component circulating current is shown as well. If the fundamental current is not well rejected, then high magnitude circulating current can saturate the neutral current input and as a result the protection will measure a value of 20 Hz current less than the actual. Saturation causes the following problems:

Table 4: Fundamental voltage drop across grounding resistor and circulating current (RN =0.32Ω)

●● Delayed operation or, even worse, no operation at all ●● Less than 100% coverage of the stator windings as the ground fault location moves towards the phase side

NOTE Saturation is most likely to occur when the grounding resistor is sized less than one ohm secondary.

Underfrequency Inhibition Sometimes it is necessary to block the 64S function during conditions such as startup when the system voltage measured by the relay is 40 Hz or lower. The third harmonic of 7 Hz is very close to 20 Hz during startup when the generator is transitioning through the lower frequencies and can cause unwanted operation. This is typically not the case though.

Commissioning Instructions Figure 10 on the next page illustrates how to configure the 64S protection for commissioning.

NOTE Use the 20 Hz signals captured during normal operating conditions to determine appropriate overcurrent pickup settings. Determine the total capacitance to ground and calculate the overcurrent pickup setting based upon these field measurements as a check.

Fig. 9: Fundamental voltage across RN as function of ground fault location

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Maintenance Vol. 2 ●● Switch F1 is open ●● Switch F2 is open ●● 20 Hz signal generator is online ●● Preferably the generator is online Measure the following 20 Hz signals: Fig. 10: 20 Hz grounding network for commissioning

Stator Ground Fault at Machine Neutral Configure the power system as follows: ●● High side breaker is open

●● VN (neutral voltage) ●● IN (neutral current) ●● Re (IN) (real component of neutral current) These signals correspond to normal operating conditions.

●● The generator is offline ●● Generator terminals are connected to delta windings of the generator step up transformer ●● Switch F1 is closed ●● Switch F2 is open ●● 20 Hz signal generator is online Place a single line-to-ground fault at location F1 and measure the 20 Hz IN. This measurement corresponds to a short circuit applied at the neutral of the machine. The total 20 Hz neutral current (IN) should be very close in magnitude to 39 mA.

Fig. 12: Numerical generator relay 20 Hz metering VN and IN are the 20 Hz signals applied to the relay inputs. Record VN, IN and Re (IN). Modern numerical generator relays can meter these values. The signals recorded in Figure 12 were captured while commissioning a large pumped storage hydroelectric unit while operating in the motoring (pumping) mode.

CONCLUSIONS

Fig. 11: Short circuit at machine neutral

NOTE This is the first step and is a quick check to see if all the wiring is correct.

Normal Operating Conditions Configure the power system as follows: ●● High side breaker is open ●● Generator terminals are connected to delta windings of the generator step up transformer

This special protection provides 100% coverage of the stator windings for ground faults under all operating conditions incluing variable real and reactive power output, operating modes and when off-line. Grounds on the last 5 percent of the stator windings do occur and can be disastrous if not quickly detected. Traditional protections (59N, 27TH, 27D) may not realible operated for faults in the last 5% of the stator winding. The total capacitance-to-ground of the generator stator windings, bus work and delta-connected unit transformer windings is a very important factor and must be known to ensure the protection settings are correctly determined. This value can be determined during commissioning. There are cases when it is hard to distinguish between normal operating conditions and an actual stator ground fault unless special steps are taken in the design of this protection. A good rule of thumb to decide if the real component of 20 Hz current is necessary is when C0 is greater than 1.5 microfarads and the grounding resistor is less than 0.3 ohms secondary. Use the real component of the 20 Hz current measured by the relay for these cases.

Maintenance Vol. 2 The protection must reject fundamental frequency (50 or 60 Hz) voltage and current signals that are present at the relay measuring inputs during ground stator ground faults. Use an under-frequency element that operates on the system voltage to block the 64S function if nuisance tripping occurs during either startup or shutdown of the generator.

REFERENCES 1

“ Stator Winding Ground Protection Failures” by Clyde V. Maughan, ASMEPOWER2013-98151

2

“ The Art and Science of Protective Relaying” by C. Russell Mason, Wiley (1956), pp. 209 – 210.

Steve Turner is a Senior Applications Engineer at Beckwith Electric Company, Inc. His previous experience include working as an application engineer with GEC Alstom for five years, an application engineer in the international market for SEL, focusing on transmission line protection applications. Steve worked for Progress Energy, where he developed a patent for doubleended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve Turner is also a senior member of the IEEE.

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Maintenance Vol. 2

GET THE MOST BANG FOR YOUR BUCK TOP FIVE TESTS FOR BEST RETURN ON INVESTMENT NETA World, Summer 2014 Issue Don Genutis, Halco Testing Services

This article expresses the author’s experience-based opinion of the best technologies available that provide the most useful information related to equipment condition for the best value. These best bang for the buck technologies are must haves to be included in every electrical maintenance testing program and will go a long way toward preventing an electrical bang. Obtaining an outage is costly, so it is not surprising that no-outage testing techniques lead the way. Listed below are the five best tests and why they provide the best return on investment.

VISUAL INSPECTION These often overlooked inspections are very inexpensive to perform, but they can provide a great deal of information related to equipment condition.  The inspections are very safe and relatively easy to conduct, but they are typically limited to what can be viewed externally. Permanently mounted instrumentation, even in the form of simple gauges, can often provide information related to internal equipment conditions.

SWITCHGEAR PARTIAL DISCHARGE SURVEYS Nonintrusive partial discharge surveys of medium-voltage switchgear can efficiently detect a multitude of problems long before complete failure occurs, allowing precious time to schedule repairs. Partial discharge surveys are relatively inexpensive to perform and should be conducted annually. The only drawback for this technology is that it is not effective on low-voltage equipment.

TRANSFORMER DIELECTRIC FLUID SAMPLING AND TESTING Over many years this technique has evolved from testing the condition of the fluid by determining its electrical, mechanical, and chemical characteristics to determining the condition of the transformer itself by dissolved gas analysis. This technology can arguably be ranked as number one. Where else can a two hundred dollar test be relied upon to assess the condition of an expensive piece of equipment?  However, the test is not completely nonintrusive and does introduce some personnel risk when performing sampling when the transformer is energized.

CIRCUIT BREAKER OPERATION ANALYSIS A great deal of information related to the mechanical operation, and thus the electrical performance, of any circuit breaker can be derived by techniques based upon applying accelerometers to the breaker during operation to record timing and operation signature. The resulting data can then be used to calculate first trip time and to spot mechanical anomalies that affect breaker operation. The test is inexpensive, but it provides a good indication of breaker condition. The drawback is that the test requires tripping the breaker which of course takes it off-line, as does almost all breaker tests.

INFRARED INSPECTIONS This is a very good test that covers a lot of ground and is a favorite of facility insurers. The survey itself is less efficient and provides greater personnel risk due to necessary panel cover removal. This technique could be safer if infrared inspection windows are installed.

HONORABLE MENTION The following two technologies didn’t make the top five but are still worthy of mentioning.

CABLE PARTIAL DISCHARGE There is a massive amount of aging medium voltage cable in service throughout our country and a much of it has never been tested. On-line partial discharge testing while the system remains energized is a relatively efficient and inexpensive test that can detect termination and splice problems which contribute to the majority of cable system failures. The drawback to this test is that it does not apply to low-voltage cables and requires stringent safety precautions.

RFI SURVEYS Like visual inspections and PD surveys, RFI surveys of outdoor substations can cover a lot of ground in a short period of time. With a main substation, which may be the sole distribution bottleneck to an entire facility, the value of detecting an anomaly safely and nonintrusively while the equipment remains in service is a big reward. However, the technology is limited to outdoor open bus substations and switchyards.

Maintenance Vol. 2 While reviewing the above list of technologies, it can quickly be seen that although all items listed provide great potential ROI, it is also apparent that each technology has unique strengths and weaknesses. These considerations must be carefully taken into account when developing an effective maintenance testing program. In addition to these technologies, traditional and more thorough outage-based testing and maintenance procedures, which address a much greater level of detail and ensure proper mechanical operation, must be included in any maintenance testing program for it to be effective. Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

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Maintenance Vol. 2

AVOIDING METAL-CLAD SWITCHGEAR FAILURE THROUGH USE OF PARTIAL DISCHARGE DETECTION NETA World, Fall 2014 Issue Tony McGrail, Jay Garnett, Matthew Lawrence, Doble Engineering Company

INTRODUCTION Metal-clad switchgear and associated ducts can be very reliable, with some installations operating for over 50 years. Using grounded metal enclosures to house conductors and switchgear means they can be protected from the elements and common failure causes. However, the aging processes involved with metal-clad equipment include moisture ingress, animal intrusion, insulation deterioration, and enclosure rusting. A number of utilities have experienced failures of metal-clad switchgear and have been looking for efficient ways to detect incipient failures. Partial discharge (PD) is a leading indicator of various failure modes and can be a valuable tool in detecting such failures. Both electric and acoustic techniques have been used with varying degrees of success. Acoustic methods use acoustic emission signals to detect sources of sound within the switchgear. Transient earth voltage (TEV) approaches look at signals developed in grounded metal-clad surfaces. High frequency CTs (HFCTs) can be used to determine local sources of partial discharge for investigation. We present here a study of PD techniques applied to a suspect metal-clad installation where previous failures had occurred. Using both acoustic and electrical PD techniques, we show that sources of discharge can be detected with confidence, locating a source to a particular metal-clad compartment. Doble’s years of experience in detecting PD problems in the field has brought value to many organizations and makes sense of what can be a confusing array of techniques. PD detection using ultrasound provides the most reliable indication of a problem with metal-clad equipment.

METAL-CLAD EQUIPMENT In this case study, the metal-clad equipment was built in 1959 and has been impacted by a buildup of salt residue from nearby roads, moisture ingress, and animal intrusion. At this station there are two 115 kV transformers feeding a double lineup breaker and a half scheme arrangement. Regular inspection of the metal clad has revealed ongoing issues that have required maintenance. Failures due to insulation deterioration and subsequent identification of partial discharge as a symptom of the failure led to PD detection being used to identify further potential failure locations. The metal-clad equipment is shown in Figure 1.

Fig. 1: Metal-clad Duct

PARTIAL DISCHARGE AS AN INDICATION OF INCIPIENT FAILURE Partial discharge is a phenomenon where electric current flows through insulation and breaks down the insulation emitting energy in the form of heat, sound, light, and other electromagnetic radiation. It is described as partial as the voltage across the breakdown does not cover the whole of the insulation system and appears as a small arc or spark. A classic approach to PD detection in large power transformers is through dissolved gas analysis (DGA). The by-products of the insulation breakdown dissolve in the oil and can be detected through chemical analysis. Further PD phenomena include ultrasound waves and transient earth voltages.

ULTRASONIC AND TRANSIENT EARTH VOLTAGES (TEV) When a partial discharge source develops sufficiently it is possible to see the discharge – little lightning strikes within insulation or large arcs with power follow through. It may also be possible to hear the characteristic buzzing and humming of a discharge. However, in the early stages, the sound emitted may be outside of the range of human hearing – at the ultrasound frequency above our hearing capabilities. Ultrasonic detection used in PD surveys normally operates around the 40 kHz range and is used to detect discharges from several causes, These can be from tracking on contaminated surfaces, arcing between conductor strands, corona discharges from sharp

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Maintenance Vol. 2 pointed objects such as slag protrusions, or even electrical floating objects. By electrical floating objects we mean metallic objects in an energized field that are not attached to the energized conductors and not tied to ground. Thus these objects reside in a magnetic field created by the nearby energized conductor and create their own charged field. This field is detectable with ultrasonic detectors and sometimes with TEV detection. Ultrasonic hand held detectors, such as shown in Figure 2, are simple to operate and provide results quickly in the field. These devices can give both readings of ultrasound intensity in dB and a phase resolved indication of the source. The dB readings provide excellent indication of the proximity of a PD source while the phase resolved plot provides information which can be used to discriminate between discharge types.

By using both TEV and ultrasound approaches it is possible to detect and identify PD sources in metal-clad switchgear. In our experience, ultrasound is the most effective means to detect PD, though we would note that there are many cases where a combined approach means that a PD source is more readily identified and confirmed.

FIELD CASE STUDY An initial ultrasonic and TEV survey on all breakers and compartments of the metal-clad switchgear yielded no high readings or indications of PD. There was evidence of moisture and rust on the duct banks from the transformers to the metal clad, which were then investigated in more detail.

SWITCHGEAR INVESTIGATION Metal-clad switchgear compartments in the north and center of the station were tested both during a normal day and a day when there was high humidity. The readings from the normal day showed no great variation, but during times of high humidity the readings had a story to tell. The results of the TEV and ultrasound are shown in Table 1. North Side Upper Compartments

Fig. 2: Doble Ultrasonic PD Measurement Device TEV are created on metal surfaces when PD is present inside voids in insulation material. These voids can be in potting material, bus insulation, bus support insulators, and other materials. When a partial discharge happens, a magnetic field is developed. This magnetic field releases a small radiation know as radio frequency interference (RFI). When RFI travels through a medium, such as air, and hits a metal surface, it generates a small transient voltage, which may be detected by a TEV sensor. The stronger the discharge signal and higher the pulse rate of the PD, the higher the reading on a TEV monitoring unit. Most TEV-based PD monitoring devices operate between 100 kHz and 500 kHz, in line with IEC standards. Partial discharge can be detected in ranges below and above these frequencies. The TEV detection unit used in this study operated between 20 MHz and 80 MHz. Ultrasonic detection and transient earth voltages were the two types of detection used in these surveys. PD detection devices are normally set to detect PD by monitoring in the 100-500 kHz range, in line with IEC standards, and some can monitor up to the 1 MHz range. In both approaches, energy levels in the source signal (acoustic or electrical) are measured and a reading given in dB. The higher the reading, the more energy there is associated with the location. It is often the case that the absolute level of PD indication is less important than the relative strength – this is useful with metal-clad locations as each compartment can be tested individually and dB levels assigned.

Compartment

U12

U14

U16

U18

U20

U22

U24

Ultrasound, dB

-5

-5

-5

-5

-5

-5

-5

TEV, dB

5

5

5

6

5

16

7

North Side Lower Compartments

Compartment

L5

L7

L9

L11

L13

L15

TR-1

Ultrasound, dB

-5

-5

-5

-5

-3

10

-5

TEV, dB

12

12

12

12

17

38

10

Center Panels Upper Compartment

Q32

Q34

Q36

Q38

Q40

Q42

-

Ultrasound, dB

-5

-5

-5

-5

-5

-5

-

TEV, dB

10

10

10

10

10

10

-

Table 1: Ultrasound and TEV Investigation of Metal-clad Switchgear – High Humidity Conditions From the results, it is clear that there are higher readings for both ultrasound and TEV measurements associated with U22/L15. The upper compartment readings are likely to be a result of activity in the compartment below. What can also be seen are the very consistent readings provided by ultrasound, while the TEV does have higher

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levels and more variability. This may reflect the ability of a TEV approach to pick up benign energy sources which provide earth/ ground current signals, TEV-based false positives. It is thought that faint sounds of arcing could be heard by the inspectors, indicating a substantial discharge level. The immediate concern was the spike in the L15 position since it had no high readings in the original survey. An outage was scheduled and the breaker was removed and inspected. The insulated material was degrading and there was also dust and residue on the surfaces, with pitting and oxidization, as shown in Figure 3. Fig. 4: Light Colored Insulation Indicating Partial Discharge Activity These PD sources related to known previous failures in the metalclad switchgear – with pitting in the bus which had been installed after previous bus sections had been replaced. As a result of the investigation, duct bank sections were assigned for replacement.

CONCLUSION Fig. 3: Pitting and PD Damage to Switchgear Insulation A maintenance outage on that section of bus was scheduled. During the maintenance the breaker and bus sections were cleaned and wiped down to remove any oxidation, dust, and oil residues. The breaker and bus were recoated and wrapped with new insulating material on the insulated areas that showed the PD in order to increase the dielectric strength and in-service life of the insulation. A follow up survey was performed during a very wet and humid day with high temperatures and heavy loading conditions. No high readings were detected indicating that the corrective measures helped. Given previous failures on the bus ducts and switchgear related to insulation degradation and tracking, it is likely that this survey and consequent maintenance helped reduce the possibility of an in-service failure.

Duct Bank Investigation The duct banks are elevated in the yard and contain bus conductors, bus supports, and heaters to help keep moisture out. An analysis of each bus compartment in multiple compartments, including the locations of the heater elements of the metal-clad system, yielded a number of areas where the readings were higher relative to nearby locations. Normally an investigation may require removal of hundreds of bolts and multiple plates. In this station, the ultrasound approach in particular with the TEV in support, allowed the inspection to be limited to those areas having high readings. A few bolts were removed to allow boroscopic camera evaluation of the components. Higher readings of PD related to locations where the bus passed through bus support insulators (see Figure 4). The insulation was a far lighter color – an indication of PD activity.

Use of ultrasonic PD detection and TEV testing can be very useful in finding problems before they become failures, as in the case discussed here where a metal-clad failure was most likely prevented. PD detection can save equipment and help save employees from the dangers associated with letting a problem get to the point of catastrophic failure. One must remember that several conditions can contribute to getting these types of ultrasonic and TEV readings as with any corona or PD detection test equipment. Those conditions such as dust, fine oily residues, and surface contamination can have much higher discharge characteristics when moisture is also added to the mix; therefore, it can be advisable to retest after rain conditions or during high humidity conditions. Also PD can occur in times of heavy loading and not at other times. Ultrasound is a very reliable indicator of PD activity in metal-clad switchgear. We have found that TEV readings, in particular, can lead to false positives, so it is a sensible precaution to use an ultrasound method in parallel to corroborate findings. Tony McGrail is the Doble Engineering Solutions Director: Asset management and Monitoring Technology. His role includes providing condition, criticality, and risk analysis for utility companies. Previously Tony has spent over 10 years with National Grid in the UK and the US. He has been both a substation equipment specialist and has also taken on the role of substation asset manager and distribution asset manager. Tony is a Fellow of IET, a member of IEEE, ASTM, CIGRE and the IAM, and is currently on the executive of the Doble Client Committee on Asset and Maintenance Management. His initial degree was in physics. He has an MS and a PhD in EE and an MBA. Tony is an Adjunct Professor at Worcester Polytechnic Institute, Massachusetts, leading courses in power systems analysis.

Maintenance Vol. 2 Jay M. Garnett has worked for Doble Engineering since 2011 as a principal engineer in the Client Services Department based in the Sacramento, California offices. Jay has worked in the utility industry for over thirty-four years and has experience in substations, hydroelectric, geothermal, fossil fuel, nuclear generation, construction, maintenance, and testing. He worked as a substation maintenance engineer for National Grid USA in the Substation O&M Services NE/NY Department from 2007 to 2011. Before that he was a supervisor overseeing the relay department for over five years. He also was a relay technician for National Grid (formerly Niagara Mohawk) in the Albany, NY area starting in 1992. Jay worked for Pacific Gas and Electric Company from 1983 until 1992, in the General Construction Department as an electrician and then as an electrical technician before moving to Albany, NY in December of 1992. Jay is a graduate from Napa Community College where he studied geology and received an Associate of Arts degree. Jay has also completed six years of apprenticeships, holding certificates as a journeymen Electrician and a journeymen Electrical Technician in the State of California. He has vice-chaired and chaired the Bushings Insulators and Instrument Transformer (BIIT) Committee at Doble while working at National Grid and is currently the assistant secretary of the Asset Management and Maintenance (AMM) committee at Doble. Jay has been a member of IEEE since 2007. Matthew B. Lawrence is the Solutions Director, Test & Assessment Technology, at Doble Engineering, focusing on substation diagnostic testing solutions. Before joining Doble in 2011, Matthew held positions in substation maintenance & operations and equipment maintenance engineering departments at National Grid and its New England based legacy companies since 1984. His most recent role was Manager of Substation O&M Services. He is a member of IEEE and affiliate of the IEEE transformer committee. Mr. Lawrence is a member and past chair of the Doble Engineering SFRA Users Group committee. Mr. Lawrence has co-authored papers presented at conferences on field transformer testing & condition assessment. Mr. Lawrence holds an Associates of Science in Electronics Engineering from New England Institute of Technology and attended Worcester Polytechnic Institute School of Industrial Management.

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QA TESTS FOR MV GVPI STATOR WINDINGS NETA World, Fall 2014 Issue Vicki Warren, Iris Power LP According to the NETA Acceptance and Maintenance Testing Specifications sections 7.15.1 and 7.15.2 for electrical testing of rotating machines, there are three required tests: insulation-resistance, dc withstand, and phase-to-phase stator resistance. The required tests of insulation resistance, polarization index (IEEE 43) and the controlled dc high voltage test (IEEE 95) have been effective in evaluating certain aspects of medium voltage (4--13 kV) global vacuum pressure impregnation (GVPI) stator windings; however, they have not proven adequate for determining whether or not the insulation system is well consolidated. As a result, there is some concern that the required tests are not sufficient for quality assessment (QA) either of a new or an existing medium-voltage (MV) winding.  The NETA specifications include three optional tests: power-factor or dissipation-factor, tip-up tests, and partial discharge tests. See NETA World--Spring 2014 for more information about the need for these additional dielectrics characteristic tests.

THE REQUIRED TESTS The insulation resistance (IR) is an indication of the total current. This value trended over time may give indications as to the presence of cracks or contamination. Generally, the trend of the IR value is erratic because of the effects of winding temperature and humidity. Unless the winding is always measured under exactly the same humidity and temperature conditions, it is complex to track the resistance over time. (IEEE 43-2000)5 See NETA World-Winter 2011 for more information. The polarization index (PI) was developed to make interpretation less sensitive to temperature. However, the mica in the stator winding insulation system has virtually an infinite dc resistance value, so the IR/PI tests do not evaluate if the insulation system is well-consolidated, impacted by mechanical forces, or thermally damaged. This requires an AC dielectric test, such as dissipation/power factor or partial discharge test as described below. See NETA World--Spring 2012 for more information. A high dc voltage withstand test may provide some assurance that the ground wall may safely be stressed to normal operating voltage, that is, a minimal level of electric strength. The dc high potential acceptance test is not a diagnostic test since the outcome is simply pass or fail. Controlled overvoltage tests, stepped or ramped tests, may afford the possibility of detecting impending insulation problems by recognizing abnormalities in the measured current response, thereby allowing the test to be discontinued prior

to insulation failure. However, as stated in IEEE 95-20026 there has been limited experience in detecting delamination or coil consolidation in mica-based insulation systems by this means. Because unexpected insulation failure can occur during the test, it is important to be aware of the possible need to make repairs before the machine can be returned to service. See NETA World--Summer 2012 for more information.

THE OPTIONAL TESTS Globally there has been a move towards using a dielectrics-characteristic test---capacitance, power factor, or dissipation factor--as part of the QA testing for GVPI systems.  The recently developed IEC standard (IEC 60034-27-2) defines the test procedures for performing off-line partial discharge testing as part of QA testing.5 Partial discharge tests have proven to be effective in locating isolated problems that could lead to failure; whereas the dielectrics characteristic tests provide a more general condition assessment.  Based on experience to date, both types of tests are needed to fully evaluate how well the winding is consolidated. IEEE Standards 14341, 564, and EPRI LEMUG2 study have all included these tests as recommendations for condition assessment.

Capacitance Normally when practical this test is performed on each phase of a winding with an accurate capacitance bridge. The capacitance Clv is measured at 0.2E where E is the rated line-to-ground voltage and also Chv is measured at line to ground voltage which is 1E. The tip-up is based on the fact that at line-to-ground voltage, if there are voids in the ground-wall insulation, the gas in the void ionizes to produce sufficiently high conductivity to short the void out. This reduces the effective thickness of the insulation, increasing the capacitance between low and high line-to-ground voltage. One void would have no impact, but if there are excessive voids due to the inadequate resin impregnation or problems with the tape or bonding material in the insulation system, the change in capacitance would be noticeable7. Therefore, increase in capacitance with voltage is an indication of internal voids. In the absence of voids, the capacitance will not change as the test voltage is increased. The capacitance tip-up is:

ΔC = (Chv – Clv)/Clv



Uncured/moisture contamination ⇒ Clv is high

Delamination ⇒ ΔC increases with voltage

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Maintenance Vol. 2 The higher ΔC is, the more voids there are in the winding ground wall. Note that as the void volume increases so does the ΔC percentage (Figure 1). For well bonded modern epoxy mica ground wall insulation, typically the ΔC is less than about one percent2.

Fig. 2: Dissipation/Power Factor

Power Factor

Fig. 1: Change of ΔC as a Function of the Relative Volume of Voids within the Epoxy Resin Specimen7 It should be noted that if the coils have semiconducting and grading voltage stress control layers, these influence the results of this test. At the higher voltage, the grading layers of silicon carbide material conduct to increase the effective surface area and thus the capacitance of the sections of winding being tested, and therefore may give a false indication of high void content. However if the results are trended against time, an increase in ΔC may give a true indication of increased void content in the ground wall insulation7.

Dissipation Factor This test is normally done at voltage steps that increase from 0.2E (DFlow) to normal line-to-ground voltage, 1E (DFhigh), preferably on individual phases. The intention of the test is to observe the increase in real power loss due to the presence of voids in a delaminated insulation (Δ tan δ = DFhigh – DFlow). As with the capacitance test, increases as a function of voltage are due to partial discharge and the ionization of the gas in the voids of the insulation system.

DF = tan δ = IR / IC [Figure 2]

Uncured/moisture ⇒ DFlow is high Delamination ⇒ Δ tan δ increases with voltage Typically the DFlow for epoxy mica windings is about one to two percent and the Δ tan δ is less than one percent2. Trending the results against time makes the best use of this test. As with the Δ capacitance test, voltage stress coatings can lead to ambiguous results obtained at high voltage.

The tip-up test (Δ cos θ) is done at two voltages, one below the inception of partial discharge activity (PDIV), 25 percent of lineto-ground voltage, 0.25E (PFlow), and one at 100 percent line-toground voltage, 1E (PFhigh), preferably on individual phases. As with the Δ tan dd test, the difference in the power factors at these two voltages can be attributed to the energy loss due to partial discharges.

PF = cos Ѳ = mW / mVA [Figure 2]

Uncured/moisture ⇒ PFlow is high Delamination ⇒ Δ cos Ѳ increases with voltage Typically, the PFlow for epoxy mica windings is less than about 0.5 percent and the Δ cos Ѳ is 0.5 percent, though many suggest the acceptance levels should be the same as for dissipation factor, that is, one to two percent for 0.2E values and one percent for tip-up. As with the capacitance tip-up test, the results of this test are influenced by the presence of voltage stress coatings on the coils, since at high line-to-ground voltage currents flow through it to produce additional power losses. Because this test method measures total energy, it is only sensitive to how widespread the PD is and not how close the winding is to failure (worst spot).

Off-line Partial Discharge Tests are usually taken at increasing voltage steps starting at 0.2E to line-to-ground voltage (1E), preferably on individual phases. Measurements include1,4: ●● The voltage at which partial discharge starts, or the inceptionvoltage (PDIV) ●● The voltage at which partial discharge stops, or the extinction voltage (PDEV)

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●● The largest repeatedly occurring PD magnitude at rated voltage Both the PDIV and the PDEV should be above 50 percent of line-to-ground voltage, or higher than 0.5E2,3.

4 KV COIL RESIN IMPREGNATION A single 4 kV coil was tested at various stages of the resin impregnation process from before (green) to partial to full impregnation (Figure 3).

Fig. 4: Partial discharge results for a fully impregnated coil

4 KV REWOUND WINDING Fig. 3: Test Results for 4 kV Coil Resin Impregnation (In the table above, the pink refers to values that would be of great concern, while the yellow values are marginally acceptable and the green values are within expected limits.)

A 4 kV winding tested as-is state before a rewind and after (Figure 5).

Discussion Dissipation Factor (DF): Dissipation factor decreases to between 0.01 and 0.02 as the quantity of resin is increased. The slightly elevated tip-up may be an issue. Capacitance Tip-Up: Since this is primarily testing for curing, then it makes sense that the partial state would have the highest activity along with the elevated DF values. Note that after full impregnation and curing, the values were significantly less than one percent. The increase in capacitance at 0.2E is unusual (see PD Max below). PDIV: In all cases the PDIV was higher than standard recommendation of 0.5E. PD max: This was puzzling in that the magnitude of the measurable PD increased with impregnation. It is hypothesized that before resin impregnation, the voids were too large to have detectable PD, so the effective thickness of the ground wall was minimal. Void shape and pattern as shown below are typical for small internal voids with the clusters within the first and third quadrants of the ac cycle as shown in Figure 4.

Fig. 5: Test Results for 4 kV Rewound Winding (In the table above, the pink refers to values that would be of great concern, while the yellow values are marginally acceptable and the green values are within expected limits.)

Discussion Dissipation Factor (DF): Dissipation Factor decreases after reconditioning to levels almost between 0.01 and 0.02; while the tip-up decreases as well though is still slightly higher than the standard recommendation of less than one percent. Capacitance: Capacitance behaved as expected with the lower capacitance in the rewound motor and a tip-up less than one percent. PDIV: In all cases the PDIV was higher than the standard recommendation of 0.5E PD max: The decrease in PD activity is expected in a new winding with minimal PD activity (Figure 6).



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Maintenance Vol. 2

BEFORE

REFERENCES 1. IEEE P1434-2010, Guide to the Measurement of Partial Discharges in Rotating Machinery 2. EPRI LEMUG Report 1000897 (Dec. 2000) Repair and Reconditioning Specification for AC Squirrel-Cage Motors with Voltage Ratings of 2.3 kV to 13.2 kV. 3. IEEE 56-2012 (Draft) Guide for Insulation Maintenance of Large Alternating-Current Rotating Machinery (10,000 kVA and Larger) 4. EC/TS 60034-27-2 Rotating electrical machines - Part 27-2: On-line partial discharge measurements on the stator winding insulation of rotating electrical machines 5. IEEE Std. 43-2000, IEEE Recommended Practice for Testing Insulation Resistance of Rotating Machinery

AFTER

6. IEEE Std. 95-2002, IEEE Recommended practice for Insulation Testing of Large AC Rotating Machinery with High Direct Voltage 7. Farahani, Mohsen, et al. “Study of capacitance and dissipation factor tip-up to evaluate the condition of insulating systems for high voltage rotating machines” Electr Eng (2007) 89:263-270.

Fig. 6: Partial discharge results before and after the rewind of the 4 kV motor.

SUMMARY Though it is premature to establish acceptance criteria for the capacitance results at 0.2E or the PD Max values at 1E, it is obvious based on these case studies that these five tests in combination provide valuable information about the quality of a GVPI insulation system before and after refurbishment or rewind. Each test evaluates a different aspect of the insulation, so it requires all five for a full evaluation: ●● DF or PF at 0.2E – curing state (<0.01-- 0.02) ●● DF or PF tip-up – widespread internal voids (< ~1%) ●● Capacitance at 0.2E – curing state ●● Capacitance tip-up – widespread internal voids (<1%) ●● PD – isolated problems ●● PDIV/PDEV (<0.5E) ●● PD magnitudes (depends on test)

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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Maintenance Vol. 2

ROLE OF ON-LINE CONDITION MONITORING FOR POWER TRANSFORMER OPERATION AND MAINTENANCE PowerTest 2013 Kenneth Elkinson and Tony McGrail, Doble Engineering Company

It is possible that off-line tests indicate that a transformer is in suspect condition but has not failed. Units in known suspect condition and/or serving the most critical loads are the high risk units which need monitoring. In such cases these units should already be regularly sampled for dissolved gas analysis (DGA). Further, it may be relevant to recommend the use of on-line DGA monitors. An on line monitor provides confidence between regular samples that there are no incipient faults developing which would not otherwise be caught. Further monitoring provided by bushing sensors and PD detection gives a comprehensive view of the transformer condition which supports further use of the unit. This paper looks at the role of monitoring, when to recommend the addition of monitoring, and what type of monitoring to apply. The ongoing challenge of all online diagnostic systems is in differentiating peripheral influences such as fluctuations in system voltage and temperature from actual changes in the medium (in this case the bushing insulation). The relative measurement method is susceptible to power systems variations and requires filtering. Minimizing the influence of external factors can be accomplished by either increasing the number of bushings being monitored simultaneously or by increasing the time interval over which the data is averaged. Relying on a single measurement or a few points over a short period of time can result in the misinterpretation of changes in the data due to external factors. Over the last decades, there has been an increase in interest in monitoring the performance of bushings, both in cases where the bushings are on transmission and generator transformers and in cases where failure modes are suspected for particular bushing types (1, 2, 3). To extract the value of monitoring, an understanding of the measurement being made is critical, and the effect of power system and ambient conditions must be considered.

span of two years and three months, until September 9, 2005, there was only a 2% increase in capacitance and no noticeable change in dissipation factor. On September 9, 2005, the relative angle associated with the phase A bushing began to decrease. Over the next three days, the measured angle decreased by almost half of a degree. On September 12 at 21:00, the current began to increase. In the span of seven hours, the phase A current magnitude went from approximately 24.8 mA to 27.2 mA, and the angle decreased by 2.5°. The IDD expert system issued an alert based on the substantial change in the sum current. The diagnostics calculated the dissipation factor of the phase A bushing at 5.6% and capacitance 350 pF. After a comprehensive review, which eliminated the external factors that could influence the bushing leakage current, the owner was advised to remove the bushing from service for off-line testing and confirmation of the on-line results; the off-line test measurement for the phase A bushing capacitance was 333 pF with a 5.5% dissipation factor. Figure 1 plots the hourly current magnitude of the three bushings, and Figure 2 displays the same information normalized to the reference bushing (which is phase B). Both Figures exhibit an increase in the phase A current magnitude; however, the total change before September 12, 2005 was only 2%. Over the course of one day, the capacitance increased by more than 10%.

CASE STUDY 1: RAPID DETERIORATION OF BUSHING In this case, 345 kV GE Type U bushings, vintage 1983, were installed on a Generator Step Up transformer. During off-line measurement in March 2003, all dissipation factors were found to be less than 0.3%, and capacitances of the three bushings ranged from 307 to 309 pF. On-line bushing diagnostics were installed in June 2003 to help support the operation of this critical asset. Over the

Fig. 1: Hourly record of bushing leakage current: All three phases

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Maintenance Vol. 2

Although most gas levels had been stable for some time, the hydrogen had been showing an increasing trend and the final failure brought a dramatic increase in most dissolved gas parameters. By itself, regular DGA is a useful asset management tool in assisting with the identification of suspect units. An on-line DGA monitor gives further information, bridging the ‘silence between samples’ which can mask rapid deterioration. It can be seen from the data in Figure 3 that an on-line monitor may have been able to give early warning of the failure if it had been applied and there was a ‘graceful’ element to the deterioration. Of course, if the failure was sudden and catastrophic there may have been no ability to act. Fig. 2: Hourly record of leakage current: Normalized to center phase What is particular about this bushing problem is how quickly the insulation medium deteriorated. Prior on-line experience involving degraded bushings suggests a long gestation period, with the bushing owner opting to replace the bushing before the condition becomes critical. While it is impossible to predict when this bushing would have failed, both the on-line and off-line measurements indicated that the bushing had to be removed from service. A subsequent tear-down of the bushing revealed burning within the paper insulation. Given the short gestation period, it is unlikely that a traditional time-based off-line test program would have identified the problem prior to the bushing failing.

CASE STUDY 2: DISSOLVED GAS ANALYSIS TESTING

Figure 4 shows the results from an on line system employed on a large transmission transformer. The levels of hydrogen show two dramatic changes in short spaces of time. These changes were significant enough to warrant investigation but, unfortunately, went unattended and the transformer failed. This raises the questions of not only how effective the monitoring system is, but also what plans are in place to respond to step changes. These are both asset management questions which require procedures and protocols be set up to manage the transformer, the monitoring system and to respond to alerts and alarms from the monitoring system. It is interesting to note that DGA for transformers covers the possibilities of either regular or occasional ad hoc sampling and continuous on line monitoring. Both require their own and individual asset management approaches.

Dissolved Gas Analysis (DGA) is a well understood test for determination of transformer condition; there are many standards available for interpretation of the results (4, 5); heuristic approaches are valuable but may be misleading in novel situations (6). Regular samples, particularly for larger or more critical units, yields a regular view on transformer condition, with a good DGA program giving early indication of failure in up to 50 % of incipient failures. Data from annual sampling though relatively sparse, is thus effective as an asset management tool. Figure 3 gives an indication of key DGA levels for a transformer which subsequently failed.

Fig. 3: DGA key gas evolution over time: laboratory analysis

Fig. 4: DGA key gas evolution over time: online analysis

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Maintenance Vol. 2 9. K. Elkinson, A. McGrail “Asset Management in the Digital Age” CIGRE Grid of the Future Sypmposium, Kansas City, MO 2012

Fig. 5: Long and short term control loops: Transformers Unfortunately, the use of the double control loop does not reflect the dynamic nature of the situation completely: there is a spectrum of data gathering and time scales, and there is a spectrum of responses. However, the double loop helps focus on short term activities and longer term goals. The role of asset management is to understand the loops and how they enable us to move from one type of response to another. At some point, the response time in the outer loop is no longer adequate to manage an asset’s health. At such a point, more monitoring and testing may be necessary, but we must also plan for deeper intervention: refurbishment and replacement (9).

REFERENCES 1. Sokolov, V. V., Vanin B. V, “On-Line Monitoring of HighVoltage Bushings,”Proceedings of the Sixty-Second Annual International Conference of Doble Clients, 1995, page 3-4.1. 2. Lachman, M. F., Walter, W. and Skinner J. S., “Experience with On-Line Diagnostics and Life Management of HighVoltage Bushings,” Proceedings of the Sixty-Sixth Annual International Conference of Doble Clients, 1999, page 3-4.2. 3. Bahr P., Christensen J., Intermountain Power Service Corp.; Brusetti, R., Doble Engineering “On-Line Diagnostic Case Study Involving A General Electric Type U Bushing”Proceedings of the Seventy-Fourth Annual International Conference of Doble Clients, 2007. 4. Donald W. Platts “Investigation of Transformer Hydrogen Gassing”, PPL Electric Utilities, 75th Annual International Conference of Doble Clients, Boston, USA, 2008 5. H. H. Wagner, “Detection Of Incipient Faults In Power Transformers By Gas Analysis, 27th Annual International Conference of Doble Clients, Boston, USA, 1960 6. A. McGrail “Data and Decisions”, IEEE Smart Grid Conference, Perth 2011 7. Asset Management Begins with the Assets , McGrail et al, International Conference of Doble Clients, Boston, MA, 2008 8. P. Prout, M. Lawrence, C. Sweetser, T. McGrail, “Investigation of Two 28 MVA Mobile Units”, 73rd Annual International Conference of Doble Clients, Boston, USA, 2004

Kenneth R. Elkinson, P.E., received his Bachelor of Science in Electrical Engineering degree from the University of Massachusetts at Lowell. Kenneth has held a number of positions at Doble Engineering, as Field Engineer, Client Service Engineer, and now Apparatus Analytics Engineer. Previously, Kenneth worked with National Grid in the US as a Substation Engineer. Mr. Elkinson is a licensed Professional Engineer in the state of Massachusetts. Tony McGrail is the Doble Engineering Solutions Director: Asset management and Monitoring Technology. His role includes providing condition, criticality, and risk analysis for utility companies. Previously Tony has spent over 10 years with National Grid in the UK and the US. He has been both a substation equipment specialist and has also taken on the role of substation asset manager and distribution asset manager. Tony is a Fellow of IET, a member of IEEE, ASTM, CIGRE and the IAM, and is currently on the executive of the Doble Client Committee on Asset and Maintenance Management. His initial degree was in physics. He has an MS and a PhD in EE and an MBA. Tony is an Adjunct Professor at Worcester Polytechnic Institute, Massachusetts, leading courses in power systems analysis.

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Maintenance Vol. 2

SMALLER COMMISSIONING ASSIGNMENTS REQUIRE GREAT DETAIL PowerTest 2014 Brian S. Moores, PE TRC Companies

INTRODUCTION The demands placed on today’s electrical power transmission and distribution systems have led to a need for increased reliability, dependability, and security with regard to the systems used to protect and operate the high voltage transmission and distribution equipment. This demand, along with newer protection technologies, has led to widespread upgrades to existing protection and control systems, many of which are decades old. These upgrades are engineered to paper and sent to the field for construction and commissioning, where Electricians, Commissioning Engineers and Test Technicians provide the manpower to install, test, commission, and certify systems operability prior to placing the new systems in service. The majority of the upgrades occur in energized substations, also called “brownfield” sites, where adjacent high voltage equipment and secondary protection systems remain in service during the upgrades. Work in brownfield sites poses a variety of risks to the personnel performing the work and also to the surrounding high voltage transmission or distribution system. Many of these upgrades are relatively small in scope, perhaps only upgrading a single piece of equipment with a construction, testing and commissioning schedule of only a week or two. It is often overlooked that these upgrades require the same risk assessments, work practices, safety briefing, clearance requirements, testing procedures, test equipment, and documentation as required on much larger jobs. Management, Engineers and Technicians may make statements such as: “It is an easy job”, “You will be able to get in and out”, “A small job, just a couple of weeks”, “You won’t have any problems”. These beliefs promote a false sense of security which can lead to mistakes causing personnel injury, equipment damage, and inadvertent power outages. No brownfield sites are identical. The power utility, design history, installation history, maintenance history, upgrade history, adjacent systems, or customers served contribute to the current status of the site when a new upgrade is set to begin. These variables add risk to a brownfield site, and as a result, these sites require extra attention when performing upgrades. Some risks include, but are not limited to: exposed energized parts (primary and secondary); incorrect, duplicate or outdated prints; mislabeled wiring; undocumented maintenance or previous system upgrades; outdated equipment; multiple ongoing projects; critical protection systems

and critical customers. All of these cumulative risks can cause personnel safety issues or inadvertent power system outages, which in turn can lead to investigations, fines, lost revenue, and/or loss of employment. Proper preparation, planning, risk assessments, and careful execution will help mitigate these risks significantly. The focus of this paper is on the specific project work associated with secondary protection and control systems. This paper will examine the recommended planning and work flow processes to ensure a safe and successful project outcome.

PREPARATION AND PLANNING It is the responsibility of the Lead Commissioning Engineer to prepare and plan for the testing and commissioning phase of the project. This is a critical phase of the project, and occurs prior to mobilizing to the site. This phase will lay the foundation for the onsite work and help identify any issues before site work begins. The Lead Commissioning Engineer must review all project documents to obtain a complete understanding of the project scope of work and required responsibilities. These documents include, but are not limited to: removal and installation design drawings, scopes of work and/or project specifications, schedules, operational descriptions, switching orders, system diagrams, outage applications, SCADA tab sheets, protective relay settings, and owner standards. Upon review of the project documents, the Lead Commissioning Engineer should develop the following plans: Testing and Commissioning Plan – This is a task based step-bystep, system-by-system plan of required testing and commissioning activities for all modified or new equipment and protection systems. The plans should outline the equipment and systems being upgraded, replaced, or modified, the associated testing and commissioning tasks, and also provide specific details encountered as a result of answering the questions described below. The plan is arranged to follow the required sequence of work. When schedule is a concern, it may also be necessary to produce a resource and task matrix identifying specific tasks. These tasks may include personnel, dates and durations to further refine the construction, testing and commissioning requirements.

46 Outage and Energization Plan – This is a plan detailing the clearance zones, primary and secondary equipment/systems to be isolated, restoration/energization of modified/new primary and secondary equipment, and testing hold points. When planning for outages, the steps required to remove the equipment from service must be considered. These may include high voltage switches or circuit breakers, low voltage potential, currents or AC/DC control circuits, protection schemes, as well as control measures or lock-out-tag-out procedures to prevent inadvertent re-energization. For energization, the plan should identify the steps to restore the equipment to service, as well as identify hold points for testing and data acquisition. The plan should also provide explicit details encountered as a result of answering the questions below. The outage and energization plan typically is used in conjunction with switching orders. Health and Safety Plan (HASP) – The HASP includes safety and incident response guidelines and procedures, nearby medical facility information, safety personnel contact information, and specific Job Hazard Analysis (JHA) for each major task. The JHAs should identify basic job steps, potential hazards and recommended safety procedures. JHAs are included for the tasks identified in the testing and commissioning plan as well as site mobility, driving and other areas of hazard and risk. As previously discussed, no brownfield site is identical, and they generally present more risks with regard to construction, testing, commissioning and safety. Several questions are considered when reviewing documents and developing plans: Is the scope of work well-defined? A well-defined scope of work leaves no question about the project work that needs to be completed. Beware of “boiler plate” scopes of work. It is imperative to understand exactly what the project entails. Is the design intent understood? The testing and commissioning phase is the last opportunity to find any design flaws or errors prior to placing in service. It is imperative to understand the design intent to ensure that the testing and commissioning of the equipment and circuits are thoroughly completed. The Lead Commissioning Engineer should address any questions with the Owner or Engineer of Record. Do you have the correct project documents? Obtain and review all transmittals provided by the owner or engineering firms to ensure documentation in hand is complete and latest revision, and, where applicable, stamped by a Professional Engineer. Preliminary drawings and documentation should not be used. What is the project schedule and is it realistic? Review the schedule to ensure adequate time has been allocated for the testing and commissioning. Often the testing and commissioning window is a single line item on the schedule and includes the construction time, which reduces the available testing and commissioning time. Often there are previous project or construction delays, which, since the testing and commissioning is

Maintenance Vol. 2 generally the last task, has removed any float from the testing and commissioning window. Often the individuals creating the schedules do not understand testing and commissioning needs. What is the construction sequence? Has a detailed construction sequence been developed? Often the construction sequences do not take into consideration the testing and commissioning needs. Construction may influence the testing and commissioning sequence, and testing and commissioning needs may influence the construction sequence. What protection schemes need to be isolated? The equipment and systems being upgraded, replaced, or modified must be isolated prior to beginning project work. Isolation plans are developed and used to log the isolating devices such as breakers, fuses, and test switches. Ensure communication assisted tripping schemes are isolated from their remote end connections or local Ethernet-based protection has the required software isolation. What adjacent protection schemes must be considered? In most cases, the systems and equipment being modified will overlap to other adjacent or common systems which will remain in service during the specific project work. Some of these systems may be critical such as common bus or breaker failure lockout schemes, or inter-area special protection systems. These may not show up in revision clouds on the construction drawings, so it may be necessary to review beyond the focus of the project scope of work. It is critical to review not just the station equipment, but entire protection schemes as a whole, as some may extend to remote substations. Are any temporary schemes required? There may be circumstances where the final system configuration may have to be achieved through a series of temporary steps. There might need to be temporary cross-tripping schemes or temporary relay settings implemented throughout the sequence of work to maintain adequate system protection. What are contractor and owner responsibilities? Identifying the roles and expectations of the contractor and owner help ensure no gaps are encountered or miscommunications occur once the project is underway. This goes along with understanding the scope of work. It is also imperative that the Lead Commissioning Engineer knows his/her role, whether it is oversight or hands on, or some combination of both. What are the testing standards to be used? Know what testing standards are to be used to ensure tests are identified and performed in accordance with expectation. Some utilities or plants have their own set of testing standards, some specifically call out NETA, and others have none. What specific documentation is required? Know what test certification sheets and equipment data sheets are to be used to ensure tests are properly performed, documented and certified in accordance with expectation. Some utilities or plants have their own set of documents; however, others have none, in which case the contractor would need to provide his/her own.

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Maintenance Vol. 2 What got missed? Review for any traps or out-of-the-ordinary conditions that may add risk to testing and commissioning. Once plans are completed, they should be reviewed by a second qualified Engineer. The second Engineer should review utilizing the same project documents and address the same questions as used to develop the plans. The plans and any issues determined from the document reviews and plan development are reviewed with the project team to discuss strategy and any necessary corrective actions. The preparing and planning is a key piece of the job, even for the smallest job. In some cases, the planning of the smaller brownfield jobs will result in more detail than larger jobs due to the intricate nature of the tasks involved and surrounding systems.

SITE MOBILIZATION Once the off-site preparation and planning phase is completed, the on-site phase of the project begins. For smaller projects, there may be an impulse to “dive head first” into the construction, testing and commissioning without due regard to risk, safety, personnel or the surrounding site environment. Prior to beginning any physical work, the Lead Commissioning Engineer must set up the job site and start the project off with plan and documentation review, risk assessments and safety review, and perform on-site preparation. The focus of this section is on the specific project work associated with secondary protection and control systems.

Plan and Documentation Review Discuss with the applicable site personnel the health and safety plans, commissioning plans, outage and energization plans, switching orders, outage applications, schedules, protective relay settings, SCADA settings/tab sheets, operational descriptions, system diagrams, owner standards and any other pertinent project documents. It is imperative all site personnel involved understand the project specifics and their assignments.

Risk Assessment and Safety Review Following mobilization and prior to beginning any work, perform a site risk assessment. A thorough risk assessment creates awareness to the project team for site, system, and safety risks. Discuss identified risks with the project team and take the necessary measures to mitigate the risks. Several items are considered when performing a risk assessment: Site Team – Review the personnel involved with the construction, testing, and commissioning. Are they qualified to perform their duties as assigned? Review experience and qualifications to perform their duties as assigned. Review the confidence levels of the personnel; overconfidence can be more dangerous than lack of confidence. Site status – What “vintage” is the site? Is the site well-organized? Is equipment in close proximity to each other and the

required work space? Is there adequate work space? Are there any other projects being performed concurrently? Are there other work groups on site? Are there other drawings from past projects? Construction drawing packages – Is there a single complete assembled package onsite to be shared by the construction and commissioning personnel, and has it been verified to be the correct revision and cross-checked against a transmittal? Ideally a single set of drawings is used. Use of multiple sets of drawings could result in inconsistent information used by the construction and commissioning personnel. Existing station drawings – Is there marked up as-built information on station drawings from previous projects or maintenance that is not on the issued construction drawings? Review for any conflicts with the design package and develop corrective action. Instruction Manuals – Are all manuals available for all equipment to be modified or installed per the project scope of work? Project Documents and Plans – Have they been reviewed with all project team members and does the entire team have a full understanding of the project scope of work and associated tasks? Test Equipment and Proper Tools – Are all required test equipment and tools on site and calibrated (where applicable), and personnel qualified to operate the equipment? System Risks – Are there any special or critical systems or outof-the-ordinary system configurations? Is the transmission or distribution line radial? Is there generation or customers that could be affected by an inadvertent operation? What are the implications of an inadvertent operation? Is there a recovery plan in place should an inadvertent operation occur? Schedule – Is there enough time to perform the project work with the proper emphasis on safety and quality? Personnel Safety – This is reviewed in conjunction with the Health and Safety Plan and associated Job Hazard Analyses. Review for any additional safety risks not initially identified in the HASP or JHAs. Review zones of clearance, minimum approach distances, PPE requirements, lock-out-tag-out procedures and tag holders.

SITE PREPARATION Create a visual work zone in the control house or mechanism house. Equipment that is being modified or removed during the construction process should be clearly identified; this can be done as simply as using a piece of brightly colored tape. It is equally as important to place barricades to clearly identify boundaries in control panels and to block access to equipment, panels or cabinets where work is not to take place; control panels can look very similar in a brownfield environment. Plastic sheeting, caution tape, colored electrical tape, signs, hanging tags, etc. are all suitable

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means of barricading. Exposed energized fuse blocks, terminals, etc. should be carefully covered with electrical tape. In tight spaces, it is also helpful to create a buffer with caution tape or cones to reduce the possibility of accidentally bumping in-service control switches or equipment. Identification and barricading helps the site personnel clearly identify equipment and allowed access areas, thus reducing the possibility of working on the wrong equipment.

Two-person verification and constant communication is utilized for each step. It may take fifteen minutes to prepare for a twominute task, but the risk of personnel safety and/or inadvertent operation is diminished greatly.

CONSTRUCTION, TESTING AND COMMISSIONING

Isolation Plans – It is imperative that an organized and detailed checklist is kept of all necessary isolation to prevent inadvertent operations during testing. The checklist is used, not only to avoid overlooking parts of the protection scheme during isolation, but also to verify that the scheme has been completely restored at the conclusion of testing.

With plans in place, work zones identified, and the project team aware of the risks and responsibilities, construction can begin. The secondary systems can be removed from service per the outage plans, protection systems isolated and logged per isolation plan, and energy sources locked/tagged out where applicable. For all of these steps, two-person concurrent verification and constant communication should be employed. Daily planning and safety briefing is required and must be documented. At the start of each day, the tasks for that day should be developed and reviewed. Major tasks should be identified and each task reviewed for associated safety and systems risks identified and discussed with the team. Checklists are used to capture the information with a signoff from the personnel involved with the tasks. This is an important step because it focuses the team on the specific tasks. If there is any deviation from the planned activities, the work should stop and the work plan should be revised and reviewed with the project team prior to re-commencing work. Items to be discussed: Daily Tasks – What circuits are being worked on? What does the work entail? Is any in-service equipment affected? Are there any special conditions to be aware of? What are the implications of inadvertent operations? Are recovery plans required? Safety – What are the hazards and risks associated with the tasks (gravity, electrical, mechanical, kinetic, environmental)? Discuss work procedures, people involved, PPE, tools, equipment, and any special precautions. Consult the necessary Job Hazard Analysis forms. Prints – Are all prints assembled for the daily tasks? Personnel – Are all personnel aware of activities and safety and systems risks? Do they understand their direct roles and responsibilities? Is the design intent understood? Identification – Is the equipment identified, barricaded, isolated? Two-person verification – Ensure that two-person verification and constant communication is utilized. When performing construction, testing, and commissioning in a brownfield environment, the Lead Commissioning Engineer directs the activities and works directly with assistant Field Engineers and Electricians to perform the work in the correct sequence, one wire or one circuit at a time. Assistant Engineers and Electricians should not be left alone to perform their associated tasks.

The Lead Commissioning Engineer, Field Engineers and Electricians should be continuously aware of the following when work is being performed:

Adjacent and/or Common Protection Systems – Often removals and installations occur on terminals or equipment shared by in-service protection systems. Care should be taken to ensure work is being performed on the correct circuits. Accidentally performing work on an in-service circuit may result in personnel injury or inadvertent operation. Prior to touching any terminal point, confirm that no AC or DC potential exists. For work in current transformer circuits, confirm that no current is flowing. Where the removals or additions take place next to in-service energized terminals (on a terminal block, control switch, or lockout relay, for example), use electrical tape to cover the adjacent energized terminals. Two-person concurrent verification and constant communication should be employed. Incorrect Wiring and/or Labeling – Do not assume that the wiring drawings accurately match the field wiring. Prior to removing wires, use hand-over-hand tracing of the wire to ensure the wire being removed accurately matches the construction prints. Use wire clips to identify cables and conductors. Twoperson concurrent verification and constant communication should be employed. Drilling and/or Sawing – Where drilling or sawing is required, protection against metal shavings should be utilized. Sawing with reciprocating saws may create excess vibration which could cause inadvertent operation to equipment in adjacent panels. Worker Focus – Are the workers fatigued due to extended hours? Are the workers moving into or out of holidays or vacations? Is cell phone use or personal conversations interrupting the tasks? All of these will cause distraction and contribute to loss of personnel awareness and focus. Site Environment – Is there significant commotion or noise due to other unrelated site activities? Are there other work groups performing maintenance or other project activities? Does the schedule require simultaneous activities, resulting in numerous workers in close proximity to the project area? Is weather a factor for outside work? Noise, commotion, multiple personnel, weather, and other site environment issues will contribute to loss of personnel awareness and focus.

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Maintenance Vol. 2 Protection Communications – Are all necessary pilot or transfer trip communication channels isolated to prevent any remote end inadvertent operations? Are all Ethernet-based software protection points isolated to prevent local inadvertent operations? Where common multiplexer communications or fiber patch panels are used, take care to ensure existing communication channels are not disturbed to avoid local or remote end inadvertent operations. Test equipment simulating power line carrier frequencies should be limited to only the frequencies used for the tested application; simulating the wrong frequencies may result in local or remote end inadvertent operations. DC Circuits – Shorting a DC circuit or inadvertently grounding a DC circuit can pose serious hazards to personnel and the equipment. Current Transformer (CT) Circuits – Energized CT circuits pose an extreme hazard to personnel and the CT itself if the secondary is open-circuited. The voltage developed across an open circuit relay class CT can reach several thousand volts. The utmost caution must be used when working around energized CT circuits to minimize the possibility of inadvertently causing an open-circuit. Voltage Transformer (VT) Circuits – Energized voltage circuits pose several hazards. The most obvious is shock from the AC voltage present. However, there is also the hazard of shorting a live circuit, which can harm personnel and damage the VT. An unintended short or open on a voltage can also cause an inadvertent operation. Test Jumpers – It is frequently necessary to use test jumpers during testing and commissioning. All jumpers shall be adequately sized, and be protected by a fast-acting fuse sized to prevent damage to the circuit and equipment under test. Use caution when installing any jumper and make certain the application is safe before installing it. Check the jumper for healthy insulation, terminals and continuity before each use.

ENERGIZATION When the construction, testing and commissioning are complete, the modified and new equipment is ready to be energized and placed in service. It is critical for the Lead Commissioning Engineer to review and certify the testing and commissioning data prior to energization. Energization cannot proceed until all data is reviewed and certified. Data sheets, test certification sheets, commissioning drawings and test data must be accurate and complete with no holes or questionable data entries. Perform a thorough site walk down to validate all equipment readiness, verify temporary safety grounds are removed, CT circuits are shorted or unshorted as necessary, fuses are installed, or any temporary wiring or jumpers are removed. Restoration and energization will proceed based on the isolation plans and energization plan. In a brownfield site, take care to ensure proper sequence of energization to ensure the correct

protection schemes are in service, system reliability is maintained, no adjacent protection systems are disturbed, and no inadvertent operations occur. This sequence was previously identified in the energization plan; however, a thorough review of the plan prior to energization should be performed to ensure accuracy is maintained. Where restoration of protection equipment interfaces with common systems, such as breaker failure lockouts, extra steps shall be taken to ensure the lockout will not operate during restoration.

CONCLUSION Smaller brownfield testing and commissioning projects require great attention to detail to ensure safety and minimize risks. These smaller projects are often perceived as simple or easy, but, as discussed here, there are many possible scenarios or situations that can lead to personnel injury or inadvertent operation. Proper preparation, planning and execution creates a safe and efficient work environment, significantly reducing the possibility of incident or injury. Proactive off-site and on-site preparation and planning phases are crucial in identifying project scope, tasks, risks and safety considerations. On-site construction, testing or commissioning should not begin until the preparation and planning phases are complete and understood by all project team members. A questioning “stop-and-think” attitude is required, along with a “zero incidents” philosophy to ensure success without incident. In summary, if you fail to plan, then plan to fail. Brian Moores has over thirteen years of experience and progressive responsibility in engineering consulting. His qualifications include ten years of design experience, including substation protection and control systems, substation power equipment, substation communication equipment, and substation automation systems. Mr. Moores’ background includes projects for most major utilities in the Northeast. Mr. Moores has over thirteen years of field experience, including testing and commissioning, and energization of primary equipment, secondary protection and control systems, and automation and integration systems. Mr. Moores serves as the Northeast Regional Manager of Field Services.

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DEPLOYING THERMAL CAMERAS TO YOUR UTILITY’S BEST ADVANTAGE: A TOW-PRONGED APPROACH PowerTest 2014 Brad Risser DEPLOYING THERMAL CAMERAS TO YOUR UTILITY’S BEST ADVANTAGE: A TWO-PRONGED APPROACH A top-to-bottom integrated IR program for utility PM and PdM that puts the appropriate thermal technology into the right hands across the board is becoming the new industry norm. Most public utilities already have a dedicated IR team within their predictive maintenance program using advanced IR cameras for regular substation surveys. In addition, more and more utilities today are putting affordable, point-and-shoot thermal cameras into the hands of linemen and troublemen, the frontline of defense, giving them the ability to perform quick scans and safety checks on energized equipment from a safe distance. This not only helps avoid potential hazardous situations found during inspection or maintenance, it also helps teams catch anomalies sooner that may warrant further investigation either by the technician on site or by thermography groups with higher resolution cameras. Catching these problems early on permits cost- and time-effective repairs to be made, avoids downtime or possible failure, and thus increases both the bottom line and public confidence.

SECTION ONE. THE VOICE OF EXPERIENCE: A UTILITY IR SPECIALIST SHARES STRATEGIES AND EXAMPLES Utility equipment faces a host of conditions that cause degradation—harsh environmental conditions, load imbalance, development of resistance in system components and contact surfaces, structural fatigue, and age. Since temperature is a key indicator of equipment condition, by using a normal thermal signature, an IR survey can pinpoint and help evaluate anomalies. After a number of years of contracting highly valued IR inspections to a third party, in 2000, the Knoxville Utilities Board (KUB) in Tennessee tasked one of their own, systems operations technician James Dan Roark, to develop an in-house thermography program. As Roark describes in his InfraMation paper, acquiring accredited IR training and developing a well-thought out infrared predictive plan are essential first steps in developing an effective condition monitoring program. Key initial steps included evaluating overall system size, prioritizing equipment (based on system integrity), and developing appropriate inspection time-frames and rotations under a variety of weather conditions. As for the actual inspection process, Roark arrived at a three-step process to ensure complete coverage of all targeted components.

STAGE ONE: “START AT THE TOP AND WORK DOWN” As Roark details in his paper, “To ensure that nothing is overlooked, inspect all high voltage structure equipment first – structuremounted potential and current transformers, air break switches, bus connections, and substation line terminations.” Figure 1, of 69KV potential transformers, taken with a FLIR 320×240 resolution thermal camera, reveals the importance of using correct camera settings. As Roark notes, “Figures 1a and 1c show the same image. If slight thermal variations are present and go undetected, extremely dangerous situations (the empty bushing on left in 1c) may be overlooked!” Other types of common problems in air break switches and line connections are also easily revealed as hotspots by a properly trained thermographer as shown in Figure 2.

Fig. 1a

Fig. 1b

Fig. 1c

Fig. 2a: Visual and thermal images of 69KV air break switches reveals anomalies within thecontacts and mechanism.

Fig. 2b: Visual and thermal images of 69KV line connections supporting substation.

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Maintenance Vol. 2 STAGE TWO: INSPECT DISTRIBUTION EQUIPMENT Roark goes on to suggest that after the high voltage structure inspection is complete, the next step is to “Evaluate distribution equipment, including main substation transformers, regulators, circuit breakers, and low voltage disconnect switch structures.” The images in Figure 3 indicate a critical condition within a tapchanger—thermal levels in tapchanger compartments should never be higher than winding compartments.

Fig. 6a

Fig. 6b Fig. 6c 14.4KV Vacuum Circuit Breakers

A very frequently encountered problem is overheated disconnect switches, usually remedied by cleaning, adjustment, and lubrication. However, with extreme cases such as those encountered by Roark in Figure 7, it is very important to re-evaluate after maintenance is performed. If the condition persists, replacement may be required as it was in this case.

Fig. 3: Thermal and thermal images of a 25MVA transformer reveal tapchanger elevated temperatures In Figure 4, all three images show conditions that may cause premature unit deterioration from connection problems on secondary bushings in 4a to a secondary core ground that has allowed the iron of the winding structure to become a current path in 4b to malfunctioning radiators in 4c.

Fig. 7a

Fig. 7b

Fig. 7c

15 KV disconnect switches before and after replacement

STAGE THREE: INSPECT CONTROL AND MONITORING SYSTEMS

Fig. 4a Fig. 4b Fig. 4c A variety of transformer conditions indicating potential problems In Figure 5, Roark presents images that prove the necessity of scanning from different angles to correctly evaluate transformers and regulators. Figure 5a seems to indicate that the regulator has an adequate oil level for proper radiator function while Figure 5c indicates differently.

Fig. 5a

Fig. 5b Fig. 5c 25MVA Regulating Transformer

However, not all elevated readings indicate abnormal situations. As Roark explains, “An inspector might think an internal control wiring problem exists in the breaker shown in Figure 6a, but that is not the case. In fact, that image is normal. The control cabinets of outdoor switchgear are heated. The heater of the circuit breaker in Figure 6c is inoperative, and in danger of moisture encroachment, one of leading causes of switchgear failure.”

After a thorough examination of the yard to ensure all structureequipment has been inspected, Roark moves the inspection inside to the control houses or protected areas in KUB’s substations. In the control and monitoring systems located within, loose connections and overloaded circuits are the most common problems. Heating systems should also be evaluated to ensure an appropriate operating environment for relay and control systems. Abnormal thermal signatures may result from, of course, loose connections, but also improperly pressed crimp connections, broken terminal screws, and deteriorated control wire, some examples of which are shown in Figure 8. Roark stresses, “The problem source must be positively identified and eliminated, or system protection may be jeopardized.”

Fig. 8: Common control system problems Undersized wire or excessive current in control wiring as shown in the images in Figure 9 can cause overloaded circuits, which left unaddressed may result in total failure and possible catastrophic consequences.

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Fig. 9: Overloaded circuits As Roark notes in his conclusion, “…it is important that recommendations are based on knowledge, camera skill, and experience. Be aware of reflections, solar loading and, most importantly, emittance variations that can cause greatly exaggerated readings. You can easily be fooled into believing there are problems where none exist.”

outages, expensive replacements, and injuries and both utilities are now benefitting from the confidence and higher productivity that comes with the greater accuracy, improved efficiency, and safer working conditions that cost-effective thermal imaging cameras help make possible. Plans for adding more cameras, like the new FLIR E4, E6 and E40, are also in the works.

SAFETY IS #1

THE NEXT STEP: PUTTING THERMAL IMAGERS TO WORK IN UTILITIES ON A DAILY BASIS Together, Southern California Edison (SC Edison) Pacific Gas and Electric (PGE) have recently added over 650 new thermal imaging cameras to their predictive maintenance programs in order to minimize risks and maximize the efficiency and effectiveness of inspection programs. Thorough inspection is crucial for ensuring that components and systems are functioning at peak performance. Inspections had previously been performed with an IR thermometer (aka spot temperature gun or radiometer), a fairly common tool of the trade. A spot temp gun can only target one spot at a time, and often requires working closer than is practical and safe. An assessment of a padmounted transformer, for example, requires a 7-point inspection of each of its insulated elbows. Examine ten elbows and you’re up to 70 measurements – extremely time-consuming. In addition, because it typically provides merely an average temperature across a circular area, the farther away an IR thermometer is from a heat source, the larger the measurement zone and more averaged the readings. Spot radiometers not only make the measuring process tedious and potentially more hazardous, their results too-often turn out to be startlingly inaccurate. Missing a hotspot could mean missing a brewing problem that signals an impending failure, which could also leave the technician with a false sense that all’s well. Thermography groups at both companies had discovered early on that a thermal camera could scan a larger area and more targets from a safer distance much faster as well as capture literally thousands of more accurate temperature measurements in each image. Select SC Edison crews already had FLIR i40s, and substation crews at both utilities had considerable experience with some of the more advanced FLIR cameras required for those applications. So after experiencing positive results with the lower-cost thermal imagers, SC Edison has added nearly 300 more i40s and PG&E ordered over 350 FLIR i7s. With more technicians and trucks armed with the technology, a far greater number of linemen and troublemen are now able to do quick scans and safety checks on their troubleshooting rounds. As a result, more potential problems are being caught and fixed in time to prevent

Fig. 10: Ray Friend, PG&E Substation Maintenance and Construction Supervisor Substation Maintenance and Construction Supervisor Ray Friend explained PG&E’s reason to add the lower-cost thermal imagers as a simple matter of common sense. “Safety is always the first thing we want to think about. And a big thing I get from talking to the people now using an IR camera is the confidence it gives them in the equipment they’re going to be working on. They want to know if something is operating [within safety parameters] the way we expect it to, whether it’s oil-filled equipment or an air switch under load.”

Fig. 11: PG&E technician doing safety check scan at substation with i7 Friend says crews now routinely do a quick scan to look for unusual hotspots on a variety of components that may need maintenance. “If you’re required to stand at the end of a 16-foot disconnect stick, ready to rip a switch open, you want to be able to trust that the switch is properly adjusted and going to do what it’s supposed to…that’s what the camera gives us.” In other words, it helps them see heat anomalies that signal potential danger.

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Fig. 12: Switch shows up Fig.13: Single phase extremely hot indicating poor transformer running much hotter or damaged contact point than similar units around it While PG&E continues to use high performance FLIR cameras for their more intensive and detailed IR inspections, Friend said the low-cost i7s make it possible for his team to use thermal imaging more frequently on their rounds and on a moment’s notice. “It’s simple to operate… there’s no rocket science involved… you can interpret things easily on the screen…all you need to have are a [few] instructions as to what to look for. And it’s portable and seems to be very rugged. We have them in trucks bouncing around and have had no issues.” Since electrical equipment tends to get hot before it fails, Friend says it’s good to have a FLIR handy. “Normally what they’re finding is loose connections, switches out of adjustment, regulators and breakers that are running too hot. They’re also finding oilfilled bushings and other equipment with abnormal temperature differences that indicate a lack of cooling.”

Fig. 14: Loose Crimp Connection

Fig.18: Phase C elbow has Fig. 19: Overloaded a poor connection that could transformer elbow connection fail at any time. Temperature is much higher inside the vinyl jacket than the exterior reading

ROI: REPAIR VS. REPLACE For example, an electrician doing a routine substation inspection in the San Joaquin Valley not long ago was passing within five feet of an energized transformer bank and quickly became alarmed. “Normally, you would expect it to give off some heat, but this thing he could instantly feel on his face,” Friend recalled. “So he immediately grabbed his i7 from the truck and took a picture and verified within seconds that there was an issue…it was white hot. He called his supervisor from his cell phone and was able to show what the thermal camera saw. The supervisor immediately took that thing out of service.” According to Friend, once offline, they found there was absolutely no oil flow in the transformer. “By catching it in time, we spent only about $300,000 to repair that transformer bank. That’s a major savings compared to the roughly $3 million to replace it, which we would have had to do if it had completely failed and been destroyed.”

Fig.15: Loose or bad 14 KV splice indicated by overheating compared to other conductors on the pole Fig. 20: Oil filled transformer

Fig. 16: Bad splice or loose connection on service drop shows abnormally hot

Fig. 17: Hotspot on contacts of closest substation protection switch need attention

Fig. 21: Thermal image shows transformer levels

Friend pointed out that the weeklong repair work requiring a crew of six was a quick turnaround. In fact, it’s about one-sixth of what it would have taken to wait for a replacement, if they could have found one in that time-frame since sometimes delivery on such equipment can span months. Fortunately, in this particular substation location, detecting the problem early and distribution workarounds helped the company and customers avoid the impact of a serious outage.

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AN OUNCE OF PREVENTION… Friend says that across the board thermal cameras have allowed PG&E to find issues early that would have eventually shown themselves but perhaps under more serious circumstances. “We’re catching them a lot sooner…in time to deal with it properly and safely…long before it fails.” That gives PG&E much better control over a situation, allowing them to more effectively target and plan repairs that help prevent expensive emergencies and shutdowns. With the ability to uncover hidden problems well in advance when they can still be repaired instead of being replaced.

Fig. 22: Lightning arrestor on the right is failing. When it finally does, it will short to ground and damage equipment and endanger personnel

CONCLUSION Utility PM and PdM programs have come to rely on IR technology to assist in almost every aspect of inspection of equipment. An IR program will be most effective when a two-prong strategy is used. First, deploy a multitude of less expensive, easy-to-use, yet highly effective thermal imagers to initially locate problems safely and efficiently. Subsequently, follow up on those findings as needed via advanced assessment with thermal cameras offering greater resolution, telephoto lenses, and a more complex feature set that allow for documentation of defects in detail and tracking of repair/trending of performance over time. Brad Risser is a graduate of the United States Military Academy at West Point and received a Bachelor of Science in Engineering. He served in the air defense branch of the Army for 5 years and left as a captain. After leaving the military, he then went to work for a Fortune 500 chemical company where he worked as a chemical sales consultant and manager for 11 years. During this period, he also attended Pepperdine University and earned a Masters of Business Administration degree. For the past 15 years, he has worked for FLIR Systems, and is currently the Director of Sales for the Western United States. *All images courtesy of Roark/KUB Tennessee

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INFLUENCE OF THE TEST VOLTAGE WAVE SHAPE OF THE PD CHARACTERISTICS OF TYPICAL DEFECTS IN MEDIUM-VOLTAGE CABLE ACCESSORIES PowerTest 2014 MSc. Hein Putter, MSc. Daniel Götz, Dr.-Ing Frank Petzold, Dipl.-Ing. (FH) Marco Stephan SEBAKMT / Megger, Germany, Henning Oetjen, Ph.D., Megger VF, US INTRODUCTION Partial Discharge measurements have become an important, non-destructive and reliable diagnostic method to detect weak spots in the insulation of underground cable circuits. PD measurements are routinely used in laboratories, e.g. for the commissioning tests of cable reels as well as in the field to verify the installation quality. Laboratory testing uses typically a 50/60Hz HV power supply and many of the factory testing standards require this. The same 50/60Hz has proven not very practical when it comes to field testing. When considering a test frequency other than 50/60Hz, it is of greatest importance that its PD characteristics are very similar to those at 50/60Hz, otherwise a reliable interpretation of the results is not possible. Especially the PDIV (Partial Discharge Inception Voltage, voltage at which PD first become active) should compare very well to the 50/60Hz value. PDIV is one of the most important parameters to characterize PD. Incorrect interpretations can occur if the PDIV at 50/60Hz is below the operating voltage and the PDIV of the alternate voltage shape is above the operating voltage. In this case the higher PDIV at the alternate voltage shape can lead to a “non-critical” assessment, where in actuality the 50/60Hz results mandate a “critical” assessment, which would trigger a well defined action level. Many research papers have been published addressing the comparability of PD characteristics at various voltage shapes. Edin [1] found that the PD activity extinguishes at low frequencies. Therefore it can become challenging to conduct a PD measurement at a low frequency like 0.1Hz. Without lots of data it is not possible to predict the comparability of the PDIV 50/60Hz and another frequency. The case of a special research project [2] shows a >300% difference between 50Hz and 0.1Hz, when a surface discharge was evaluated. It can be explained in this particular case by considering the dependency of the surface discharge from the voltage gradient, which for this type of a discharge is 500 times smaller at 0.1Hz compared to 50Hz. The table below shows the results of a list of publications comparing the PDIV at 50Hz and 01.Hz, amounting to differences between 10 and 250%, see Table 1.

Table 1: Comparison PDIV 50Hz to 0.1Hz Most surface discharges in cable systems occur at the terminations. Because of their nature they can be diagnosed with alternative methods like acoustic detectors or visually by special cameras. Discharges at layered interfaces are always internally and responsible for most PD defects within accessories. Typically they cannot be detected by acoustic or visual methods. Both surface discharges and discharges at layered interfaces are very dependent on the voltage gradient, which makes them similar in their behavior. Therefore it can be expected that discharges at layered interfaces show a similar dependency with regard to the PDIV when compared to surface discharges. This was confirmed by an actual field test of a termination at E.on, the biggest German utility company [3]. The splice was chosen because of its troublesome history. The circuit containing the splice tested for PD both with 50Hz and 0.1Hz, the PDIV for 50Hz was below operating voltage, compared to the PDIV above 2Vo at 0.1Hz. The splice was cut out and evaluated. It showed critical PD patterns in the semicon layer and the insulation. This proved beyond any doubt that PD had been present for quite some time at operating voltage and that the splice was definitely in critical condition. Besides 0.1Hz VLF sinusoidal and 50/60Hz PD methods a method based on a Damped AC voltage shape (DAC) has established itself as a very effective method for PD testing. Over the past 10 years a lot of field test data was collected with great success in terms of benefit to the cable owner using this method. The data show very good correlation between the 50/60Hz and the DAC data. This resulted in a broad comparative study of competitive , commercially available PD Measurement Systems conducted by CESI [4]. Table 2 shows the selected voltage shapes. In order to analyze the comparability of the systems to the 50/60Hz results, 3 parameters were selected, PDIV, PD Localization and PD levels.

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Fig. 2: B lock Diagram of a VLF CR Unit Table 2: Test voltage shapes used in the comparative study [4] Figure 1 shows the PDIV for a number of artificially created fault. The DAC method (the degree of dampening correlates to the natural attenuation induced by the tested circuit) proves to be comparable to the 50/60Hz data. The largest differences are seen with the 0.1Hz Sinusoidal wave shape, which was confirmed by the field test results on 18 different cables [4].

One of the substantial advantages of the CR technology is its capability to store and recover the energy required to charge the cable via the choke during the polarity change of the voltage. It allows to recover about 90% of the stored energy within the charged cable, which is available to charge the cable in the opposite polarity during the next half cycle. This concept allows substantially higher test loads at 0.1Hz at fairly small input power compared to the sinusoidal VLF concept. Systems with up to 25 μF @60 kV RMS are commercially available. Figure 3 shows the characteristic shape of the cosine rect- angular wave shape for 01.Hz. The polarity change follows a cosine curve and happens within a time interval (milliseconds) that is very similar to 50/60Hz.

Fig. 3: Cosine Rectangular Wave Shape at 01.Hz Fig. 1: PDIV for cables with artificially introduced faults [4] Aside from the voltage shapes discussed so far there are a number of other shapes, which might be suitable for PD diagnostics. Pepper [5] performed in depth research evaluating a triangle voltage shape and the VLF Cosine rectangular voltage shape (CR) as voltage source to conduct PD testing on solid dielectric power cables. Both voltage shapes qualified for this purpose, however the CR showed higher PD discharge levels, especially for sliding discharges

Voltage Shape VLF CR (Cosine Rectangular) The VLF CR is generated by a circuit containing a DC HV power supply U (+&-), an auxiliary capacitor C, a thyristor controlled switch S, a choke L and a toggle switch with a zero position W. Figure 2 shows the block-diagram of a VLF CR unit.

Voltage Shape DAC (Damped AC Voltage) The generation of a damped AC voltage requires pretty much the same components as described for the VLF CR technology, compare figure 2. The difference is in the switch S, which opens in the case of the VLF CR when the power supply must add additional energy to reach the full voltage in the given polarity. In case of the DAC this switch will stay closed, creating a damped resonance circuit. The resonance frequency is a function of the inductivity of the choke, the capacitance of the auxiliary capacitor and the capacitance of the cable to be tested.

Advantages of the Voltage Shape with regard to PD Diagnostics and Withstand testing The VLF CR technology has a big advantage in terms of chargeable cable capacitance and performing the poarity reversal in a time interval very close to power frequency. This makes the technology very interesting to be used as a power supply for off-line PD testing. The same 2 characteristics make the VLF CR technology a very effective tool to conduct withstand testing with or without PD testing (monitored withstand test), allowing very long cables or all 3 phases of a 3 phase circuit to be tested together at 0.1Hz.

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Maintenance Vol. 2 The DAC voltage shape cannot reach the same electrical stress within the same test duration when compared to the VLF CR. The short duration of the damped AC voltage shape would require a huge number of test cycles to match the electrical stress level for cables and accessories as provided by the VLF CR Technology. On the other side it is exactly the very short duration of the voltage stress of the DAC, which is a big advantage in the non destructive PD diagnosis.

Test Set-up PD Measurement with VLF CR The PD Measurement using the VLF CR was done with conventional coupling. Figure 5 shows the on-site test set up. No noise suppression measures like gating, windowing or hardware filtering were employed.

TEST RESULTS The test results shown below demonstrate how the VLF CR technology in combination with a PD measurement present a interesting alternative to state of the art high voltage power supplies like the VLF sinus or the DAC. The comparability of the measured parameters like PDIV and PD levels was established by comparing them to the DAC voltage shape. The DAC comparability to power frequency test data has been addressed in a substantial number of publications [4,7].

XLPE Cables with Artificial Defects Reference [6] reports on the evaluation of artificially induced weak spots using conventional and non-conventional PD coupling. Summarizing the results an artificial weak spot (sliding discharge), was clearly localized. With the help of a “Classification Map” it was possible to characterize and group the PD activity in relation to its frequency make-up and distinctively separate it from background noise and electronic noise, which was caused by the VLF CR.

Fig. 5: Test Set-up with VLF CR2.2.2 Test Circuit 1; 2.2.2 XLPE, 469m ( 1,563‘) The first test circuit had the following parameters:

Figure 4 shows the Classification Map. The “blue / 1st group” represented the noise sources from the HV power supply, the “red / 2nd group” represented the PD pulses created by the sliding discharge weak spot and the “green / 3rd group”, representing high frequency noise sources.

3

1 2

Cable Insulation

XLPE

System Voltage kV RMS

22

System Voltage kV RMS

469 (1,563)

Year of Installation

1985

Table 3 shows the most important test results, comparing the DAC to the VLF CR. Table 4 compares the result of the localization of the weak spots between DAC and VLF CR L1

Fig. 4: Test results @ 8kV with conventional coupling and without any filtering methods

Service Aged Cable Segments The following tests on 3 service aged circuits were done to show comparability between the PD results gathered with the VLF CR and the DAC. Some of the cables, which had different length, were pure XLPE sections, some mixed cable sections.

L2

L3

DAC

CR

DAC

CR

DAC

CR

PDIV kVRMS

13.2

12.0

10.8

14.0

12.0

12.0

TEmax pC (U0)

300

620

-

125

490

Table 3: PDIV, TEmax for DAC compared to VLF CR, test circuit 1

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Maintenance Vol. 2 Summarizing the results one can conclude that both methods showed the same weak spots in the cable. The location of the splices were unknown. The fact that in all 3 phases PD occurred at 125m (416‘) makes it very reasonable to place a splice at that distance. The overall PD level values were fairly low, therefore it was recommended to repeat the test in one year.

Teststrecke 2; Mixed cable, 662m (2,206‘) The second test circuit had the following parameters Cable Insulation

PILC / XLPE

System Voltage kV RMS

11

Length in m (ft)

662 (2,206‘)

Year of Installation

1960

Table 5 shows the most important test results, comparing the DAC to the VLF CR. Table 6 compares the result of the localization of the weak spots between DAC and VLF CR L1

L2

L3

DAC

CR

DAC

CR

DAC

CR

PDIV kVRMS

4.2

6.0

4.2

3.0

4.2

3.0

TEmax pC (U0)

2350

1100

600

1400

2650

9300

Table 5: Comparison of PDIV and TEmax for DAC and VLF CR, test circuit 2

Table 4: Localization of weak spots DAC compared to VLF CR test circuit 1

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Summarizing the results one can conclude that both methods identified the same weak spots in the cable.. Die The locations of the splices were not known. Because PD appeared in all 3 phases at 150m (500‘) and 430m (1,433‘), it can be safely assumed that splices were at these locations. The direct comparison between DAC and VLF CR shows some smaller differences. DAC shows the weak spot at 150m more pronounced compared to the VLF CR; for the weak spot at 430m it is just the opposite. This might be caused by the type of PD/weak spot. Most likely the splice is a transition splice, which typically can handle higher PD levels, but it still should be put on the repair list because the PD was present under operating conditions. Additionally an inspection of the near end termination of phase 3 was recommended.

Test Circuit 3; Mixed Cable, 1629m (5,430‘) The 3rd test circuit had the following parameters: Cable Insulation

PILC / XLPE

System Voltage kV RMS

11

Length in m (ft)

1629 (5,430‘)

Year of Installation

1965 / 2004

Table 7 and Table 8 show the most important test data Table 7 Comparison PDIV, TEmax for DAC and VLF CR, L1

L2

L3

DAC

CR

DAC

CR

DAC

CR

PDIV kVRMS

2.4

6.0

2.4

<3.0

2.4

<3.0

TEmax pC (U0)

9500

7400

6545

5500

14980

5000

Table 7: Comparison PDIV, TEmax for DAC and VLF CR, Test Circuit 3

Table 6: Localization of weak spots, comparison between DAC and VLF CR, test Circuit

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Maintenance Vol. 2 in over 10 years of PD field testing that it “emulates” very well 50/60Hz operating frequency and matches extremely well its PD parameters. Another advantage of the DAC is its short duration of the test voltage, promoting a non destructive PD diagnosis. On the other side it is the short duration that disqualifies the DAC from performing withstand tests. The comparative tests between DAC and VLF CR show a good correlation between the PDIV values. The PDIV is a very good parameter to characterize the risk potential of the PD, see Tables 3,5 and 7. The VLF CR shows generally slightly higher PD charge levels. Most likely they are caused by an accumulation of charges at the layered interfaces during the plateau phase of the voltage (5 seconds). This effect has a positive impact on the localization of PD weak spots with the TDR method because this allows to locate weak spots also on longer cables. The assessment of the risk potential of PD weak spots using PD limits is not or only partially possible. The type of weak spot (void; interface between the field compensation and insulation etc.), which determines in a significant way the risk potential, can be determined in special situations based on the PD patterns. Therefore more research is done with the VLF CR regarding pattern recognition. The design of the VLF CR units permits also the generation of a DAC voltage by control of the thyristor switch. The combination of VLF CR with DAC voltage generation offers the possibility to conduct a withstand test with or without a simultaneous PD test in addition to the application of the DAC for a non destructive PD Diagnostics.

REFERENCES

Table 8: Comparative localization for DAC and VLF CR, Test Circuit 3 This circuit shows a very distinct and substantial weak spot at 165m (550‘). With exception for phase 1 all PDIV values are very similar. The PD levels are also very similar at the max. test voltage. The VLF CR did also identify an additional weak spot at 590m (1,966‘). The splice at 165m was recommended for immediate replacement due to its high PD level and low PDIV. After the repair, an additional should be performed to validate the workmanship of the new splice .

DISCUSSION The PD test results obtained with the VLF CR method were benchmarked against the DAC method. The DAC has proven

1

J äverberg, N; Edin, H: Applied Voltage Frequency Dependence of Partial Discharges in Electrical Trees. Proc. IR-EEETK, Stockholm, Sweden, 2009

2

 oigt, G; Blum, D; Wolf, T; VLF-TE Messungen an betriebV sgealterten Mittelspannungskabel. R&D Project FH Konstanz, 2001/ 2002

3

 on; Importance of voltage type equivalence. VWEW Infotag E 2004

4

 olloca, V; Fara, A; Nizzi, G; de Nigris, M; Comparison C among different diagnostic systems for medium voltage cable lines. Cired 2001.

5

epper, Daniel: Grundlagenuntersuchung zum TeilentlaP dungsverhalten in kunststoffisolierten Mittelspannungskabeln bei Prüfspannungen mit variabler Frequenz und Kurvenform. Berlin: TU Berlin, 2003

6

 ötz, D.; Petzold, F.; Putter, H.: Zustandsbestimmung und G Qualitätskontrolle von Montage an Mittelspannungskabeln unter dem Aspekt zunehmend großer Kabellängen. ETG Fachtagung: Fulda, 2012

7

 ester F.J.; Condition Assessment of Power Cables UsW ing PD Diagnosis at Damped AC Voltages, PhD. thesis, TU Delft, 2004

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OPTIMIZE STATOR ENDWINDING VIBRATION MONITORING WITH IMPACT TESTING PowerTest 2014 John Letal and Vicki Warren, Qualitrol-Iris Power ABSTRACT In recent years, stator endwinding vibration has developed into a significant failure mechanism of large motors and generators. In some cases, driven by end users to reduce costs, manufacturers have used insufficient stator endwinding support. This lack of support has led to excessive motion between parts resulting in abrasive damage and high cycle copper fatigue resulting in cracked conductors. During maintenance outages, visual inspection identifying dusting, insulation fretting, and greasing are indications that endwinding vibration is present. There is an offline test, the impact test, that can determine the most “relaxed” areas of the endwinding where vibration would likely be the highest and therefore more damaging to the winding. The test itself consists of impacting a particular part of an endwinding structure with a calibrated force and measuring its overall response with a temporarily installed accelerometer. As with any offline test on electrical machinery, there are proper procedures that should be followed in order to ensure valid information. In order to avoid premature failure in the stator endwinding, excessive motion and vibration in “relaxed” areas should be monitored during operation using permanently installed accelerometers. There is a practical limit to the number of accelerometers to use and this impact test can be utilized to determine the optimal sensor locations and thus maximize the benefit of monitoring stator endwinding vibration.

force is the electromagnetic frequency at twice power frequency (100Hz/120Hz). This is generated from the magnetic fields that are produced between two parallel current-carrying conductors. The electromagnetic forces between two adjacent bars are proportional to the square of the current [2]. Harmonics of this force can occur from the power system currents that excite the stator endwindings resulting in vibration at exact multiples of this fundamental frequency. Another force on a stator endwinding during normal operation is at turning speed: 50/60 Hz for 2-pole machines and 25/30 Hz for 4-pole machines. These forces can be measured in three directions. Considering the end view of a stator these are normally specified as radial, tangential (or circumferential), and axial. Figure 1 shows the radial and tangential directions as a reference with the axial direction into the page. For the electromagnetic force the directions of most concern are radial and tangential. This is because the force is generated by two parallel current-carrying conductors, i.e. the force between the top and bottom bar (radial) and between two adjacent bars (tangential) [2]. The force in the axial direction is usually negligible.

This paper describes common problems caused by endwinding vibration, the offline “impact” or “bump” test and the online monitoring system using practical case studies for each.

BACKGROUND The stator endwinding allows for safe electrical connections between bars in series and to other parallels. These connections must be made away from the stator core to prevent insulation failure at the connection points. On higher voltage machines, the required creepage distance between the core and the connections can become quite long. Additionally, higher speed machines have long endwindings for geometric reasons, e.g. 2m or longer is not uncommon [1]. The long unsupported lengths of endwinding bars, particularly on high speed machines are susceptible to excessive motion resulting in vibration. The dynamic response of stator endwinding bars resulting in vibration can be attributed to two primary forces. The main

Fig. 1: End view of generator stator with Radial (R) and Tangential (T) directions To accommodate for these forces during operation, each bar is often lashed to a support ring made of insulated metal. The hoop strength of the support ring prevents movement in the radial direction. Insulated blocks placed between adjacent bars prevent movement in the circumferential direction. Depending on the length of the endwinding, one or more rows of blocking may be present [1]. See Figure 2 for an example of such a support system.

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Maintenance Vol. 2 mer tip surface (for an even strike), avoiding double impacts (for one strike), and ensuring enough energy is generated to excite the structure (for a solid strike). An experienced analyst will have a “calibrated” swing resulting in excellent repeatability.

Fig. 2: Stator endwinding support system: Ring, Blocks, Lashing Many system disturbances or frequent starts will create large transient forces and may accelerate the wear rate of components [1]. Age is another factor that will contribute to endwinding vibration as the insulating blocking and bracing material shrink over time loosening the endwinding support and resulting in excessive motion. Stator endwinding natural frequencies tend to decrease as the structure loosens with age and operation. As well, the structure tends to become more heavily damped resulting in the natural frequencies covering a wider range than in a new or recently repaired endwinding structure. If these changes in the endwinding natural frequencies come to influence the operating forces of a machine, the vibration will be resonant resulting in excessive vibration reducing the life of the stator endwinding structure significantly [2].

Fig. 3: Impact test setup with force hammer and accelerometer A precaution when using a force hammer is to avoid “driving the system” by over exciting or impacting too hard. This can result in frequency shifts as shown in Figure 4 where there is a 2 Hz decrease at 110 Hz. The aim of impact testing is to measure the natural frequencies of the endwinding structure itself and any changes in dynamics due to improper test procedures will result in inaccuracy.

Properly scheduled visual inspections are an important requirement to detect any evidence of excessive motion. Periodic offline tests such as impact (or bump) testing can provide an indication of how the structural characteristics of a stator endwinding change over time.

IMPACT TEST PREPARATION Purpose: To excite the natural frequencies of a stator endwinding when the machine is offline the analyst can strike the structure with a calibrated force and measure the resulting response. Many tools are readily available for these tests, but important factors need to be considered.

Force Hammer A force hammer, red tip in Figure 3, is used to excite the stator windings while the measured responses in acceleration from around the endwinding can be compared. The advantages of using a force hammer are the speed of testing, ease of setup, portability, and cost. These factors make a force hammer highly suitable for field work whereas a shaker is more suitable for lab testing. This is a comparison test so repeatable hammer strikes are required. This can be achieved by ensuring to strike with the entire ham-

Fig. 4: Frequency shift as a result of d riving the system in measurement 2 (blue)

Accelerometer An accelerometer, grey cube with black signal cable in Figure 3, is used to measure the response due to the excitation by the force hammer. Locations with higher acceleration response due to the same force can be expected to vibrate at higher amplitudes during machine operation. Considerations when selecting a sensor for this testing are type, axis, and mounting. Conventional piezoelectric accelerometers are suitable for this testing as the machine is offline and there is no risk of compromising electrical clearances with metallic components in a high voltage area that is found during machine operation. The frequency range of the accelerometer is governed by the natural frequency of the sensor itself. Generally, the smaller the physical size of the sensor, the higher the natural frequency. Considering we are

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Maintenance Vol. 2 locating frequencies in the few hundred Hz range, general purpose accelerometers with maximum frequency ranges of a few kHz or more are suitable and readily available.

magnitude approaches a maximum and; 2) a phase shift crosses through 90° [3]. To identify natural frequencies these observations can be determined with impact testing. See Figure 5.

Single axis accelerometers are easier to work with, but tri-axial accelerometers provide more information by collecting data in 3 directions simultaneously. Because we are interested in natural frequencies in the radial and tangential directions in stator endwindings, this decision becomes a balance of time (more time with single axis) and bookkeeping (more data with tri-axial). Poor mounting techniques of the accelerometer can result in poor results. The main requirement is for close mechanical contact between the accelerometer and the surface to which it is being attached. This will ensure the excitation forces are completely transmitted from the component surface to the accelerometer. Additionally, the response from the accelerometer’s natural frequency should not be measured within the endwinding structure natural frequency range. The type of sensor mount affects the accelerometer’s natural frequency. The more rigid (stiff) the mount, the closer the measured natural frequency will be to the accelerometer calibrated value. This can be achieved by stud or cement mounting; however, general purpose accelerometers typically have a natural frequency in the 5-10 kHz which far exceeds the frequency range of interest for stator endwinding impact testing. With this in mind, a more practical mount for stator endwinding testing is beeswax. Even though wax results in a reduced usable frequency range the frequencies of interested are in the few hundred Hz range and still well within the usable range of a wax mounted general purpose accelerometer. Wax provides a quick mount on a variety of surfaces. The cleaner the surface the better the wax will stick. The only practical consideration is at higher temperatures (e.g. >100°F) the wax can sometimes become soft and not stick.

TEST PROCEDURES The goal of impact testing is to establish a dynamic signature for the structure by doing Fourier analysis. There are two impact test procedures that can be used to establish the natural structural characteristics of a stator endwinding structure: Driving Point and Modal Analysis.

Fig. 5: Natural frequency example The critical bands for a motor or turbine generator are around rotational speed frequency and twice line frequency. Therefore, applied forces in the endwinding structure of a 2-pole, 50/60 Hz generator are at rotor rotational frequency, 50/60 Hz and at alternating load current electromagnetic forces, 100/120Hz. The concept of critical band refers to the risk of vibration amplification when the structure natural frequencies are close to the forcing frequencies. In service, the natural frequencies may drift in the bands due to temperature, aging and other variable factors. Thus, an acceptance band should be defined with these factors in mind. The acceptance criteria are based on the magnitude of the acceleration over force through the critical excitation bands. The impact test should not be considered as a stand-alone test or replacement to a Modal analysis test.

Modal Analysis Modal analysis consists of measuring motion at various points of a structure when it is excited by some driving force. The pattern of motion usually takes certain shapes which are related to the natural frequencies or natural motion tendencies of the structure. This provides a definitive description of structural characteristics through curve fitting techniques to generate a shape table that closely represents the dynamics of a structure.

In the Driving Point test, the force hammer and the accelerometer are at the same measurement location, as shown in Figure 3. The measurement location is regarded as where the maximum deflection signals can be obtained and selected by the analyst. The result is a measured response at the excitation point or frequency response function (FRF). This transfer function is expressed in the frequency domain. [3]

Modal analysis assumes the structure is linear. This means that the response will be proportional to the input force. This can be checked by performing a driving point test with different sizes of force hammers and obtaining the same FRF. As well, modal analysis assumes that the test is time invariant; the parameters are constant during the test. Ambient and winding temperature should be recorded through impact testing and not fluctuate significantly. Finally, modal analysis assumes passivity. To ensure that all response is due to the measured forces, it is best to perform impact testing when background/operational forces are a minimum.

The phase will be between 0 and 180 degrees or 180 and 360 degrees and be ~90 degrees at a natural frequency. Two observations are required to identify a natural frequency. As a driving frequency approaches an undamped natural frequency, 1) the

An endwinding structure can be modeled with a circular ring. When the structure takes certain shapes at similar frequencies to a force, the resonant condition amplifies the vibration on an endwinding. For a 2-pole machine the shape for twice supply

Driving Point

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frequency deflection is oval. This shape is not the only mode that can be excited by forces within the rotating machine. Other modes such as cantilever modes (the whole endwinding bouncing up and down) or breathing modes (expanding and shrinking diametrically) could also become resonant if forces act on the winding in the critical directions and at the critical frequencies. However, the oval mode shape in Figure 6, for 2-pole machines is the most critical for vibration analysis of the stator because it naturally gets driven by the rotor forces if the resonant frequencies are close to the rotor forcing frequencies. For reliable operation of rotating machines, it is critical that natural frequencies for the mode shapes into which the endwinding can be deformed are far away from the driving frequencies (120 Hz).

Fig. 6: Critical mode shape for 2-pole machine When performing modal analysis, enough points must be measured to resolve the mode shape of interest. In general, for 2-pole machines 12 points are sufficient to define the oval mode shape, but for slower machines more points are required to define the appropriate mode shapes. The 24 points used to collect Figure 6 offer more resolution.

CASE STUDIES Case Study 1 – Temperature Effects on Stator Endwinding Natural Frequencies Structural characteristics change with age resulting in a decrease to the natural frequencies and heavier damping. This effect is similar when the temperature of a stator endwinding structure increases. This is an important consideration when using offline impact testing which is generally performed at a much lower temperature than operation. As winding temperatures increase, the stiffness of the endwinding structure decreases [2]. The standard undamped natural frequency (fn) relation is:

Where k is stiffness and m is mass.

From this equation it can be seen that a decrease in stiffness results in a decrease in the natural frequencies of the structure [2]. If a vibration component is influenced by a natural frequency, the response (or vibration amplitude) will be affected by a change in winding temperature. Because of the inverse relationship between winding temperature and natural frequency, an increase in temperature to a system that is low tuned (meaning the natural frequency is below the forcing frequency) may decrease the vibration amplitude because the natural frequency moves further away from the forcing frequency and influences it less, if at all. This is the ideal condition for critical mode shapes. Conversely, a high tuned system (meaning the natural frequency is above the forcing frequency) may increase in vibration amplitude with an increase in winding temperature as the natural frequency decreases and moves into the forcing frequency and influences it more. This frequency shift can be quite dramatic at higher temperatures as the elastic quantity for epoxy mica insulation decreases significantly when the winding temperature is beyond a transition temperature of around 80°C [5]. This was demonstrated experimentally [6] in which mode shape tables were produced from impact data collected on stator endwindings in cold, warm, and hot conditions. Mode

Cold (24°C)

Warm (60-58°C)

Hot (90-82°C)

Frequency change (from Cold to Hot)

n=2

104.36

101.28

93.32

11.04

n=31

122.03

118.26

110.93

11.10

n=32

127.01

124.15

116.25

10.76

n=41

162.16

155.96

148.60

13.56

n=42

166.78

161.73

153.44

13.64

Table 1: Connection end mode shape frequency [6] This experimental data indicates that even though the mode shape frequencies measured were affected by the temperature of the windings, the mode shapes themselves were not. Figure 7 displays the oval mode shape in the cold and the hot conditions overlaid. The frequencies decreased with temperature by more than 10 Hz [6]. This is important when establishing the condition of stator endwindings with offline testing. Generally, a 10% band can be used to cover for the dampening effect of natural frequencies, but a wider band may be necessary to account for temperature, as shown in this experiment.

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The resulting online acceleration data in Figure 9 showed dominant peaks at 120 Hz from the electromagnetic force with multiples at 240 and 360 Hz. Harmonics are generally expected to decay linearly if not influenced by resonance as the force dissipates out of the system, as is the case for this machine. Note that because the offline natural frequency from Figure 8 was not within the forcing frequency range, then it does NOT go into resonance when online, so is not visible in Figure 9.

Fig. 7: Oval mode shape in hot and cold condition overlaid [6]

Case Study 2 – Stator Endwinding Vibration and Impact Testing It is impractical to monitor every component of a stator endwinding and some care is required to identify the optimal locations. Once the locations for monitoring have been properly identified, the offline impact test data can indicate the resulting frequency content and relative amplitudes of the online vibration data. It is widely considered that the connections are the most important locations to monitor endwinding vibration. They are generally more massive and the long unsupported lengths increase the likelihood for resonance and high vibration amplitudes. Figure 8 shows offline impact test data on a connection that identified a natural frequency around 320 Hz (lower than a harmonic of the forcing frequency of 360Hz). The two characteristics can be identified near this frequency; high magnitude, 0.015 g/N in the lower plot and phase shift crosses through 90° in the upper plot. From Case Study 1, these natural frequencies are expected to shift down at operating temperatures. This 60 Hz machine has primary forces at 60 and 120 Hz, as well as power frequency harmonics in harmonics of 120 Hz. The natural frequency identified is not expected to influence these forces and harmonics significantly.

Fig. 8: Offline impact data connection

Fig. 9: Online vibration response connection

Case Study 3 – Stator Endwinding Harmonic Vibration and Impact Testing Figure 10 shows offline impact test data collected on a winding bar on the same machine as above in Case Study 2. The test identified natural frequencies near 211 and 392 Hz. Again, the two characteristics can be identified near 211 Hz frequency; high magnitude, 0.011 g/N in the lower plot and phase shift crosses through 90° in the upper plot. The natural frequency near 392 Hz has high magnitude, 0.020 g/N in the lower plot and phase shift crosses through 90° in the upper plot (higher than the harmonic forcing frequency of 360 Hz).

Fig. 10: Offline impact data winding The resulting online acceleration data in Figure 11 showed dominant peaks at 120 Hz from electromagnetic force with multiples at 240 and 360 Hz. Because these harmonics are influenced by a natural frequency, they do not decay linearly as seen on the connection in Case Study 2. The high amplitude at 360 Hz is due to a resonant response. The system at this winding location is approximately eight times more responsive at 360 Hz than at 240 Hz and the online vibration data behavior showed this correlation.

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Maintenance Vol. 2 REFERENCES 1. G.C. Stone, E.A. Boulter, I. Culbert, et al. Electrical Insulation for Rotating Machines. Hoboken NJ: Wiley, 2004, pp. 29-30, 172-174. 2. H.O. Ponce, B. Gott, G. Stone, Generator Stator Endwinding Vibration Guide: Tutorial, EPRI, 2011. Project Evaluation No 6382.

Fig. 11: Online vibration response winding The driving frequency (electromagnetic force) at 120 Hz is similar at both locations. This is readily apparent by comparing response amplitudes, 0.6 g pk on the connection and 0.7 g pk on the winding, and considering there is minor sensitivity from the impact test data at both locations. The vibration amplitude at 360 Hz is significantly greater on the winding compared to the connection due to a local natural frequency identified on the winding that is influencing this response. This demonstrates the importance of impact testing to determine the optimal locations. High sensitivity measured with offline testing in critical frequency bands should be considered for online vibration monitoring as these are the locations that are most likely to vibrate. The data presented shows that even though the connections are generally considered the critical components for monitoring vibration, the windings are a more suitable sensor location for this particular.

CONCLUSION Stator endwinding vibration has developed into a significant failure mechanism attributed partly to the efforts by manufacturers driven by end users to reduce costs and additionally, on load cycling machines, with demand fluctuations. Consequently machines are being operated with insufficient stator endwinding support leading to excessive motion between parts and ultimately cracked conductors due to high cycle copper fatigue. In order to avoid premature failure, this excessive motion during operation should be monitored and repaired. As shown by the case studies in this paper, an effective online monitoring system requires the sensors to be installed at locations most likely to vibrate. Impact testing is an offline test that can be used to assess whether stator endwindings are likely to vibrate in resonance with operational forces and optimize the location of the accelerometers for monitoring. When performing any offline test on electrical machinery it is important to choose the right tools for the job. For impact testing a calibrated force hammer is used to measure the excitation input and an accelerometer is used to measure the response output. Appropriate practices should be implemented when collecting data. Avoid frequency shifts from mounting errors to ensure good correlation between the force hammer and the accelerometer.

3. Inman, D.J. Engineering Vibration. 2nd Ed. Upper Saddle River, NJ: Prentice Hall, 2001, pp. 102-106, 508-509. 4 Hewlett-Packard, Appl. Note 243, pp.34-39. 5. A. Jarosz, A. Foggia, J. Adam, et al. Mechanical behavior of hydrogenerator endwindings, in Proc. IEEE-IEMDC, 1999, pp. 308-310. 6. M. Sasic, H. Jiang, G.C. Stone. Requirements for Fiber Optic Sensors for Stator Endwinding Vibration Monitoring, in Proc. IEEE-CMD, 2012, pp. 118-121. John Letal is a rotating machines engineer at Iris Power responsible for supporting rotating machine mechanical monitoring initiatives including stator endwinding vibration. Prior to Iris, he spent most of his career as a field service engineer troubleshooting large rotating equipment using such tools as vibration analysis, force response measurements, and modal analysis. He was also involved in the implementation and execution of vibration analysis programs. John holds a Bachelor of Science degree in Manufacturing Engineering from the University of Calgary and is registered as a professional engineer. Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in mediumto high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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Maintenance Vol. 2

PROCESS ANALYSIS – YOUR PATH TO SYSTEM KNOWLEDGE PowerTest 2014 Noah Bethel. CMRP, PdMA Corporation Process Analysis as a baseline recording from each motor involved in our system processes provides the eyes and ears necessary to easily see the onset of reduced reliability. How well do you know your system process? Could you identify the reason behind every precision variation in load of each of the motors throughout your system operations? If you answered Good to the first question but No to the second question then you are in the majority. The majority of maintenance professionals who are not taking advantage of the built in reliability sensors we call the electric motor.

ELECTRICAL TO MECHANICAL TO ELECTRICAL The electric motor takes electrical energy and creates an invisible rotating magnetic field in the stator windings. This rotating magnetic field induces, or causes current and subsequent magnetic fields on the rotor. These two magnetic fields, like magnets over and under a table, will attract and repel to create torque that turns the shaft of the motor creating mechanical energy. This mechanical energy delivered to various processes throughout your system in turn provides feedback through the motor in the form of electrical energy. Variations in torque caused by load changes or mechanical faults will modulate the rotation of the rotor on which the induced magnetic field exists. This change in the rotating magnetic field will in turn modulate or change the invisible rotating magnetic field on the stator, thereby providing intelligence into the unseen inner workings of your system processes.

QUANTITATIVE PROCESS ANALYSIS There are times where precision analysis of current values taken from a motor during a transient or process can identify a variety of issues. Starting a motor may be one of the most stressful transients that a motor experiences during normal operations. That being said it is common knowledge that performance and reliability may be best verified under a stressful condition. And, if a stressful condition is required (a motor can’t work if it can’t start) then what better opportunity to use that stressful condition to perform some assessment on the reliability of the motor.

Fig. 1: Normal In-Rush/Start-Up of a squirrel cage induction motor Figure 1 presents a fairly classic display of an across-the-line standard squirrel cage AC induction motor. Notice the rapid inrush to 289 amps followed by a steady decrease in current through the beginning of the start-up and a quick drop to a steady state at the end of the start-up in approximately 3.2 seconds. These are quantitative values of current that can establish a healthy baseline and be used to compare to future values of acquired current for trending.

QUALITATIVE PROCESS ANALYSIS In addition to the quantitative side of data analysis there is the equally powerful but sometimes underrated qualitative analysis. Where quantitative analysis focuses on defined values to compare to a baseline or previous test, qualitative analysis uses more of a characteristic recognition or change as it applies to a process. Compared to Figure 1, notice the uncharacteristic start-up seen in Figure 2 for a motor used on a similar application. Ignoring the values, the initial magnetizing in-rush doesn’t act so different but the start-up current is very different. Rather than a smooth gradual reduction of current through a three second start-up, a large amount of hunting or modulating is displayed over a 16 second start-up. Unlikely a product of the mechanical process, we must suspect that variations in rotating electrical impedance might be the source. And, where better to find varying rotating impedance than on the rotor cage?

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There is an advantage beyond the use of current analysis towards the reliability assessment of the motor. As discussed in the paragraphs above, intelligence into the application (pump, compressor, etc.) and the process itself (boiler feed, condensation, lube oil, etc.) can be extracted from the current data taken on a motor.

Fig. 5: Current demodulation showing vane pass and speed frequencies for comparison to Figure 4

Fig. 2: In-Rush/Start-Up of squirrel cage induction motor showing hunting throughout the start-up Figures 4 and 5 are a quantitative comparison between two identical horizontal pumps. Figure 4 is typical for this application with the pump vane frequency amplitude of 0.027 dB. In Figure 5, pump PF-8.6A pump vane frequency amplitude is 0.046 dB; nearly double that of all the other identical equipment platforms. Additional testing and a scheduled inspection of the impellor are recommended, given the substantial difference in these vane pass frequencies.

Figures 6 and 7 are qualitative comparisons of data taken on the same circulating water pump at different times. This pump was being powered by a 4000v, 3000HP AC induction motor. So, not only is there interest in the very expensive motor, but additionally in the pump responsible for critical circulating water to the utility plant. The data in Figure 6 was taken in January, 2010, during a routine process analysis current test. Recognizing that the normal qualitative performance of a centrifugal pump under the proper head pressure and normal load would be a steady state demand the process capture in Figure 6 is very uncharacteristic.

Fig. 6: Qualitative current RMS envelope from a circulating water pump motor trended with Figure 7 Taking the immediate steps to use this data in comparison to running characteristics of previous data from 18 months prior on the same pump you can see a dramatic difference in Figure 7.

Fig. 3: Centrifugal Pump

Fig. 4: Current demodulation showing vane pass and speed frequencies for comparison to Figure 5

With no complaints from operations on the circ-water pump performance, no further investigation would have been made. However, given the simple qualitative analysis on the process current test and the fact that utility requirements were not at peak demand, a visual inspection was authorized. As can be seen in Figure 8 this pump could have experienced a potentially catastrophic failure that would have resulted in a reduction in the unit capacity. Had a catastrophic failure occurred in the middle of the summer when utility demand is high, well… “It’s all about the MegaWatts” as we have heard from our utility customers. Figure 8 shows that the inlet bell has been broken. This could create the possibility of turbulent flow, which could cause cavitation in the pump and intermittent load variations as seen in Figure 6. Additional concern would be toward the possibility of the broken pieces of the inlet bell entering the pump cavity and causing impellar damage.

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acquired with the expected amplitudes and times associated with each event it can be easily compared to follow-up tests. Overlaying two process analysis tests will easily identify which event is seeing a change.

Fig. 7: Qualitative current RMS envelope from a circulating water pump motor trended with Figure 6

Imagine how much easier it would be to isolate the fault if you had trendable process analysis timelines to show you the way. Its kind of like having a built in sensor for every application. Process Analysis as a baseline recording from each motor involved in our system processes provides the eyes and ears necessary to easily see the onset of reduced reliability.

The same qualitative and quantitative approach described by this pump case study can be applied to belts, fans, compressors, etc. Keep in mind the approach to using electric power as a sensor to identify mechanical anomalies is correlative. We are not expecting current signature to take a lead role in mechanical analysis as that position should always be dominated by the vibration analysis industry. However, the power to correlate and provide another means of identifying mechanical anomalies is unquestionable. Fig. 9: Process analysis of servo motor application

Noah Bethel, CMRP, is vice president of product development for PdMA Corporation, Tampa, Fla., a leader in the field of predictive maintenance, condition monitoring applications, and development of electric motor test equipment for motor circuit analysis. Tel: (800) 476-6463 or visit www.pdma.com.

Fig. 8: Damaged inlet bell on circ water pump

PROCESS ANALYSIS We have discussed the application of current analysis towards the identification of mechanical anomalies. Building on the electrical to mechanical to electrical transition discussed in paragraph two, we can use the current trace seen in the RMS enveloped In-Rush/Start-Up test to provide time and amplitude sensitive information toward the process being driven by the motor. Take the example of a servo driven robotics application in the automotive industry seen in figure 9. Every transient can be linked to an event, a transfer, a move of an object between one place to another. There are six main events throughout the operation of this process that can be easily identified with some basic visual feedback and knowledge of the process. In Figure 9 the first event starts with a 36 amp signal that lasts for 1.5 seconds followed by a rapid 45 amp second event. After the six events the whole process starts over every 30 seconds. Once a baseline has been

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UNITED STATES

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alabama 1

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

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arizona

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

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ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

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ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

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Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

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Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

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Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

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Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

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Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

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Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

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Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

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RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

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Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

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Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

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RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

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CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

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CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

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Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

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Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

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Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

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High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

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Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

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Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

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florida 50

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C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

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ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

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CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

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Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

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Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

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High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

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Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

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Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

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Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

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Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

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Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

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Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

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Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

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Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

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POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

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ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

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Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

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High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

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Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

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High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

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Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

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missouri 114

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116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

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143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

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new york 139

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141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

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152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

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148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

182

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189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

VOLUME 3

MAINTENANCE Vol. 3 HANDBOOK

SERIES III

HANDBOOK

Published By

MAINTENANCE

SERIES III

MAINTENANCE VOL. 3 HANDBOOK

Published by

InterNational Electrical Testing Association

MAINTENANCE VOL. 3 HANDBOOK TABLE OF CONTENTS Testing Rotating Machinery Insulation Resistance Test............................................. 5 Vicki Warren

Modern Testing and Diagnosis of Power Cables Using Damped AC Voltages............ 7 Edward Gulski, Rogier Jongen, Ralph Patterson

Improving Reliability Beyond Compliance........................................................... 14 Karl Zimmerman

Battery Discharge Testing: Implementing NERC Standard and Field Experiences...... 18 Dinesh Chhajer and Robert Foster

How to Maintain Station Batteries...................................................................... 23 Tom Sandri

NERC Requirements for Substation DC Supply Systems......................................... 27 Lynn Hamrick

On-line Partial Discharge Testing: Introduction to Detection and Analysis of Electromagnetic and Acoustic Partial Discharge Signals....................... 31 Louis Nemec

The Trillion-Dollar Cable Question...................................................................... 36 Alan Mark Franks

Lessons Learned From a 400Kv Busbar Misoperation Using the IEC 61850 Standard......................................................................... 39 Dhanabal Mani, Vijay Shanmugasundaram, Jason Bueno

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InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Understanding and Maintaining Critical Service Equipment.................................. 44 John Weber

Go Green or Go Home.................................................................................... 49 Noah Bethel

The Trifecta of Motor Maintenance.................................................................... 52 Noah Bethel

Designs, Methods and Limitations for Test Isolation Devices................................... 55 Scott L. Short

Gaps in Your Electric Motor Reliability Program................................................... 66 Noah Bethel

System Testing of Protection Devices and Schemes – What is it and Why Do We Need It?................................................................. 67 Alexander Apostolov and Will Knapek

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

269.488.6382

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Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

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Maintenance Vol. 3

TESTING ROTATING MACHINERY – INSULATION RESISTANCE TEST NETA World, Spring 2015 Issue Vicki Warren, Senior Product Engineer, Iris Power LP

The insulation-resistance test [IEEE Std. 43-2013] is a useful indicator of contamination (Figure 1) and moisture on the exposed insulation surfaces of a stator winding, salient pole or cylindrical rotor windings, especially when there are cracks or fissures in the insulation. The test is easily done and is one of the most common tests performed on any motor or generator winding. Since squirrel cage induction motor rotor windings are not insulated, this test is not appropriate for such motors.

the insulation are present.” From Section 6.3.1, in metals the free electrons at higher temperatures increase thermal agitation and thus increase resistivity; whereas, in insulators the higher thermal agitation frees electrons and decreases resistivity. The result is that the expected results of insulation-resistance will decrease at higher temperatures. Since the recommended values are all at 40°C, then different recommended values are necessary when the test specimen is at different temperatures. Table 1 below shows the recommended minimum insulationresistances temperature corrected as defined by IEEE 43-2013 (Sec 12.3).

Fig. 1: An example of a contaminated winding The insulation-resistance and/or the polarization index test should be done prior to application of any high voltage tests to assure that the winding is not wet or dirty enough to pose a risk of failure that could be averted by a cleaning and drying-out procedure. However, insulation-resistance testing is principally a pass/ fail criterion and cannot be relied upon to predict the condition of the main insulation except when the insulation has already faulted. That is, since the insulation-resistance test is insensitive to internal insulation problems; a high insulation-resistance reading does not imply that the winding is in good condition. See Fall 2011 NetaWorld issue for more information about the insulation-resistance test theory and test configuration.

TEMPERATURE CORRECTION IEEE 43-2013 (Sec 6.2), the insulation-resistance can vary inversely, on an exponential basis, with the winding temperature. “Regardless of the cleanliness of the winding surface, if the winding temperature is at or below the dew point of the ambient air, a film of moisture may form on the insulation surface, which can lower the insulation-resistance or polarization index. The effect is more pronounced if the surface is also contaminated, or if cracks in

Minimum Insulation-Resistance

Test Specimen

IR1min = kV + 1

For most windings made before about 1970, all field windings, and others not described below.

IR1min = 100

For most ac windings built after about 1970 (form-wound coils).

IR1min = 5

For most machines with random wound stator coils and formwound coils rated below 1 kV and dc armatures.

Table 1: Recommended minimum insulation-resistance values at 40°C (All values in MΩ) Notes from IEEE 43-2013 (Sec. 12.3) regarding Table 1: ●● IR1min is the recommended insulation-resistance, in megohms, at 40°C of the entire machine winding (all phases). Tests on individual phases would be expected to be twice the above values. ●● kV is the rated line-to-line voltage for three-phase ac machines, line-to-ground voltage for single-phase machines, and rated direct voltage for dc machines or field windings. ●● It may not be possible to obtain the above minimum IR1 min values for stator windings having extremely large end arm surface areas, or for dc armature windings with commutators. For such windings, trending of historical IR1 min values can be used to help evaluate the condition of their insulation. ●● The values in Table 1 may not be applicable, in some cases, specifically when the complete winding overhang is treated with grading material. ●● The values in the above table do not apply to green windings before global vacuum impregnation treatment.

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Maintenance Vol. 3

In order to avoid the effects of temperature in trend analysis, subsequent tests should be conducted when the winding is near the same temperature as the previous test. However, if the winding temperature cannot be controlled from one test time to another, it is recommended that all insulation test values be compared to acceptance values corrected to a common base temperature of 40 °C. Though this corrected value is an approximation, this permits a more meaningful comparison of insulation-resistance values obtained at different temperatures. [Table 2 and Table 3 derived from IEEE 43-2013 (Sec 6.3.3 and Sec 12.3)] Note: The tables below are an approximation and could lead to significant errors if used to evaluate insulation-resistance at temperatures outside the range from 20 to 60oC (shown in grey below). These values might also lead to error with windings affected by moisture and dust.

AC windings T (°C) (form-wound)

Form Wound Random< 1kV wound DC Armatures

Field Windings (kV+1) * Value

10

143

7

7

(kV+1) / 0.7

20

125

6

6

(kV+1) / 0.8

30

111

6

6

(kV+1) / 0.9

40

100

5

5

(kV+1) / 1.0

50

67

3

3

(kV+1) / 1.5

60

43

2

2

(kV+1) / 2.3

70

30

2

2

(kV+1) / 3.3

80

22

1

1

(kV+1) / 4.6

Table 2: Recommended minimum insulation-resistance for THERMOSETTING insulation stator winding systems built after about 1970 (All values in MΩ).

T (°C)

All windings

10

(kV+1) / 0.125

20

(kV+1) / 0.25

30

(kV+1) / 0.5

40

(kV+1)/ 1

50

(kV+1) / 2

60

(kV+1) / 4

70

(kV+1) / 8

80

(kV+1) / 16

Multiply the value in column 2 by kV + 1 where kV is the rated line-to-line voltage for three-phase ac machines, line-to-ground voltage for single-phase machines, and rated direct voltage for dc machines or field windings.

Table 3: Recommended minimum insulation-resistance for THERMOPLASTIC insulation stator winding systems built before about 1970 (All values in MΩ).

TREND Trend analysis is often ambiguous, since moisture contamination normally lowers the insulation-resistance and/or polarization index readings. As long as the insulation-resistance remains fairly

level, the insulation system is in good condition. High humidity can cause resistance values to drop, so lower resistance readings on one test do not always mean the insulation is beginning to deteriorate. (For this reason it is a good idea to record humidity readings for each test.) If resistance drops for two or three successive tests (maintaining the same test interval), the winding should be cleaned, dried and tested again. If the resistance does not increase, the machine should be rewound. It is difficult to predict the effect of moisture condensation on the surface if testing below the dew point; therefore, an attempt to trend these values would introduce an unacceptable error. In such cases, it is recommended that the history of the machine tested under similar conditions be the predominant factor in determining suitability for return to service.

FAILED TESTS When machines are tested that have been out-of-service and when the winding temperature is below the dew point, the resultant values may be considered too low. These machines may need to be cleaned and/or dried out to meet expected levels. The history of the machine should help to determine the potential risk for returning a failed winding to service; however, further high-voltage testing is not recommended for such. Note that the effects of moisture contamination on a healthy winding should not preclude obtaining acceptable readings.

ENDNOTES IEEE std. 43-2013, IEEE Recommended Practice for Testing Insulation-Resistance of Rotating Machinery i

Ms. Vicki Warren, Senior Product Engineer, Iris Power LP. Ms. Warren is an Electrical Engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Ms. Warren has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium to high voltage rotating machines, switchgear and transformers. Additionally, Ms. Warren has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Ms. Warren also actively participated in the development of multiple IEEE standards and guides, and was Chair of the IEEE 43-2000 Working Group.

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Maintenance Vol. 3

MODERN TESTING AND DIAGNOSIS OF POWER CABLES USING DAMPED AC VOLTAGES NETA World, Spring 2015 Issue Edward Gulski and Rogier Jongen, Onsite HV Solutions AG, Switzerland and Ralph Patterson, Power Products & Solutions LLC, United States Modern on-site testing and diagnosis of power cables up to 230 kV consists of voltage testing, partial discharge detection, and dissipation factor measurements. Since the last 10 years, in a ddition to continuous ac or VLF energizing, the use of damped ac energizing is getting more and more worldwide attention. Having in mind the forthcoming IEEE 400.4 guide for the use of damped ac testing in this paper the application of damped ac voltages for on-site testing and diagnosis of underground power cables up to 230 kV will be presented.

Most failures occur as a result of localized electrical stresses that are higher than the dielectric strength of the dielectric materials in the area of the localized stress or if the bulk dielectric material degrades to the point where it cannot withstand the applied voltage. To find these defects prior to a failure, on-site tests, as shown in Figure 2, are applied to assess the quality and cable system integrity as well as the availability and reliability of the cable circuit.

Insulation failure of a power cable can occur as a result of the normal operational voltage or during a transient voltage due to lightning or switching surges. Examples of failures are shown in Figure 1. Fig. 2: Example of on-site testing using sinusoidal damped ac voltages (a) diagnostic testing by damped ac system 30 kV of a 3 km long 10 kV XLPE insulated cable; (b) after-laying testing by a damped ac 190 kV system of a 12 km long 110 kV XLPE cable; (c) after-laying testing by a damped ac 270 kV system of a 6 km long 150 kV XLPE cable In relation to the applied damped ac testing procedures, the IEEE 400.4: Guide for Field-Testing of Shielded Power Cable Systems Rated 5 kV and above with Damped Alternating Current Voltage (Damped ac), document is under balloting. This guide includes practical considerations, based on user experience during the last 10 years in relation to several IEC standards. Examples of such considerations include the number of damped ac excitations applied during testing and the minimum recommended test voltage level. User feedback has confirmed the following test parameters: Fig. 1: Examples of insulation defects in power cables: Distribution cables: (a) bad positioning of field grading; (b) large crack in the center of an epoxy resin joint; (c) interfacial problems in a termination; (d) connector sharp edges inside mass insulated cable termination; Transmission cables: (e) termination of 132 kV XLPE cable with unsealed bottom resulting in contamination and moisture ingress in side insulator; (f, h) cable movement due to expansion of oil due to high temperatures, directly resulting in cracks and voids in joint insulation with final breakdown; (g) electrical treeing in 150 kV gas pressure cables resulting in long term insulation degradation and finally cable breakdown

●● Maximum damped ac test voltage levels: ○○ For MV cables (6-35 kV) up to 2.0 Uₒ (Uₒ is the rated phase to ground voltage) ○○ For HV cables (36-150 kV) up to 1.73 – 2.0 Uₒ ○○ For EHV cables (150-230 kV) up to 1.4 – 1.7 Uₒ ●● Number of damped ac excitations at maximum applied damped ac voltage withstand level: 50. In this paper, the use of damped sinusoidal ac voltages (damped ac) for monitored testing of power cables will be discussed based on general considerations and practical examples.

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Maintenance Vol. 3

Fig. 3: General overview of damped ac (DAC) field test possibilities for different testing goals of cable systems [IEEE 400.4/ D8 under balloting]

ON-SITE ENERGIZING METHOD AT DAMPED AC VOLTAGES Damped ac testing can be used as a simple withstand test or in combination with partial discharge (PD) and dissipation factor (DF) measurements for new installed and service-aged cables, Figure 3. The use of damped ac voltages for testing power cables is in compliance with relevant IEC, IEEE, and Cigre international standards and guidelines. To generate damped ac voltages with durations of a few tens of cycles of ac voltage at frequencies up to a few hundreds of Hz, a test system has been developed. This method is used to energize and to test on-site power cables with sinusoidal ac frequencies. The system consists of a digitally controlled high voltage power supply to energize capacitive load of power cables with large capacitance (e.g., 10 µF), Figure 6. With this method, the cable under test is energized during a time tcharge=Umax Ccable/Iload with continuously increasing voltage, see Figure 4. During this phase the test object is stressed with an increasing unipolar voltage. The energizing time depends on the maximum available load current of the voltage supply, the test voltage, and the capacitance of the test object. As a result, due to ac field distribution, dc stress, steady-state condition, and space charges are not applied to the test object, and the damped ac stress as applied to the test object can be considered as similar to factory testing conditions.

Fig. 4: Schematic overview of one damped ac excitation. The maximum damped ac voltage level is determined by the voltage peak values (Vdamped ac) and respective RMS-values (Vdamped ac/√2) of the 1st damped ac cycle.

Fig. 5: Schematic overview of withstand test by damped sinusoidal ac voltage excitations. The duration of the test is determined by the number of damped ac excitations which are applied to the power cable at a selected damped ac test voltage. The maximum damped ac withstand voltage level is determined by the voltage peak values Vdamped ac and respective rms-values Vdamped ac/√2 of the first damped cycle At maximum selected test voltage, a specially designed solid-state switch connects an air-core inductor to the cable sample in a closing time of <1ms. Due to relatively low cable inductance, no transient overvoltages will occur in the test object. At this moment, the series of ac voltage cycles starts with the resonance frequency of the circuit fdamped ac= 1/(2Π√(L × Ccable)) where L represents the fixed inductance of the air core and Ccable represents the capacitance of the cable sample, Figure 6. The air core inductor has a low loss factor and design, resulting in a slowly decaying ac waveform of test voltage applied to the cable sample. During a number of ac voltage cycles, the PD signals are initiated in a way similar to 50(60) Hz inception conditions. This procedure can be repeated for multiple excitations followed after each other to perform a voltage withstand test as shown in Figure 5. The DF can be measured with the decay characteristics of the damped ac voltage wave and the evaluation of the DF can be especially valuable for finding insulation ageing development in paper-oil insulated cables.

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Maintenance Vol. 3

Fig. 6: Schematic diagram of damped ac (DAC) systems for on-site testing and PD detection of distribution and transmission power cables

DAMPED AC VOLTAGE WITHSTAND TESTING The application of withstand tests can be divided into two classes: ●● Unmonitored damped ac hold test: a number of damped ac excitations is applied and the ability to hold the maximum damped ac voltage (i.e., no breakdown occurs) is recorded as seen by the black dotted lines in Figures 7a and 7b. The intent of a simple damped ac withstand test is to cause weak points in the cable insulation to fail during voltage application (with minimal fault current) at a time when the impact of the failure is low (no systems or customers affected) and repairs can be made more cost effectively. If a failure occurs during the test, see the vertical dotted line in Figure 7c breakdown, then the failure should be located through a fault location process and repaired and the circuit retested. The results of these tests are described as either pass or fail. ●● Monitored damped ac hold test: a number of damped ac excitations are applied and one or more additional attributes are measured and used to determine whether the cable passes or fails the damped ac test. In the graphs in Figure 7, the black dotted lines represent the applied damped ac voltage and the grey dotted lines represent the PD detection. Due to additional information as provided by PD detection, the monitoring insulation properties during a damped ac withstand test, and the effect of the test voltage during its application can improve the evaluation of the insulation condition. The applied maximum test voltage levels for voltage withstand testing of newly installed cables are given in Table 1.

Fig. 7: Schematic overview of three different situations of damped ac (DAC) voltage withstand test: (a, b) during selected number of Ndamped ac excitations (black dotted lines) no breakdown has occurred and alternatively above the PD background noise PD has been observed or not (grey dotted lines); (c) before the selected number of Ndamped ac excitations for the damped ac withstand test has been applied breakdown has occurred, and above the PD background noise PD has been observed

Power cable rated voltage U [kV] phase-to-phase

U0 [kV]

Damped ac test voltage level V T [kVpeak] phase-to-ground

3 6 10 15 20 25 30 35 45-47 60-69 110-115 132-138 150-161 220-230

3 4 6 9 12 15 18 21 26 35 64 77 87 127

6 12 17 26 34 43 51 60 74 99 181 187 212 254

Table 1: Damped ac test voltages levels (20 Hz–500 Hz) as used for damped ac testing (50 damped ac excitations) of recently installed power cables [IEC 60502, IEC 60840, IEC 62067]

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Maintenance Vol. 3

PRACTICAL EXAMPLES The application of damped ac voltages for testing and diagnosis of transmission power cables up to 230 kV has a history of more than 10 years. In this section, examples are presented and discussed to highlight the importance of monitored testing. Example 1: A newly installed 2.1 km long, 10 kV XLPE insulated underground cable circuit has been tested in accordance with the IEC 60502 Standard which recommends voltage withstand testing using sinusoidal ac voltage up to 2 Uₒ. Monitored withstand testing was performed by using a damped ac resonant circuit with damped sinusoidal ac voltages at 224 Hz for 50 damped ac excitation at 2.0 Uₒ. For the duration of the withstand test, standardized PD detection was applied. During the application of damped ac over-voltage, no breakdown was observed. It follows from Figures 8 and 9 that internal PD activity was registered in a joint in phase L3. The joint was investigated and the PD source was identified in the crimping tube. After the repair, the complete cable system was free of PD and the test was considered successful.

Example 2: Maintenance testing was performed on a service-aged 2.0 km long 30 kV XLPE insulated underground circuit. Starting from 0.6Uₒ, PD activity up to 9000 pC was registered in one of the joints. Increasing the damped ac test voltage up to 1.7 Uₒ resulted in concentrated PD activity in this particular joint (Figure 10). Due to the fact that the PD inception voltage is below Uₒ, increased network stresses may result in inception of, and an increase in PD activity during normal operation. Recommended replacement of the joint was accomplished, and the investigation confirmed a PD source (Figure 11).

Fig. 10: PD results of a maintenance testing of a 10 kV 2.0 km Long XLPE cable section

Fig. 11: Investigation of the joint at 415 m location having PD up to 9000 pC at 1.7 U ° Fig. 8: PD results of an after-laying testing of a 10 kV 2.1 km long XLPE cable section

Sand in between the crimp tubes

Voids between the crimp tubes due to improper crimping

Fig. 9: Investigation of the joint at 955 m location having PD up to 800 pC at 2 U °

Example 3: A newly installed 13.3 km long, 220 kV XLPE insulated underground cable circuit was tested using a damped ac resonance system at 49 Hz, applying up to 1.3 Uₒ, (Figures 1214). Monitored withstand testing was performed. As the damped ac test voltage was increased starting from 0.2 Uₒ, PD activity was observed in phase L1. An increase in the test voltage resulted in an increase of PD activity, At 0.4 Uₒ test voltage, a breakdown at the discharging site occurred. PD mapping revealed the PD concentration at 5.3 km indicated the breakdown position in the cable. The defect produced PD before an actual breakdown occurred, and with TDR analysis, the PD defect location could be determined. The other two phases fulfilled the after laying conditions and suc-

Maintenance Vol. 3

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cessfully passed the test. No internal PD activity in the cable insulation and accessories and no breakdown occurred during the tests of the other phases. The measurement was repeated from the other end of the L1 cable. The PD activity occurring before the breakdown could be localized at 8 km, which is the same location seen from the original tests (13.3 – 8 = 5.3 km).

Fig. 12: On-site testing of a 220 kV 13.3 km long XLPE cable circuit: The damped ac system HV30 is connected to one of the cable section phases

a Fig. 14: PD mapping as made up to 1.3U during damped ° ac on-site testing of a 220 kV 13.3 km long cable circuit. The PD concentration at 5.3 km distance indicates the breakdown site of phase L1(left). Measurement from the other end confirmed this location at 8.0 km.(right) b

c

Fig. 13: Damped ac voltages and PD patterns as observed during damped ac monitored voltage withstand testing of a 220 kV XLPE cable underground circuit (13.3 km): (a) example of PD pattern at 0.2U of phase L1, (b) example ° of PD pattern at breakdown voltage of 0.4 U of phase L1, ° (c) PD pattern at 1.3 U of phases L2 and L3 °

Example 4: Maintenance testing (damped ac frequency 62 Hz) was performed on a service-aged 35-year old 2.2 km long 66 kV XLPE insulated underground circuit: see Figures 15 and 16. Starting from 1.1 Uₒ, PD activity of up to 100 pC was registered in one of the joints. Increasing the damped ac test voltage up to 1.5 Uₒ resulted in concentrated PD activity in three joints. Based on this test, it was concluded that if this cable section were energized for network operation, there was a possible risk of failure during operation. Due to the fact that PDIV was very close to Uₒ and increased network stresses could result in an inception and increase of PD activity, the risk of a failure depends on the overvoltage stresses during operation. Replacement of the joint or performing the next maintenance tests within approximately six months was recommended in order to evaluate the progress of the degradation at the above mentioned locations by comparing the change of PD activity over time.

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Maintenance Vol. 3 CONCLUSIONS The following conclusions may be drawn: ●● Monitored voltage withstand testing is becoming more and more common practice. PD measurement, including PD-pattern information and time domain reflectometry (PD localization), helps detect and locate discharging defects in the insulation and accessories of power cables. ●● The combination of damped ac voltage measurements and PD detection are an alternative to continuous ac test voltage testing of distribution and transmission power cables. ●● In the context of detecting and locating discharging defects in cable accessories, monitored testing using damped ac voltages can be less destructive and more sensitive than unmonitored continuous ac voltage testing. ●● Damped ac voltage measurements are useful for after-laying testing of newly installed cables, maintenance testing of repaired cables, and diagnosis and condition assessment of service-aged cables. ●● The upcoming IEEE 400.4 guide will support users around the world with the application of the damped ac technology for diagnosing and testing underground power cables.

Fig. 15: PD patterns as observed at 1.5 UF during ° maintenance testing of a 30-year Old 66 kV XLPE insulated 2.2 km long underground circuit

Fig. 16: PD mapping as made up to 1.5 U during maintenance testing of a ° 30-year old 66 kV XLPE insulated 2.2 km long underground circuit

Maintenance Vol. 3 Edward Gulski (Fellow IEEE) was born in Poland. He received his MSDegree in Information Technology in 1982 from Dresden University of Technology in Germany, his PhD Degree from Delft University of Technology in the Netherlands in 1991, and his Doctor Habilitatus degree from Warsaw University of Technology, Poland, in 2004. At present he is CEO of onsite.hv.solutions AG in Switzerland, an international organization providing knowledge support for power utilities. As a part-time professor at Poznan University of Technology in Poland he is involved in research and education in the field of insulation diagnosis of HV components and asset management. He is chairman of CIGRE WG D1.37 Guidelines for Basic and Practical Aspects of Partial Discharge Detection Using Conventional (IEC60270) and Unconventional Methods, member of CIGRE Study Committee D1 Materials and Emerging Test Technologies, member of the IEEE Insulating Conductors Committee, chairman ofthe IEEE Working Group PE/IC/ F05W/400.4 P400.4 and Swiss member of CigréWG B1.38 “After laying tests on acand dccable systems with new technologies.”He is author or coauthor of more than 350 publications and three books in the fields of HV diagnosis and asset management. Rogier Andreas Jongen was born in The Netherlands and graduated with a MSDegree in Electrical Engineering from Delft University of Technology in 2004. After graduation he joined the Department of High Voltage Technology & Managementof the same university. In 2012 he received the Ph.D. degree for research on statistical failure analysis of component lifetime data, and its relation to asset management decisions. He worked for almost four years from 2009 with the Swiss company Seitz Instruments AG, as product manager of testing and diagnostic measurement equipment for HV network components. Now he works with onsite. hv.solutions AGin Switzerland as technical manager in the field of on-site testing and diagnosis of high voltage equipment, especially high voltage cables and power transformers. Ralph Patterson is President of Power Products and Solutions, located in Charlotte, North Carolina. His professional background includes workingas a design engineer of transformers and as a specifying engineer of insulated conductors. He has more than 25 years in power engineering,particularly in insulation diagnosis and evaluation of electrical distribution equipment. He serves on the NETA Standards Review Council,is the NETA liaison for the IEEE Insulated Conductor Committees working groups, and received NETA’s 2001 Outstanding Achievement Award.

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Maintenance Vol. 3

IMPROVING RELIABILITY BEYOND COMPLIANCE NETA World, Summer 2015 Issue Karl Zimmerman, Schweitzer Engineering Laboratories

“I’m concerned that we are too focused on compliance rather than thinking and doing the right thing.” These are words spoken by an electric utility executive at the inaugural Modern Solutions Power System Conference sponsored by Schweitzer Engineering Laboratories in Chicago in June 2012. As one looked across the ballroom, heads nodded in agreement among the group of several hundred conference goers. A lively discussion led to a consensus: The often weak relationship between compliance activities and reliability is a problem facing not only utilities, but industry as well, and it does not appear to be getting better.

According to Pittman, Valero found that capital investment was not the primary means for better reliability. Rather, improved reliability was fundamentally achieved through improved work processes. Pittman said, “Unplanned outage costs (over a period of several years) exceeded $1.9 billion, and we found 87 percent of those were preventable through reliability programs.” The maintenance plan Valero implemented has borne fruit. Besides improved metrics, “we have much better participation and buy-in from the field,” Pittman said. (See Fig. 2)

One year later, the conference reassembled in Chicago. One of the half-day panel sessions addressed the question at the heart of the issue: How can we improve reliability beyond compliance? Panelists from the aviation, petrochemical, and electric utility industries, along with protection and control system equipment manufacturers, participated in a four-hour session to discover solutions. Clifton Ericson, an author and a senior system safety engineer from URS Corporation, discussed the relationship between safety and reliability. (See Fig. 1) Ericson said that standards are beneficial and necessary, but they not enough. “Things fail. Things wear out. Humans err. Designs contain flaws. A system safety program is needed.” He used the example of a common mode failure that caused three separate hydraulic lines to fail on United Airlines Flight 232 in 1989. The hydraulic lines were on independent rightof-ways except for a short common path, which is where the failure occurred. “Reliability only considered the three redundant hydraulic lines. Safety is the missing link in reliability,” said Ericson.

Fig. 2: Measure for continuous improvement *ESARN - Electrical Safety and Reliability Index *MAIN - Materials & Inspection Network Assessment The third speaker was John Bettler, technical lead for the relay section of ComEd in Chicago, who talked about the quality process for today’s protection engineer. Developing good documentation, using standardized setting guidelines, creating application notes, performing training, and developing standardized testing requirements are the beginning of a reliable protection system. The process, Bettler said, “will incur challenges and requires support,” from executives all the way to field personnel. (See Fig. 3)

Fig. 1: Reliability and safety overlap The next speaker, Jerry Pittman, technology advisor for electrical systems for Valero, spoke of the company-wide changes that resulted in the organization’s improvement from third quartile to first quartile according to Solomon availability metrics. The vision, Pittman said, was to “instill a culture of risk-based process safety and reliability at every refinery to push beyond regulatory compliance to operational excellence.”

Fig. 3: Process for the modern protection engineer Compliance issues, he said, “must be addressed properly to avoid potential penalties.” He said engineers provide on call 24 X 7 support to evaluate all events to ensure correct operations, but there is also a separate group of personnel to assist with compliance activities.

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Maintenance Vol. 3 The final speaker was David Costello, Technical Support Director for Schweitzer Engineering Laboratories. Through his experience of working with utilities and industry, Costello was able to talk about focusing on the basics to improve reliability. Human errors, like incorrect settings or wiring issues, are much more common than equipment common-mode or “hidden” failures, he said. Therefore, “focus on human factors” like performing peer reviews, testing in the lab as much as possible, requiring complete documentation, and investing in training.

The relationship between the aviation and electric power industries spawned an interesting discussion on how compliance activities can be used to improve reliability. Airlines and airplane manufacturers have more freedom in sharing problems without fear of retribution from regulators by virtue of safe harbor laws. If errors occur and lessons are learned, sharing data “allows the entire industry to benefit,” said Ericson. One electric utility participant, on the other hand, described the feedback loop from compliance to reliability as “painful.”

Costello also discussed complexity. “One utility engineer told me, ‘we lost our picture’; the blueprint drawings showing the ac and dc schematics.” Some have expressed that microprocessor-based relays “have too many settings.” The solution, Costello said, is to require better documentation, settings descriptions, and logic diagrams. “Remember that the good ol’ days were complex also,” said Costello, recounting older electromechanical technology with a myriad of wires and hardware. (See Fig. 4)

Costello recounted a recent event. “As a member of the planning committee for the Texas A&M Relay Conference, it was very difficult to get utility engineers to volunteer to present at the Real World Experiences session,” he said. Many engineers expressed concern about disclosing problems because, Costello said, because “it may make them vulnerable to fines or litigation.”

Fig. 4: The good ol’ days, Photo courtesy of Oncor Power Delivery Costello also talked about learning from each other, as well as from other industries such as aviation. Using reliability analysis like fault trees, finding the root cause of events, and sharing what you learn are all tools for improving reliability.

A common problem expressed by one utility engineer: “The same regulator who comes to ‘help’ on Monday, comes back on Tuesday to report the findings as a violation.” Many other conference attendees expressed that there was a lack of consistency in audits between reliability councils and even individuals within a region. The presentations and discussion that followed expressed a general desire for the relationship between operators and regulators to improve. Further progress is needed, and one step in that direction was taken at the 2014 Modern Solutions Power Systems Conference in Houston, in which Costello moderated a session titled “Reinventing the Relationship Between Operators and Regulators.” Ultimately, the best solution for electric utilities and industry is to keep the focus on reliability. Designing for safety and reliability, creating an environment of continuous improvement, and determining the root cause of system events are all factors in moving the needle in the right direction. The contributions of the panelists and subsequent discussion yielded many lessons learned. The following table summarizes some contributions that can lead to improved reliability beyond simple compliance.

LESSONS LEARNED FROM DESIGN Conventional Wisdom says:

Improving Reliability Beyond Compliance says:

“We lost our picture” of older technology blueprints

Provide or require complete documentation, including descriptions, logic diagrams, and schematics as necessary

Find errors through commissioning tests

Develop checklists and test plans, test in the lab as much as possible, and mandate time for thorough field checks

Use the latest and greatest

Use what you need to solve the problem

Make quick changes in field using microprocessor-based relays

Maintain revision and document control

Each engineer calculates settings

Develop standards and processes for calculations and perform peer reviews

When budgets are tight, cut training first

Commit to training and mentorship

Let’s try it out! I think it will work!

Evaluate new technology in the lab, not in the field

Fix problems as they occur

Maintain a database of installed protection system devices and act on service bulletins

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LESSONS LEARNED FROM TESTING Conventional Wisdom says:

Improving Reliability Beyond Compliance says:

Provide simple dc control schematics and electronic settings to field technicians

Require complete documentation, logic diagrams, control schematics, and settings descriptions, as necessary

Make Company A responsible for this, Company B responsible for that

Commit to extra coordination and peer review at interties and hand-offs

Hire contractors and sub-contractors to save time and money

Require references and proof of experience, provide expectations, require a plan, and review completed work

Find phasing and wiring problems by energizing primary equipment

Use synchrophasors and primary injection, when possible, to prove phasing, wiring, and settings before energization

LESSONS LEARNED FROM FAULT ANALYSIS Conventional Wisdom says:

Improving Reliability Beyond Compliance says:

Analyze only incorrect operation

Evaluate all operations (correct and incorrect), implement lessons learned, and take corrective actions in all affected locations, designs, and processes

If operation occurs, place equipment back in service

Evaluate all operations for root cause before re-energizing equipment

Do not share system operations to limit exposure to compliance audits, fines, and litigation

Find a proper channel to share what you know, if necessary through a third party; get engaged and do the right thing

LESSONS LEARNED FROM OTHER INDUSTRIES Conventional Wisdom says:

Improving Reliability Beyond Compliance says:

Improve reliability based on the sound judgment of experienced engineers

Yes, but also use reliability tools like Fault Tree Anaysis and other data to improve

Focus on capital improvements, common-mode failures, and hidden failures

Focus on human factors, which are much more common, implement a system safety and reliability program, foster a spirit of continuous improvement

Do not encourage engineers and operators to share problems to limit exposure to compliance audits, fines, and litigation

Push for a model closer to the airline industry, where the FAA allows airlines and manufacturers to share problems without fear of fines (unless criminal)

Need to cut costs

Use risk assessment: cost of activity versus cost of inactivity

As the moderator of this session, the author wishes to express his gratitude for all of the presenters and participants in the discussion, which added value to this article. As an industry, it is our goal and ideal to continuously improve reliability. It is up to the creativity and hard work of those in the electric power industry to make it happen, and to leverage our compliance activities into improved reliability. Improving reliability is a slow and steady process, which can be likened to the work of the stonecutter, so eloquently described by the Danish American philosopher Jacob Riis.

Maintenance Vol. 3 Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying.

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BATTERY DISCHARGE TESTING: IMPLEMENTING NERC STANDARD AND FIELD EXPERIENCES PowerTest 2015 Dinesh Chhajer and Robert Foster, Megger As the electrical grid ages and expands, it is becoming apparent that testing and maintenance is critical to the reliability of the network. While many utilities have developed maintenance plans, regulatory committees such as the Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corporation (NERC) have set forth mandates to ensure that the equipment related to protection and controls is being maintained properly. Batteries provide power to the protection and control equipment, including relays, circuit breakers, and other auxiliary devices. If the battery fails, then the substation is left unprotected. Due to the criticality of the batteries for protection, NERC has laid out requirements on maintaining and testing the stationary batteries. Although many tests can be performed to assess the condition of the batteries such as ohmic testing, specific gravity, state of charge etc., only the capacity test, commonly referred to as the discharge or load test, can measure the true capacity of the battery system and determine the batteries’ state of heath. The capacity tests suggested by NERC standard PRC 005-2 are the performance test and the modified performance test. Before performing these tests, certain conditions must be met and a decision must be made on how to discharge the batteries. The battery may be tested to verify that the capacity is equal to or greater than the manufacturer’s specification or that it will meet the duty cycle required by the load. In the end, capacity can be determined by calculation based on a rate-adjusted or time-adjusted method. This paper references the IEEE 450 standard to explain different test methods, test preparation, and test performance. The standard can be consulted for further details.

FERC AND NERC REGULATIONS Blackouts have a huge economic impact on affected areas. To ensure a stable nationwide grid, even distribution of the bulk electric supply, and more reliable power system network, independent regulatory agencies such as FERC and NERC were formed to monitor these activities. FERC is an independent government agency, and its goal is to assist consumers in obtaining reliable, efficient, and sustainable energy services at a reasonable cost through appropriate regulatory and market means. NERC is a self-regulatory organization whose mission is to ensure the reliability of the North American bulk power system. It is subjected to oversight by FERC. NERC has the legal authority to enforce

reliability standards with all users, owners, and operators of the bulk power system in the United States and Canada. The existing reliability standard that applies to battery testing and maintenance is NERC Standard PRC-005-2 Protection System Maintenance. This standard ensures that all protection systems affecting the reliability of the Bulk Electric System (BES) are maintained, tested, and kept in working order. It is applicable to all generation owners, transmission owners, and distribution providers. NERC’s PRC-005-2 standard provides recommendations for maintaining, testing, and recording data for the stationary batteries. In the standard, Table 1-4 (a)1 lists the testing and maintenance intervals for vented lead-acid batteries. Key maintenance activities recommended in the table are listed below: ●● Every four months, verify station dc supply voltage and check the electrolyte level and any unintentional grounds. ●● Every 18 months, check float voltage, internal ohmic value, inter-cell connection resistance, and battery rack structure. ●● Perform internal ohmic test, and compare against baseline once every 18 months or verify that the station battery can perform as manufactured by conducting a performance or modified performance capacity test of the entire battery bank at least once every six years.

PERFORMANCE TEST IEEE Standard 485-1997, IEEE Recommended Practice for Sizing Lead-Acid Batteries for Stationary Applications, defines a performance test as “a constant-current or constant-power capacity test made on a battery after it has been in service.” It is the most commonly used discharge test method, and it determines if the battery is performing according to the manufacturer’s specifications and/or if it is within acceptable limits. It can be used for benchmark as well as maintenance practices. For the performance test, a constant current specified by the manufacturer is applied for an accompanying specified time. Battery manufacturers publish tables that include different discharge rates specified for different periods of time. Each discharge rating has an end-point cell voltage as the stop criteria for the discharge test. Depending on the load requirements, amount of time available, or the capabilities of the test equipment the user in the field can

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Maintenance Vol. 3 determine the appropriate discharge rate. The measured capacity is generally corrected to 25°C, but temperature correction can vary by manufacturer. It is recommended that this test be performed within the first two years after the battery is in service; thereafter, the test interval should be at 25 percent of the expected service life. It should be performed annually if the battery shows any sign of degradation or has reached 85 percent of the service life expected for the application. However, if the battery has reached 85 percent of service life but delivers a capacity of 100 percent or greater of the manufacturer’s rated capacity and has shown no signs of degradation, performance testing at two-year intervals is acceptable.

MODIFIED PERFORMANCE TEST A modified performance test is defined as a test in the “as found” condition of battery capacity that measures the battery’s ability to satisfy the duty cycle. The modified performance test is similar to the performance test in that it verifies manufacturer’s specifications and tests the capacity of the battery. It also has the added benefit of verifying that the battery will meet the specified duty cycle. The test is designed to encompass the entire duty cycle, so a chosen current is applied for a certain amount of time and then modified and applied for a different amount of time. This is repeated until the entire duty cycle is completed. Once the duty cycle is satisfied, the remainder of the test is dedicated to meeting the manufacturer’s specifications while taking into account the aging margin. A detailed description of modified performance tests and case examples can be found in IEEE 450 Annex I.

EFFECT OF TEMPERATURE Cell temperature can greatly affect the battery’s performance, including the state of charge and state of health of the battery. Batteries perform best when they are operated at or close to their published rated temperature. At higher temperatures, the internal resistance of the cell goes down, accelerating the rate of chemical reaction and thereby improving the capacity of the battery. However, operating the battery at elevated temperature reduces the service life of the battery. Conversely, at colder temperatures, the chemical reaction rate slows down and the capacity decreases. Manufacturers recommend operating the battery at published temperature to derive the published capacity and optimize the service. When a capacity test is performed outside the manufacturer-specified temperature, correction factors are applied (per IEEE 450 or manufacturer recommendations) to capacity calculations for baseline comparison and trending of results.

BATTERY DERATING FACTOR Batteries are sized to serve the designed load requirements throughout their expected service life. Like any other electrical

asset, battery performance deteriorates with age, temperature, charge-discharge cycles, maintenance practices, charger settings, and a number of other factors. Therefore, batteries are sized with an aging factor so that they can deliver a charge to the specified load until the end of their life cycle. Aging factor is the safety margin built into the sizing calculation when selecting the battery’s rated capacity. The derating factor is based upon the aging factor. It is indicative of reduced capacity as the battery approaches the end of its service life2. A battery sized with an aging factor of 1.11 will have a derating factor of 0.9. In this case, a battery having 90 percent published capacity remaining will marginally meet specified load requirements with no safety factor. It also marks the end of the battery’s service life, where any further decrement in capacity would put the system at risk.

CAPACITY CALCULATION METHODS A battery’s capacity is defined in amp hours. It is typically expressed as a percentage, as a ratio of measured amp hour capacity to manufacturer’s published capacity (rate x time). Two different methods measure the capacity of a battery bank: Time-adjusted method. In the time-adjusted method, the test current is kept constant and is defined by the published rate (discharge current) for the desired time duration. The capacity test is performed until the voltage reaches the end cell terminal voltage. In Table 1, for a 1.75 V endcell voltage and an eight-hour test, the rate will be 15.8 A. Since the rate is kept constant and is equal to a published rate, battery capacity is calculated as the ratio of measured discharge time to published discharge time.

Where, ○○ C= Capacity at 25°C ○○ Ta=Actual time duration of test to specified terminal voltage ○○ Tm=Published rated time to reach terminal voltage ○○ Kt=Temperature correction factor as per IEEE 450 Table (1)

Table 1: Manufactured published ratings at 25 C Rate-adjusted method. The rate-adjusted method is more complex than the time-adjusted method. In this method, time duration is kept constant, and the rate is adjusted based upon the battery’s derating factor. IEEE 485 states, “To ensure that the battery is capable of meeting its design loads throughout its service life, the

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battery’s rated capacity should be at least 125 percent (1.25 aging factor) of the load expected at the end of its service life.” This means the battery would reach the end of its service life when it reaches 80 percent of its specified performance.

required is goggles and face shields, acid-resistant gloves, and a protective apron. Additionally, safety guidelines recommended by IEEE 450 as well as federal, state, and local safety precautions should be followed.

Referring to Table 1, for a 15-minute test duration and a derating factor of 0.8, the rate is adjusted to 182 A (80 percent of 228 A). The test is conducted with15-minute and 182-A settings until the specified end voltage is reached. Capacity is calculated by taking the ratio of the test rate and published rate corresponding to actual test duration using manufacturer’s data.

Since the pre-test conditions can greatly affect the outcome of the test, it is recommended that key parameters are checked before initiating the test. Prior to testing, the battery should be under float conditions for at least 72 hours. Individual cell voltage, float current from the charger, and battery terminal float voltage should be measured to verify the float conditions. Stabilized float current measurement determines the fully charged state of the battery. The battery connections and resistance measurements should be checked. Additionally, the temperature of the electrolyte in 10 percent or more of the cells should be measured. Make sure the battery is isolated from any other battery or critical load.

Where, ○○ C=Capacity at 25°C ○○ Xa=Actual rate used for the test ○○ Kc=Temperature correction factor as per IEEE 450 Table (2) ○○ Xt=Published rating for time to specified terminal voltage This method can be difficult to use because the discharge rate corresponding to actual test time sometimes is not available in manufacturer-published data; in some cases, interpolation and other curve-fitting techniques determine it. Two factors that affect the capacity calculation numbers are degradation in battery quality and reduction in battery efficiency at high discharge rates. It is a well-known fact that battery efficiency decreases with increased discharge rate. The capacity measured at the 1 hour discharge rate is different than the capacity measured with an 8 hour discharge rate. The time-adjusted method provides a conservative end-of-life assessment because it does not consider changes in battery efficiency with discharge time. Technically, the rate-adjusted method provides more realistic results as it takes into account the battery sizing criteria and derating factor. When high-rate, short-duration tests are performed, that is why the rate-adjusted method yields more accurate results than the time-adjusted method. Both test methods yield the same results when tested for long durations (typically eight hours). Because of simplicity, it is recommended to use the time-adjusted method for long-duration tests (60 minutes or greater). Though complex, the rate-adjusted method is preferred when performing a short-duration (60 minutes or less), high-discharge test because results will not be masked by the battery efficiency factor.

SITE PREPARATION Site preparation is important to ensure that testing is performed safely and correctly. Before performance or modified performance testing can begin, certain initial conditions must be met. The load connected to the battery should be connected to backup power prior to disconnecting the bank for testing. The minimum PPE

Once all initial conditions are met, the load bank and any other necessary test equipment should be set up and the battery disconnected from the charger and connected to the load bank. If it is not possible to disconnect the charger, the load should be adjusted to compensate for the current that the charger is providing.

DISCHARGE TEST PROCESS After the initial preparation, the discharge rate and test duration is selected using manufacturer’s published data. These test parameters will depend on the selected test and on the method used for capacity calculations. Note that current values are not adjusted for temperature; temperature is taken into consideration when the capacity is calculated. Timing starts when the load begins to discharge the battery at the selected discharge rate. The battery should be discharged until it reaches minimum terminal voltage. The minimum terminal voltage is determined by multiplying the number of cells to the minimum average voltage of the cell specified by the design. A minimum of three measurements of both the battery terminal voltage and individual cell voltages should be measured over the course of the discharge — one at the beginning of the test when the load is applied (to detect any initial voltage drop due to application of the load), one or more at specified intervals, and one at the end of the test. To include the voltage drop across the inter-cell connectors, the voltage of each individual cell should be measured between posts of the same polarity, from one cell to an adjacent cell. Figure 1 shows cells connected to battery voltage monitors, which monitor individual cell voltage and overall terminal voltage at specified intervals for the duration of the test. While the test is being performed, the connectors between the cells should be monitored for any abnormal heating. It is allowed to pause the discharge test for up to 10 percent of the total test time or six minutes, whichever is shorter. This allows the user to fix any problems that arise during the test, such as bypassing an individual weak cell or fixing any problem with the connections or test equip-

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Maintenance Vol. 3 ment. Only one pause is allowed for the duration of the test, and the pause time should not be counted in the total discharge time. Once the test is completed, determine the battery capacity. The test equipment can then be disconnected.

manufacturer’s published rating. The replacement should be made as soon as possible, without exceeding one year from the date of the capacity test. When looking for a replacement, follow the IEEE 485 guidelines to perform the sizing calculations, and contact the battery manufacturer for recommendations on the appropriate battery style and design to meet the requirements. Per IEEE guidelines, a new capacity baseline for the replacement bank should be established by performing an acceptance test on site.. In the event that only one or a few cells need replacement, the battery manufacturer should be consulted on compatibility with the existing battery installation, overall duty cycle, and load requirements. Efforts should be made to identify replacement cells that have performance characteristics similar to the existing installation. Per the IEEE acceptance criteria, all replacement cells should be tested for capacity before installation. After the replacement, benchmark capacity of the battery bank should be re-established, using either the time-adjusted or the rate-adjusted method.

Fig. 1: Connection of individual voltage monitors and load bank for discharge testing

CELL BYPASS AND POLARITY REVERSAL While performing the discharge test, one should be prepared to bypass weak cells approaching polarity reversal. Polarity reversal takes place when one or more cells are weaker than the other cells in the string. Since all the cells are in series and the discharge current is the same, the weak cells tend to overheat and discharge faster than the others. This can bring the whole battery string down. If any cell voltage drops to one V or below, it is approaching polarity reversal. In the event of polarity reversal, it is recommended to pause the test, disconnect the weak cell, and bypass it with a jumper suitable to handle the discharge test current. All safety and precautionary measures should be followed when performing this. The end voltage should be recalculated, and the test should be resumed with a modified end terminal voltage. The maximum allowed time to bypass a weak cell and then resume the test is defined by the lesser of 10 percent of test time duration or six minutes. Only one pause is allowed for the duration of the test. Pause time should not be counted in total discharge time. If cell reversal is identified at the very end of the discharge testing, finish the test and do not take any action. Bypassing weak cells is not allowed during the duty cycle portion of a modified performance test.

BATTERY REPLACEMENT CRITERIA Upon completion of a capacity test, the measured capacity should be reviewed based on sizing criteria used during installation to determine if the battery is still able to meet the load requirements. The most common recommended practice is to replace the battery bank, if measured capacity is less than 80 percent of the

FIELD CHALLENGES ASSOCIATED WITH DISCHARGE TESTING Load selection for discharge test. Battery manufacturer’s published discharge times range from one to 20 hours or more. It is preferred to test the batteries in a reasonable amount of time. A performance test with time duration of three to four hours is common, but such shorter test times require higher loads. The discharge current required for these short-duration tests can exceed the nominal capacity of portable instruments. This problem can be solved by connecting additional load units in parallel. Advanced planning is needed if extra units are required to achieve the desired discharge rate and time frame assigned for the activity. In any case, no matter how big the load is, power is dissipated in the instrument as heat during the test. Take care to direct the heat dissipation away from the batteries and/or properly ventilate the area to avoid heating the room or batteries while testing. Also, if several units are connected in parallel, there might not be enough space at the end posts to connect the cables from the load units. A good practice is to have a piece of cable or bar available to extend the post a little and provide space to connect the cables from multiple load banks. Backup power. Backup power can be provided through a mobile dc power system or through a backup battery bank at the substation. If no backup power is available, an on-line discharge test can be performed. During this type of test, the regular substation load is always connected to the battery and is continuously monitored. The load bank maintains the desired constant current by regulating the remaining current needed in addition to the substation load current. This method requires an additional CT accessory to monitor the substation load current. Connection to insulated posts. Some batteries might have the post and straps totally insulated with just a small access to measure the voltage with a digital voltmeter. This could make the installa-

22 tion of the load cables, and especially the individual voltage monitors, very difficult. The batteries should be prepared for the connections; several different types of clips or leads should be available to connect the individual voltage monitors to the batteries. Bypass a cell. Bypassing a cell might be required during the test. If a cell hits one V or less, it should be bypassed. The time allowed by the IEEE 450 standard for bypassing a cell is very short. It is a simple procedure, but it requires being ready with a bypass cable of the right gauge and length. Check historic tests to determine if a bypass might be required and prepare the proper cable for it. Insulated tools should be available for this procedure to avoid a short circuit during the cell bypass.

SUMMARY With regulations set forth by NERC and FERC, all generation and transmission owners as well as distribution providers must be compliant, or they will face heavy penalties imposed by these regulatory agencies. Maintenance must not only be performed but also well documented. Test results and maintenance records must be provided to NERC upon request. One of the options under compliance tests, the capacity test determines the true health of a battery. Safety precautions should be taken and certain initial conditions met before the capacity test can be performed. A performance test is used to verify the battery’s capacity related to the manufacturer’s specifications. The modified performance test will also verify that the battery meets the specified capacity, and it will test the duty cycle required by the load. The test method should be determined prior to testing, and the same method should be repeated for the remainder of the battery life. The capacity can be calculated using the time-adjusted or the rate-adjusted method. The effect of temperature is taken into account by using temperature-correction factors during the capacity calculations. Proper maintenance not only ensures that the battery owners are compliant but also determines the health of the batteries. The capacity test will help owners verify that the battery will supply the load needed when called upon to protect valuable assets. Additionally, it provides guidance for scheduling replacement when the battery approaches the end of its service life.

REFERENCES NERC Standard “PRC-005-2 – Protection System Maintenance“ 2012 IEEE Standard 450-2010, “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications” IEEE Standard 485-1997, “IEEE Recommended Practice for Sizing Lead-Acid Batteries for Stationary Applications” Discharging at high and low temperatures, “http://batteryuniversity.com/learn/article/discharging_at_high_and_low_temperatures”

Maintenance Vol. 3 Steve Clark, “Rate adjusted battery capacity testing and calculations, including what to do when someone says oops!” The BattCon Proceedings, 2007 Subhash Chalasani, “Battery state of health estimation through coup de fouet: Field experience.” The BattCon Proceedings, 2003 Phillip E Pascoe, Adnan H Anbuky, “The behavior of the coup de fouet of valve-regulated lead–acid batteries” Dinesh Chhajer received his M.S. degree from the University of Texas at Arlington in 2006. Currently, he is working as a Sr. Applications Engineer for Megger. At Megger, his responsibilities include providing engineering consultation and recommendations in relation to the testing of transformers, circuit breakers, batteries and other substation assets. Dinesh has previously worked as a substation maintenance engineer and substation design engineer with POWER Engineers, Inc. He is a IEEE member. He is currently a licensed professional engineer (PE) in the state of Texas. Robert Foster is an Applications Engineer with Megger, specializing in high voltage circuit breaker and transformer testing. He graduated from California State University, Chico with a Bachelors of Science in Physics and Mechatronic Engineering. After graduation he worked as a Field Service Engineer for ABB in the high voltage dead tank circuit breaker division. He is involved with customers and product development supporting products and applications throughout North America.

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HOW TO MAINTAIN STATION BATTERIES NETA World, Fall 2015 Issue Tom Sandri, Shermco Industries

There are various philosophies and opinions for maintaining and testing station battery systems. These approaches can range from doing nothing and replacing when the battery fails to an intense, time-based battery maintenance regimen. Obviously the “do nothing” approach appears a little flawed. Keep in mind that batteries are perishable items with a useful life, and their variability is based on a number of factors. They require a constant float charge to maintain freshness as well as periodic inspections to ensure that they are maintaining the proper charge and can deliver the rated output. Besides being perishable, another unique feature of a battery compared to other electrical assets is that it uses chemicals, metal alloys, plastics, welds, and bonds that must interact with each other to produce a constant dc source. For this reason, the type of battery (flooded lead-acid, sealed/valve-regulated lead-acid, or nickel-cadmium) should be considered before embarking on a battery maintenance program. Such a program can employ a number of recommended practices and typically includes inspections, actions, and measurements conducted under normal float conditions and capacity tests usually performed with the battery system off line. The most commonly recommended practices are contained in three standards of The Institute of Electrical and Electronics Engineers (IEEE): ●● IEEE 450 Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications. ●● IEEE 1188 Recommended Practice for Maintenance, Testing, and Replacement of Valve-Regulated Lead-Acid (VRLA) Batteries for Stationary Applications. ●● IEEE 1106 Recommended Practice for Maintenance, Testing, and Replacement of Nickel- Cadmium Batteries for Stationary Applications. If the application involves the generation transmission, or distribution of bulk electrical power, it is likely subject to North American Electric Reliability Corporation (NERC) requirements. Those requirements are outlined in Standard PRC-005-2 Protection System Maintenance. + While the IEEE standards were consulted to arrive at certain details of the PRC-005-2 maintenance procedures, the former are recommended practices while the latter are mandatory and enforced by NERC.

BASIC INSPECTIONS It is important to understand that no single test or procedure tells the whole story. The purpose of tests and inspections is to determine what condition the batteries are in, and hopefully, provide some idea of where that condition is headed and how fast. A power outage is the wrong time to find out that the batteries did not have sufficient capacity, the load was dropped sooner than designed, or that the entire system failed due to a single component failure — and that all of this could have been predicted and prevented. Therefore, it is important to have all usable test data available and to record it properly. Visual Inspection. It is important that the entire system is examined. The battery surfaces should be clean and free of dust, dirt, tools, and electrolyte. Floors should be clean, and the mechanical system supporting the batteries should not have any rust or look distressed in any way. Make sure ventilation systems are verified and thermostat setting is checked and recorded. Check each battery jar for signs of leaks or cracks and inter-cell straps for signs of corrosion. Whether correct or not, each of these items should be recorded, corrected if needed, and noted when the correction was made. Charger Output Voltage and Current. The charger’s output voltage and current are typically measured and displayed on the charger itself. However, it is important to understand that the measurement and/or the charger display may not be accurate. Because the charger plays such an important role in the life of the battery, the output voltage of the charger should be verified with a dc voltmeter and the charger output current be verified with a dc ammeter and adjusted accordingly. This should be done at float levels as well as equalization charge levels, if available. Float Voltage. Float voltage should be measured and recorded across each cell at the battery posts. The measurement is made on the battery post and not on the straps or hardware. This should be measured during float conditions and not during discharge or recharge. The value obtained should be compared to the manufacturer’s recommended value of float voltage per cell. The sum of each individual cell’s float voltage should equal that of the charger output.

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CURRENT AND CONNECTION RESISTANCE TESTS

100Ah of battery capacity. The less the ripple current, the longer the battery life will be.

Another important battery maintenance consideration is measurement and/or monitoring of current and connection resistances. Excessive current flow — either dc or ac — indicates a problem in a battery cell or with the charger and rectifier circuit. With loose connections, continuity in the battery string is compromised and the resulting high-resistance areas can overheat.

Ripple current measurements (and charger designs that minimize it) are suggested in IEEE-1188 in particular because the heating that results can contribute to a condition of thermal runaway in VRLA batteries.

DC Float Current. Float current is the dc current that flows through the battery string during float conditions. It is the result of float voltage applied to the cell’s internal resistance. Because of Kirchhoff’s Current Law, float current can be measured anywhere within the series string. A difference in current measurement at the beginning of the string compared to the end is an indicator that current is flowing to ground through a damaged cell. When originating in the string, the ground current value can be very small and difficult to measure. Normal float currents are typically less than one amp and vary by size and manufacturer. If the manufacturer does not recommend a float current value under normal conditions, then values from one test to another should be compared to look for gross increases from previous measurements. This is especially important in VRLA batteries, as increased float current can lead to thermal runaway. Float current should be measured during float conditions and not during discharge or recharge.

Fig. 2: Current ripple from a charger Inter-Cell Resistance. Inter-cell resistance (also called strap resistance) is an important measurement and should not be overlooked. While application of the correct torque to the strap bolt and nut is important, it is not sufficient to ensure a low resistance connection. Resistance should be measured across each strap by making contact at the battery terminals and not on the straps themselves.

Fig. 3: Proper points for inter-cell resistance measurements

Fig. 1: Float current flowing through a battery string AC Ripple Current. Ripple current is measured with an ac meter. The measurement should be taken through each series string during float conditions. Ripple current and ambient temperature should be analyzed together because high ripple current in the presence of a high ambient temperature will have more of an adverse effect on the battery than high ripple current alone. IEEE recommends that ripple current not exceed five amps for every

The reason for making contact at the battery post and not on the strap is that the measurement must include the contact resistance between the strap and the post. The junction between the strap and the post is where most high resistances will occur, usually due to a loose connection or the presence of foreign material.

SPECIFIC GRAVITY AND DISCHARGE TESTING Specific gravity is the ratio of the weight of a solution to the weight of an equal volume of water at a specified temperature. As applied to battery maintenance, the measurement of specific

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Maintenance Vol. 3 gravity is an indicator of the state of charge (SOC) of a cell or battery. During battery discharge, the specific gravity decreases to a value near that of pure water, and it increases during a recharge. The battery is considered fully charged when specific gravity reaches its highest possible value.

●● First, every battery has a certain number of deep discharges that it can tolerate before failure, so each discharge test reduces battery life.

Specific gravity tests are performed on vented/wet cells. As mentioned earlier, this measurement is temperature dependent, and all measured values must be compensated for electrolyte temperatures above or below 25°C (77°F). Electrolyte level can affect the specific gravity measurement because water is lost during the recharge cycle. If there is less water and the same amount of acid due to a full recharge, then the specific gravity measurement will be higher than it should.

If the battery system being tested is in service, a backup system should be installed to prepare for a potential power outage. A temporary external load comparable to the normal load served should be connected to the main system under test. The time of the test can last as long as the rating on the battery.

●● The second drawback is the complexity, cost, and time to correctly perform a discharge test.

Because sulphuric acid has a higher density than water, the sulphuric acid often migrates to the bottom of the jar. This can lead to a lower specific gravity measurement at the top of the jar than at the bottom. Normally, an equalization charge will mix the electrolyte so that the specific gravity measurement is accurate at any level measured. Fig. 5: Battery load/discharge test

OHMIC TRENDING

Fig. 4: A sample of electrolyte is drawn for a specific gravity test Discharge Tests. There are three types of load tests: the acceptance test, the performance test, and the service test. ●● The acceptance test is made at the beginning of battery life, is usually performed at the factory or at installation, and is based on the battery’s design capacity. ●● The performance test, which is also based on battery capacity, is typically performed two to three years after installation and then every five years, based on the IEEE recommendation.

There are three types of ohmic battery testers: impedance testers, conductance testers, and resistance testers. Each method is recognized by IEEE and is a means of determining the Stateof-Health (SOH) of a battery. Perhaps one of the greatest values of ohmic testing is that it is performed while the battery is online, filling the gap between discharge tests by providing a correlation to a cell’s capacity. AC Test Methods. Impedance testers apply an AC test current to the battery under test and measure the vector sum of the internal cell resistance and the capacitive reactance of the cell plate. The measurement theory is based on Ohm’s Law. The products inject an ac test current of either 50 or 60 hertz (I) into a battery or cell; the ac current is measured by the receiver, and the ac potential drop across the cell (E) is measured using potential probes. The cell’s impedance (Z) is derived from: E = Z I

●● The service test, which is performed as needed, is based on the load and determines if the battery will correctly supply the load. Load testing or discharge testing is the absolute assessment of whether a battery is going to be capable of supplying the amount of current for the designed amount of time. However, there are some drawbacks:

Fig. 6: Equivalent battery circuit — ac measured components

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Ra=Resistance of the acid Rm=Metallic resistance, including grids, top lead, posts Cc=Capacitance of cell Rc=Charge transfer resistance L=Inductance Conductance testers also measure the flow of ac current through a battery; however, they measure the conductance rather than the impedance. DC Test Methods. Resistance testers measure the drop in dc voltage by applying resistance. A resistance tester places the battery cell under momentary load (approximately three-second load of approximately 72 amps). The instantaneous voltage drop at time zero and voltage recovery when the load is removed will show a voltage drop across the internal resistance. Ra=Resistance of the acid Rm=Metallic resistance, including grids, top lead, posts Cc=Capacitance of cell Rc=Charge transfer resistance L=Inductance

Fig. 7: Equivalent battery circuit — dc measured components Although different techniques are used to capture internal ohmic values of a battery cell, the data can be managed in a similar manner. In short-term analysis, each individual cell’s ohmic reading can be compared to the average ohmic value for all of the cells. This analysis will quickly expose possible weak cells that are falling outside the bank average. If a baseline is established for the battery, the readings can be compared against the baseline to determine approximately how much life has been used. Baselines are best established from a known healthy cell or after a capacity test. Finally, by comparing readings over time, the aging rate of the battery can be established.

BATTERY MAINTENANCE SUMMARY A battery is a complex electro-chemical device. Batteries are the only element of a Protection System that is perishable and has a limited life. As perishable items, batteries require not only a constant float charge to maintain their freshness (charge), but also periodic inspection to determine if problems exist with their aging process as well as testing to see if they are maintaining a charge or can still deliver their rated output as required.

Besides being perishable, a second unique feature of a battery that is unlike any other Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and bonds that must interact with each other to produce the constant dc source required for Protection Systems, independent of issues and disturbances on the ac system. No battery manufactured today for Protection System application is free from problems that can only be detected over time by inspection and test. These problems can arise from variances in the manufacturing process, chemicals and alloys used in the construction of the individual cells, quality of welds and bonds to connect the components, the plastics used to make batteries, and the cell-forming process for the individual battery cells. Other problems that require periodic inspection and testing can result from harm caused during transportation from the factory to the job site, length of time before a charge is put on the battery, the method of installation, the voltage level and duration of equalize charges, the float voltage level used, load characteristics, and the battery’s installation environment. Thomas Sandri received his BSEE from Thomas Edison University in Trenton, N.J. He has been active in the field of electrical power and telecommunications for over 30 years. During his career he has developed numerous training aids, training guides, and has conducted seminars-both domestic and international. Thomas supports a wide range of electrical and telecommunication maintenance application disciplines. He has been directly involved with and supported test and measurement equipment for over twenty years and is considered an industry expert in application disciplines including battery and dc systems testing and maintenance, medium and high voltage cable, ground testing, and partial discharge analysis.

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NERC REQUIREMENTS FOR SUBSTATION DC SUPPLY SYSTEMS NETA World, Fall 2015 Issue Lynn Hamrick, Shermco Industries

On August 14, 2003, large portions of the Midwest and Northeast United States and Ontario, Canada, experienced an electric power blackout. The outage affected an estimated 50 million people with 61,800 megawatts (MW) of electric load in the states of Ohio, Michigan, Pennsylvania, New York, Vermont, Massachusetts, Connecticut, New Jersey, and Ontario. The blackout began about 4:00 PM, and power was not restored in some parts of the United States for 4 days. Parts of Ontario suffered rolling blackouts for more than a week before full power was restored. Total cost estimates in the United States and Canada exceeded $2 billion.

and maximum maintenance intervals for vented lead acid (VLA or flooded), valve-regulated lead acid (VRLA or sealed), and NiCad battery systems respectively. The standard also provides an exclusion to these time-based maintenance activities if the monitoring attributes of PRC-005-2, Table 1-4(f) have been implemented. Although this table has been provided for information purposes, only the time-based maintenance program requirements will be discussed herein.

As a result of this blackout, the North American Electrical Reliability Corporation (NERC) was formed and tasked with developing standards for utilities and other producers regarding reliability and maintenance of the Bulk Electrical System (BES). NERC was also given the authority to enforce these standards. On December 19, 2013, the Federal Energy Regulatory Commission (FERC) approved NERC Reliability Standard PRC-005-2, Protection System Maintenance. Included in the federal register was Docket No. RM13-7-000, Order No. 793. In this submittal was FERC’s approval of NERC’s proposed implementation plan for the standard, “which requires entities to develop a compliant protection system maintenance program within 12 months, but allows for the transition over time of maintenance activities and documentation to conform to the new minimum maintenance activities and maximum maintenance intervals.” This standard includes requirements associated with maintaining and testing BES substation batteries. Utilities are required to develop a protection system maintenance program (PSMP) that conforms to the new PRC-005-2 minimum maintenance activities and maximum maintenance intervals. Based on a utility’s experience with substation battery systems, the utility should select and implement an appropriate maintenance program to perform at an appropriate interval. The standard also states that for batteries associated with the station dc supply, a time-based maintenance program shall be implemented. Most substation battery systems use battery systems with vented lead acid (VLA or flooded) or valve-regulated lead acid (VRLA or sealed) battery systems due to the cost and experience with these types of systems. However, nickel-cadmium (NiCad) battery systems are also in use. Accordingly, slightly different maintenance and testing requirements are provided in the NERC standard for each of these different battery types. PRC-005-2, Tables 1-4(a), 1-4(b), and 1-4(c) provide the minimum maintenance activities

Tables 1-4: PRC-005-2 T (a) and (b)

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Maintenance Vol. 3 only distilled or demineralized water. In addition, be careful not to overfill the battery with water. Removing some of the electrolyte will reduce the concentration of potassium hydroxide in the cell and adversely affect its operation. Similar to VLA battery cells, an unusually high usage of water indicates excessive gassing, and troubleshooting of the battery and charging equipment should be performed. In accordance with PRC-005-2, Tables 1-4(b), the following activity should be performed and documented at least every six months for VRLA battery system types:

Tables 1-4: PRC-005-2 T (c) In accordance with PRC-005-2, Table 1-4(a), -4(b) and -4(c), the following activities should be performed and documented at least every four months for all battery system types: ●● Verify dc supply voltage — Battery charging is an important factor in battery system maintenance. A properly functioning battery charging system with a healthy battery condition will result in a fully charged and reliable battery system that is available for service when needed. A consistent dc supply voltage from the battery charger is necessary for a healthy battery system. ●● Inspect for unintentional grounds — Battery systems are typically ungrounded systems. Unintentional grounds can adversely affect the operation and reliability of battery systems as well as pose safety hazards to personnel. Additionally, in accordance with PRC-005-2, Tables 1-4(a) and -4(c), the following activities should be performed and documented at least every four months for VLA and vented NiCad battery system types:

●● Inspect cell condition by measuring cell internal ohmic value — Measuring cell internal ohmic values can assist in determining battery health. The most common methods of measuring cell internal ohmic values include using dc voltage to measure resistance or ac voltage to measure conductance or impedance. A cell’s internal resistance provides useful information in detecting problems and can be used for indicating when a battery or battery cell should be replaced. A change in cell resistance relates to aging and provides some failure indications. Rather than relying on an absolute resistance reading, measurements are trended against previous cell resistances with subtle changes requiring further investigation. When using dc voltage, resistance is measured in ohms. When using ac voltage, impedance is also measured in ohms. An increase in resistance/impedance of 25 percent over an initial baseline (100 percent) or related cells indicates a performance drop to about 80 percent. When using ac voltage and the measurement is conductance, the units employed are mhos, or siemens. As conductance declines, so does a battery’s ability to meet its specified capacity and supply energy. A decrease in conductance of 25 percent over an initial baseline (100 percent) or related cells indicates a performance drop to about 80 percent.

●● Inspect electrolyte level — Vented or flooded cells have translucent or transparent jars, so the electrolyte level can easily be compared to a recommended level that is marked on the cells. The frequency of watering depends on usage, charge method, and operating temperature. Avoid exposed plates at all times, as this will result in damage, leading to reduced capacity and lower performance.

In accordance with PRC-005-2, Table 1-4(a), -4(b), and -4(c), the following activities should be performed and documented at least every 18 months for all battery types:

○○ For VLA battery cells, an unusually high usage of water indicates excessive gassing. If excessive gassing exists, troubleshoot the battery and charging equipment. An excessive amount of charge results in high battery temperature and a reduced battery service life.

●● Battery continuity — All cells within the battery should be connected in a continuous manner to support proper battery operation. When called upon for use, each cell provides a specific voltage in support of the battery system voltage. For VLA batteries, the cell voltage is typically ~2 vdc. For VRLA batteries, the cell voltage can vary from ~2 to 12 vdc. For vented NiCad batteries, the cell voltage is typically ~1.2 vdc.

○○ For vented NiCad cells, during discharge the plates absorb a quantity of the electrolyte. On recharge, the level of the electrolyte actually rises; and at full charge, the electrolyte will be at its highest level. Therefore, water should never be added to the battery until three or four hours after it has been fully charged. If it is necessary to add water, use

●● Verify float voltage — Charger float voltage is the typical voltage output for a normal charging process. This voltage should be in accordance with manufacturer recommendations, but may need to be increased as the battery ages or degrades.

●● Battery terminal connection resistance — The battery terminal connection is where the battery connects via cabling to the rest of the dc system. As with any electrical circuit,

Maintenance Vol. 3 connection points within the system must be maintained at a very low resistance to minimize overheating and subsequent connection failure. Increases in battery terminal connection resistance over time are indicative of a degrading connection. ●● Intercell connection resistance — As with the battery terminal connection, connections between the battery cells must also be maintained at a very low resistance to ensure proper battery continuity as well as minimize overheating and possible cell failure within the battery. Increases in intercell connection resistance over time are indicative of a degrading connection that could be caused by battery post corrosion or a loose or otherwise defective connection. ●● Inspect physical condition of rack — In most substation applications, battery cells are numerous and heavy. Therefore, the racks supporting the battery cells should be structurally capable of supporting the weight and position of the cells. Any movement of the rack could stress the cells, the cell posts, and the intercell connections and lead to a degraded battery. The racks should be inspected for signs of corrosion as this is indicative of possible electrolyte leakage from a cell on the rack. Additionally, in accordance with PRC-005-2, Tables 1-4(a) and -4(c), the following activities should be performed and documented at least every 18 months for VLA and vented NiCad battery system types: ●● Inspect cell condition — Most cells have translucent or transparent jars, so the inside of the jar may be inspected. As discussed previously, electrolyte level can easily be compared to a recommended level marked on the cells. Look for cracks, breaks, and pieces hanging on the side, as this is indicative that the cell may need to be replaced and that other cells may also have a similar problem. ○○ For VLA battery cells, the positive plates are located toward the center of the jar and are typically the first to wear out. They should be dark brown or black. Sparkle is evidence of sulfation or undercharge. The negative plates are thinner than the positive plates and sit toward the outside of the jar. These should have a clean lead color from top to bottom. Pink discoloration indicates copper contamination. Inspection of the sediment should provide a general idea of the battery conditional trend from the last inspection. Accumulation of gray material under the negative plates, accompanied by sparse black sediment, is indicative of an undercharging condition. Excess black sediment under the positive plates with little negative sediment is indicative of an overcharging condition or excess temperature. If excess sediment covers the bottom of the jar, the battery has been cycled heavily or operated at high temperature. A crusty trail or accumulation is evidence of electrolyte leakage. Signs of corrosion on the terminal connections, intercell connections, and racks are also indicative of electrolyte leakage.

29 ○○ For NiCad battery cells, spilled electrolyte can react with carbon dioxide to form potassium carbonate crystals. These crystals, which are non-toxic and non-corrosive, can be loosened with a fiber brush and wiped off with a damp cloth. When potassium carbonate forms on a properly serviced battery it may indicate the battery is overcharging because the voltage regulator is out of adjustment. ●● Measure cell internal ohmic value — For VLA batteries, this alternative method of inspection can be performed, particularly when cells are not visible to inspect. Measuring cell internal ohmic values can assist in determining battery health. The most common methods of measuring cell internal ohmic values include using dc voltage to measure resistance or ac voltage to measure conductance or impedance. A cell’s internal resistance provides useful information in detecting problems and can be used for indicating when a battery or battery cell should be replaced. A change in cell resistance relates to aging and provides some failure indications. Rather than relying on an absolute resistance reading, measurements are trended against previous cell resistances with subtle changes needing further investigation. When using dc voltage, resistance is measured in ohms. When using ac voltage, impedance is also measured in ohms. An increase in resistance of 25 percent over an initial baseline (100 percent) or related cells indicates a performance drop to about 80 percent. When using ac voltage, the measurement can be conductance in mhos, or siemens. As conductance declines, so does a battery’s ability to meet its specified capacity and supply energy. A decrease in conductance of 25 percent over an initial baseline (100 percent) or related cells indicates a performance drop to about 80 percent. In accordance with PRC-005-2, Table 1-4(a), -4(b), and -4(c), some form of battery performance or capacity test should be performed for each battery type. However, the type of test and the required interval for performing the test varies for each battery type. ●● Verify battery performance — Battery performance is verified by evaluating cell measurement against baseline (i.e., internal ohmic values or float current) or performing a battery capacity by load test. For VLA batteries, the load test option is performed at least every six years, and for VRLA batteries, every three years. For NiCad batteries, the only option is the battery capacity by load test performed at least every six years. ○○ Verify battery performance by evaluating cell measurement against baseline (i.e., internal ohmic values or float current). A cell’s internal ohmic value provides useful information in detecting problems and can indicate when a battery or battery cell should be replaced. However, measuring resistance, impedance, or conductance cannot provide a linear correlation to the battery’s capacity. As stated previously, an increase in resistance of 25 percent over

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Maintenance Vol. 3 an initial baseline (100 percent) or related cells indicates a performance drop to about 80 percent. Further, as conductance declines, so does a battery’s ability to meet its specified capacity and supply energy. A decrease in conductance of 25 percent over an initial baseline (100 percent) or related cells indicates a performance drop to about 80 percent. When evaluating battery health, factory internal ohmic measurements should not be used as a baseline for future reference. A battery should be installed and commissioned in accordance with manufacturer’s recommendations, which should include an initializing equalization charge, followed by placement in normal float conditions for a short time before taking baseline measurements. Internal ohmic values can change drastically from factory measurements after a battery is in its operating configuration and has undergone the initial equalizing charge. Regarding float current, the float charging current flowing into a battery string is dependent on the basic cell electrochemistry, the applied charging voltage, the average internal cell temperature, and the string’s state-ofcharge. The normal float charging current is the expected current flowing into a fully charged battery, under a given applied charging voltage, and at a given average cell temperature to keep the battery fully charged. Since the cells are electrically connected in series, the current flow is the same through each cell, although individual cell temperatures and voltages may be different. Therefore, float current reflects the average condition of all the cells in the string. Most manufacturers provide the normal float current expected under specified conditions. Typically, float current increases because of a ground fault on a floating battery system or some type of internal battery problem. Therefore, an increase in float current is indicative of a battery problem. ○○ A battery capacity or load test is the only way to get an accurate measurement of the actual capacity of the battery. The test involves putting the battery on a load bank and discharging the battery while measuring cell parameters, as well as battery performance over time. If the battery meets the load and time characteristics as designed, it passes. A load test should be performed when the battery is first installed. When performed within a time-based maintenance program, the capacity test is also useful in monitoring the battery’s health and estimating the remaining battery life. For substation battery systems, rated capacity values are typically available from the manufacturer.

The following general industrial standards are excellent resources for maintaining and testing the respective battery systems. Additionally, these standards provide specific recommendations associated with the performance of battery capacity tests.

●● IEEE Standard 450-2010, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications; ●● IEEE Standard 1188 -2005, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve-Regulated Lead-Acid Batteries for Stationary Applications; and ●● IEEE Standard 1106 -2005, IEEE Recommended Practice for Installation, Maintenance, Testing, and Replacement of Vented Nickel-Cadmium Batteries for Stationary Applications. As stated previously, below is a copy of NERC standard PRC-005-2, Table 1-4(f), which is provided for information only.

Table 1- 4: PRC-005-2 (f) In summary, utilities are required to develop a PSMP that conforms to the new minimum maintenance activities and maximum maintenance intervals provided in PRC-005-2. Based on a utility’s experience with substation battery systems, the utility should select and implement an appropriate maintenance program to be performed at an appropriate interval. Most substation battery systems use battery systems with vented lead acid (VLA or flooded) or valve-regulated lead acid (VRLA or sealed) battery systems due to the cost and experience with these types of battery systems. However, NiCad battery systems are also in use. Accordingly, slightly different maintenance and testing requirements are provided in the NERC standard for each battery type. PRC-005-2, Tables 1-4(a), 1-4(b), and 1-4(c) provide the minimum maintenance activities and maximum maintenance intervals for these battery systems. Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

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ON-LINE PARTIAL DISCHARGE TESTING: INTRODUCTION TO DETECTION AND ANALYSIS OF ELECTROMAGNETIC AND ACOUSTIC PARTIAL DISCHARGE SIGNALS NETA World, Fall 2015 Issue Louis Nemec, Power Monitoring and Diagnostic Technology Ltd. It’s no secret that insulation breakdown is responsible for the vast majority of electrical failures (see IEEE Gold Book Table 36). Partial discharge activity (PD) usually begins long before a complete insulation failure. PD testing enables discovery of insulation defects before they give rise to insulation failures and unplanned outages.

tively. Virtually all insulation defects can be discovered and localized. This provides an optimum level of insurance for power system managers. A practical approach to on-line partial discharge testing includes measurements of electromagnetic emissions and acoustic emissions, which are emitted as a bi-product of partial discharge. It’s important to consider the ambient electromagnetic and acoustic environment. Phase-resolved measurements are used to compare the incoming acoustic and electromagnetic signals to the power frequency. Partial discharges will always produce electromagnetic emissions in the UHF spectrum and acoustic emissions in the ultrasonic range. Three main types of electromagnetic sensors apply to OLPD, and two main types of acoustic sensor technology apply to OLPD.

Table 1: IEEE Gold Book Table 36 According to IEC 60270, PD testing has been performed offline. These tests can derive the apparent charge (pC) of a PD. However, for many of today’s power systems, insulation tests must be performed on-line while systems remain energized and in service. On-line PD testing incorporates many of the concepts involved in off-line testing. On-line testing works by measuring emission signals, which emit from PD activity with a specific pattern. PD can be quickly detected and confirmed using on-line methods. The apparent charge (pC) cannot be calculated using on-line methods. On-Line Partial Discharge (OLPD) is able to accurately pinpoint and characterize partial discharges. Currently, no global standard is specifically designed for on-line PD tests. OLPD has been around for several decades, yet many challenges and nuances have persisted. Electrically noisy environments and disturbance signals have plagued on-line testing efforts by masking PD signals or producing false-positive results. Many OLPD test instruments have failed to provide sufficient evidence to warrant a service interruption for further inspection or maintenance. Technology available today can overcome the challenges of online testing. OLPD can be performed efficiently and cost effec-

Handheld PD Detection devices are available, which include all of the sensors and analysis modes described. Multi-channel diagnostic equipment may be required to perform certain diagnostic functions involving multiple simultaneous sensors. This paper introduces OLPD concepts and methods. Corona cameras and infrared cameras are also helpful, along with DGA reports from oil samples.

ON-LINE PARTIAL DISCHARGE TESTING: INTRODUCTION TO DETECTION AND ANALYSIS OF ELECTROMAGNETIC AND ACOUSTIC PARTIAL DISCHARGE SIGNALS On-line partial discharge sensor technology includes: ●● Electromagnetic sensor technology ○○ UHF — ultra-high frequency sensor, 300 MHz to 1.5GHz, directional electromagnetic coupling antenna. Measures airborne UHF transmitted from the PD source. UHF signals can be carried on metalwork. Every PD has an emission in UHF spectrum. ○○ TEV — transient earth voltage sensor, three to 100MHz, capacitive coupler, handheld TEV sensor for metal-clad switchgear. ○○ HFCT — high-frequency current transformer, 0.5 to 50MHz, doughnut-sized CT to measure PD pulses on ground leads. These HF pulses can travel dozens or hundreds of feet on ground shields and on the ground grid.

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●● Acoustic Emissions (AE) ○○ Acoustic contact sensor, 20 to 300 kHz piezoelectric sensor — for in-tank PD detection and localization in fluid dielectric, such as oil or SF6. ○○ Ultrasonic microphone(s), 40 kHz center-frequency, airborne ultrasonic — for external, surface PD. Ultrasonic microphone for close range PD detection and localization. Ultrasonic microphones can also be built in to a parabolic dish concentrator for long-range pinpointing. Each sensor technology has certain applications, limitations, advantages, and disadvantages. In general, they can all be applied to substation apparatus, including all types and components of MV and HV switchgear, GIS, transformers, and power cables. Partial discharges are defined in IEC 60270 as “localized electrical discharges that only partially bridge the insulation between conductors and which can or cannot occur adjacent to a conductor. Partial discharges are, in general, a consequence of local electrical stress concentrations in the insulation or on the surface of the insulation. Generally, such discharges appear as pulses having a duration of much less than one µs.”

ELECTROMAGNETIC EMISSIONS UHF (300MHz to 1.5GHz) — A UHF pulse propagates in all directions from the site of the insulation defect. Each time the 60Hz sine wave approaches a positive- or negative-peak, wideband electromagnetic pulses are emitted and transmitted through the air. These UHF signals are detectable with a UHF sensor. The timing of the pulses is in sync with the 60Hz ac sine wave of the grid, which is energizing the system. UHF pulses occur at half-cycle intervals approximately 8.33ms apart or 180 degrees apart.

discharge (PRPD) and 3D phase resolved pulse sequence (PRPS) PD signals appear on PRPS charts as groups of pulses, which occur 180 degrees apart. The magnitude of the pulse depends on the distance from the defect to the sensor and the direction the UHF sensor is facing. Magnitude of measured signal also depends on the nature and location of the defect, whether it is internal or surface PD. The structure of the apparatus will affect the ability of the UHF signal to spread into the air. The incoming UHF pulses are plotted as amplitude versus time (phase angle) on the x-y plane. In 3D PRPS view, the z-axis looks back five seconds into the past. This allows viewing the continuity of the signal in real time.(T=50 means the z-axis is 50 ds, 5000ms, five seconds). The PRPD and PRPS charts are used with UHF and HFCT sensors. Let’s consider how partial discharges happen. What are the mechanisms of partial discharge? Where are certain types of PD activity found? What do different types of PD look like on the phase-resolved display? ●● Floating electrode — is the most common type of PD (see Fig. 1). It occurs when an energized conductor is exposed to another conductive surface of different potential, which is not grounded but is in the electric field between main conductor and ground. It can be metal-to-insulation or metal-to-metal. Floating electrode PD can be caused by loose parts, manufacturer’s defects, or by non-grounded metal within the electric field of the energized conductor. It is often caused by human interaction. For example, conductors are not positioned properly or a foreign or loose object is within the electric field. Floating electrode defects are normally found near the surface. Detectable UHF signal amplitudes are very high. Corona cameras may also be useful to locate floating electrode PD. Not much heat is produced. The sensors that apply: UHF, AE ultrasonic and contact probe, TEV, and HFCT sensors can apply.

Fig. 2: Void discharge depicted on PRPS (Phase Resolved Pulse Sequence)

Fig. 1: 2D and 3D phase resolved charts indicating floating electrode partial discharge activity. 2D phase resolved partial

●● Void discharge — occurs in defects in solid dielectrics such as resins, rubber, polymers, and porcelain. (See Fig. 2) Voids are found in cables, bushings, GIS junction insulation, etc.. Voids are highly destructive to insulation and typically continue to grow until failure. If a void PD is discovered, the insulator might need to be replaced. The sensors that apply are UHF, HFCT, AE contact probe, and TEV.

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Fig. 3: Corona discharge depicted on PRPS (phase resolved pulse sequence)

Fig. 5: Particle discharge depicted on Phase-Resolved Pulse Sequence (3D PRPS) chart

●● Corona discharge — a discharge to air from the surface of an insulator. (See Fig. 3) This activity is destructive to insulation. Mostly appears in the negative half-cycle. Sometimes it can become bipolar (discharges twice per cycle) as it evolves into surface PD. Found in many places on GIS, MV switchgear, transformers, bolted connections and terminations. The sensors that apply are ultrasonic, UHF, and HFCT.

●● Particle discharge — occurs in GIS (SF6 gas) and in oil-filled equipment. (See Fig. 5) Caused when conductive particles contaminate insulating fluids. Allows charges to jump from particle to particle. In GIS, the particles can bounce inside the tank because of vibrations. Applicable sensors include UHF, AE contact probe, and HFCT.

Harmless corona is not an issue, if it occurs on sharp ends or corners of high-voltage conductors. Irregular magnetic field strengths cause some parts of the air to become conductive. Relaxation of excited electrons in these conductive air regions give off UHF and ultrasonic emissions, and possibly, audile sounds. It’s very common on EHV systems.  Ultrasonic dish or corona camera can determine if it originates from the insulator or from the conductor.

Fig. 4: Surface PD depicted on phase-resolved pulse sequence (3D PRPS) chart ●● Surface discharge — destructive discharge along the surface of insulation, also known as surface tracking. (See Fig. 4) Usually, it’s caused by contamination or weathering of an insulator surface. It is different from corona because it tends to track to grounded metal; corona discharges to air. Corona can evolve into surface PD as it becomes more severe. Surface PD can happen on any MV and HV equipment. It occurs when the surface of the insulation breaks down, often in humid environments. Poor equipment maintenance can lead to this phenomenon. Moisture intrusion is also a common cause of surface PD. Applicable sensors include AE ultrasonic and contact probe, UHF, and TEV (low magnitude).

To determine if PD activity is present inside electrical apparatus by use of directional UHF sensor, the incoming signals must be in phase with the ac sine wave (180 degrees apart). They should be nearly continuous, as shown in the Figure 1 PRPS. The source of the UHF signal must come from the HV apparatus. UHF source is determined by comparison of UHF charts at various locations in the substation. A real PD signal has increasing magnitude as the switchgear inspection window is approached with the UHF sensor. The signal should reach peak magnitude when the sensor is pointed into the inspection window or cabinet door seam. High-frequency current (0.5 to 50MHz). Partial discharge pulses also induce a high-frequency current signal onto case grounds of metal-enclosed apparatus. A split-core high frequency current transformer (HFCT) is placed around grounding leads of metal-enclosed MV or HV equipment. The HF currents on the ground grid can be compared to the 60Hz ac sine wave by using phase-resolved measurements. The PRPD and PRPS charts for HFCT and UHF look the same (see Figures 1-5). The type of PD can be determined with HFCT. The magnitude of the HFCT signal can be compared at different locations. HFCT is a reliable method to check for PD inside of oil-filled transformers, where airborne emissions are not likely. TEV high-frequency radio signals (three to 100MHz). These may become present on the switchgear enclosures when PD activity is inside, or when common noise from lighting systems is induced on the switchgear. These are called transient earth voltage (TEV) signals. It can become induced or reflected on any metal work and onto grounded enclosures and switchgear cabinets. TEV is always detectable when PD activity is in metal-clad switchgear, but the signal tends to spread out along multiple, unpredictable paths to ground. TEV usually becomes detectable on all nearby metal work. For this reason, it is usually difficult to locate the source of a TEV signal. A high-level (50 dB) TEV signal may be

34 present on metal posts, fences, and cabinets near the defect. TEV signals are good indicators of PD. However, TEV is also commonly caused by noise from lighting systems. False PD signals from lighting ballasts will produce detectable TEV signals on most metal structures nearby or all over an entire indoor substation. Turning off the lights for a moment is a good way to check if the lights are the source of the TEV signal. Additional information from UHF or acoustic sensors is usually needed to reach a conclusion. Noise is not in phase with the power frequency; it is automatically filtered by the phase-resolved measurements. It’s merely energy in the same bandwidth of the sensor, but has no relationship to 60Hz. It shows up at random points along the x-axis, whereas PD always shows up 180 degrees apart. Disturbance noise: Lighting systems, variable frequency drives, and motors can produce UHF emissions, which also fit the profile of PD signals. These are PD look-alikes. Do not be fooled. Comparison of UHF signal amplitudes can be made from many different locations and directions around the apparatus. UHF signals that resemble PD will become induced onto metal work from nearby lighting systems and motors. Typically, the UHF noise signal will be detected in the air near the switchgear and also far away from the switchgear. When the UHF sensor is pointed into the window of the switchgear, the amplitude of the noise signal will decrease. If PD and noise are present, then the origin of the real PD signal is from inside the switchgear. The amplitude will increase when the sensor is pointed inside the switchgear. In heavy industrial environments, false or look-alike PD signals are common. It is important to compare the change in UHF amplitudes as the sensor is changing locations and directions. Observe the rate of change of the amplitude with respect to the position of the UHF sensor. Simply walk around the station with the UHF sensor while looking at the changes in amplitude on PRPS chart. You will be able to conclude if there is a PD inside the HV equipment or not — usually PD is not present. The origin of the false signal is often related to lights or machines. Occasionally, it is not possible to determine the source of a UHF emission using only one sensor. Level II diagnostic equipment with multiple UHF sensors and time-of-flight measurement capabilities is required to verify the source.

ACOUSTIC EMISSIONS (AE) Mostly ultrasonic and inaudible acoustic energy will emit from the site of the defect. Some of the more intense PD may become audible. Audibility may also depend on the upper frequency limit of your hearing. Airborne ultrasonic emissions. PD at or near the surface of an insulator will produce airborne ultrasonic emissions centered near 40 kHz. Ultrasonic microphones with 40kHz center frequency and detection band from 20 to 80 kHz are commercially available. Airborne acoustic emissions may travel for only a few feet or as far as 40 feet, depending on the magnitude and location of the PD

Maintenance Vol. 3 and the structure of the electrical apparatus. The amplitude of the airborne ultrasonic emission is determined by the point of detection. How far away is the microphone from the defect? Surface PD and corona will produce airborne ultrasonic emissions. The ability of the ultrasonic signal to spread out into the air depends on the structure of the apparatus. Phase-resolved measurements are also used for acoustic signal analysis. The signal should occur twice per cycle — once at the positive wave peak and once at the negative peak. The acoustic waveform should have four distinct peaks on a cycle interval (720 degrees or 33.2ms).

Fig. 6: Phase-resolved waveform of airborne ultrasonic PD signal. The x-axis shows a two-cycle time interval (720 degrees). The Y axis shows the amplitude of the measured signal (mV). In-tank ultrasonic emissions. PD inside of sealed equipment will produce ultrasonic signals in the 90 to 160 kHz range. These are detected using piezoelectric acoustic contact sensors. These acoustic pulses can travel through dense material, such as solid or fluid dielectrics or along metal tank walls. Typically, acoustic PD signals in GIS and oil-filled transformers will be detectable on the exterior walls of the tank; however, they cannot travel through air. Vacuum gel is used to provide a path between the exterior of the tank and the acoustic emission sensor. Acoustic/ultrasonic testing provides the ability to precisely locate PD sources. If the signal is airborne, the parabolic dish concentrator can isolate the PD emission using amplitude comparison. When a PD is inside of GIS or inside of a transformer, an amplitude comparison may lead you close to the source. Level II diagnostics can utilize multiple acoustic sensors. If PD is in between two sensors, then the Time Difference of Arrival (TDOA) method can determine the plane of the PD. A third measurement in the other plane will give the exact position of the PD fault. In addition to electromagnetic and acoustic emissions, PD can also produce — and therefore be identified — by recognizing the presence of three physical phenomenon: ○○ Light – sometimes visible, sometimes not. Arcing may be visible, but you probably don’t have visual access to the location of the activity. For overhead insulators, use a co-

Maintenance Vol. 3 rona camera to see UV emissions. The UHF sensor also overlaps into the corona/UV spectrum. ○○ Heat – release of low levels of infrared energy. Infrared cameras are readily available. When conductors have issues, the resistance goes up and hot spots appear on the camera. But when PD occurs in the insulation, only a small temperature rise occurs. Typically, IR inspections overlook most PD. Actually, IR and PD inspections complement each other quite well. PD is for insulation as IR is for conductors. Look for a very slight temperature rise, e.g. one to four degrees F. ○○ Chemical – ozone, verdigris-nitric acid (nitrous oxide + H2O), hydrogen gas in oil, combustible gasses in oil, other gasses with odor, SF6 decomposition products. DGA oil insulation and SF6 tests can indicate PD activity, but these samples cannot locate the PD specifically. PD near the surface of insulators may leave track marks, burn marks, white powder, or other visual evidence. However, it’s not easy to spot these signs unless one knows exactly where to look before opening any cabinets or inspecting. When a PD is suspected by electromagnetic or ultrasonic detection, it is likely that some chemical evidence will be observable when the apparatus is inspected. Synthesis of information from each sensor is the key to OLPD. Typically, a single instance of PD can be detected by more than one of the sensor technologies discussed here. Electromagnetic and acoustic tests will usually agree and confirm each other. Most PD can be detected and localized using the concepts outlined in this article. In part two, more advanced concepts that apply to Level II PD diagnostics will be discussed. Cable testing and PD signal separation techniques, analysis of waveforms, time-of-flight measurements, 3D localization, and modern instrumentation will be covered. Louis Nemec attended Georgia Institute of Technology where he studied electrical engineering and chemical engineering. In 2009, he earned his bachelor’s of science with a major in analytical chemistry from Georgia State University. Since that time, Louis has been working in the high-voltage test and measurement field for over six years. He spent four years as a technical representative for ProgUSA where he gained experience with testing and maintenance of high-voltage and medium-voltage power transmission and distribution systems. In 2013, he became involved in the sales of partial discharge test equipment. In 2015, Louis joined with Dustin Ashleigh to manage a global sales network for Power Monitoring and Diagnostic Technology Ltd., a company dedicated to partial discharge detection and diagnosis of insulation defects.

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THE TRILLION-DOLLAR CABLE QUESTION NETA World, Spring 2016 Issue Alan Mark Franks, Avo Training Institute

lasting 10 to 15 years before failing. Tree-resistant cross-linked polyethylene (TRXLPE) came on the scene in the late 1990s for most utilities. TRXLPE is an enhanced XLPE that increases resistance to the water treeing process, increasing cable life to 20 to 30 years. Most utilities realize that many of these cables today are at or over their expected life. Many utility companies are in the beginning or middle stages of providing high-tech rejuvenation processes to extend the cables’ life or are planning complete replacement of these cables in bulk quantities at significant costs.

A trillion dollars is a conservative estimate when you consider the magnitude of the power cable issues in the U.S. It has been known for some time that the cable systems in the U.S. have reached — and in many cases, exceeded — their life expectancy. Let’s face it: Wholesale replacement of an underground cable installation is expensive, time consuming, and results in off-hour scheduling and clearances, requiring customers to be without power during reconnection of power to the installation. Much has been published about the failures in cables, splices, and terminations, but more still needs to be said about the aging power cable issue. Analysis clearly states the issues with service-aged polyethylene, the concentric-neutral (CN) cables that were the mainstay for utility installations in the mid 1960s through 1980s (initially HMWPE or high-molecular weight, and then XLPE or cross-linked polyethylene). Thought to be the answer to many installation issues, these cables turned out to be a major disaster due to reliability and replacement costs. Much of this CN cable had no jacket to protect it from the environment or installation damage — much less water, the culprit of the century where polyethylene insulation is concerned. In defense of the manufacturers and utility engineers, no one knew what was to ensue between water and polyethylene insulation (the formation of water trees in the insulation). Since this condition is slow to develop and much slower to reach total insulation failure via the formation of full-blown electrical trees, it was not evident early on that these cables, which were expected to last 30 to 40 years, would only last half of that time — many only

As utilities and industries with large cable systems are at various stages in addressing the issues with service-aged polyethylene-insulated cables, the question that keeps coming up is: What is the condition of my cables? This leads to a second question about how to determine the conditions of cables. The first question is really about how to manage the cable system or defining a good asset management strategy for the cables. The second is about specific techniques to actually determine the condition of each cable. Another critical factor to proper cable system management is the human factor, which is discussed a bit later.

CABLE SYSTEM ASSET MANAGEMENT Recently, an engineer in a large utility was given the overall management responsibility of a $150 million cable replacement project. This is a large opportunity with the potential for a huge success — or, without a planned approach that involves determining a replacement philosophy — it could result in financial disaster. Some concerns are: ●● How much cable are we talking about? 10K feet? 500k feet? 500 miles? ●● What kind of cable, when will it be installed, what size, voltage, etc.? ●● What is the history concerning the cable plant? ●● What is the mode of construction — direct bury, in conduit, aerial, duct systems, etc.? ●● What is the ultimate cost of materials and labor? ●● Are competent labor forces available? ●● At what point in the life cycle is the cable under consideration? (This is a big question.)

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Maintenance Vol. 3 ●● What is the criticality of loads? ●● What methodology will be used to determine condition and priority of replacement? These questions deserve infinitely more than discussed here. The point is the importance of developing a philosophy concerning cable management.

DIAGNOSTIC TESTING This brings up diagnostic testing and the condition term in the management topic. For years, cables have been proof tested for acceptance and maintenance tested employing an age-old technology known as the dc hipot. This technology has been used successfully for decades to test and retest cables using paper insulation lead cable (PILC). It is inexpensive, easy to use, and appears to be the logical choice to continue to test new and service-aged cables of the extruded insulation design. However, the Electric Power Research Institute (EPRI) concluded that this approach is the wrong choice. EPRI found that service-aged polyethylene (and EPR) cables already in the stages of insulation tree formation would develop space charges that remained in the insulation after testing, and when reenergized with line frequency, could hasten failure. This was a significant revelation in the cable industry, as there was not a proven alternative and no industry consensus standards provided alternative guidelines for testing. As a result, many companies halted testing in any form, and new and service-aged cable systems went without any acceptance or maintenance test at all. (Enter the Dark Ages for cable testing.) Today, however, we have current industry standards such as IEEE 400 Bundle Series and the ANSI/NETA standards providing guidelines for withstand (acceptance) tests and diagnostic tests for troubleshooting, trending, and diagnosing cable condition. These new testing technologies evolved due to the need for diagnosing the condition of service-aged cables in the U.S. and other countries with the same cable issues. With the issue using dc test voltages previously discussed and the requirements for using 60 Hz line frequency for testing high capacitive cables of long length (large, expensive equipment), very low frequency (VLF) testing has become a popular technology. VLF is used to perform withstand (acceptance) proof tests as well as dissipation factor (VLF Tan Delta) diagnostic tests. VLF Tan Delta, used in conjunction with the partial discharge test, has proven a successful method for analyzing the condition of service-aged extruded dielectric cables (XLPE and EPR) while avoiding the space charge issue of dc testing. Numerous manufacturers in the U.S. and other countries make all manner of test units to perform diagnostic testing. Industry consensus standards support the technologies and provide guidelines for utilities and industries in the U.S. to administer effective testing programs to address the complex issues concerning underground power cable installations. The test method applied and the specific

equipment employed is usually predicated on how the information will be used. Ultimately, the information generated by the testing program becomes a critical component in the cable asset management decision-making process.

THE HUMAN FACTOR The complexity of the new testing technologies, evaluation of test results, and importance of sound installation practices leads to the final topic of discussion: the human factor. Considering the cost and importance of electrical systems in the U.S., we must ask this question: In all of the plans and technology improvements for our cable systems, where have we provided for the safety, technical, and skills training for our human resources? It’s a good question, considering the millions of dollars being spent on new cable, new technology, new test equipment, and methods. With all the planning and technical issues to address, it’s easy to overlook the one resource that is going to ensure the same mistakes are not made over and over in the future. Studies by the National Electric Energy Testing Research and Application Center (NEETRAC) at Georgia Tech point to a major cause of cable failures in the U.S. being tied to poor workmanship issues during cable pulling, splicing, and terminating. As this is well documented, it is reasonable to expect that without a change in direction, the same results will be repeated. The millions of dollars spent in insulation rejuvenation, cable replacement splicing, and termination will not have the expected positive effects in service reliability, revenue, and reduced costs. The outcome will be dismal, and ultimately, the cable installation workmanship issue will be revisited, most likely at much higher costs. Ensuring excellence in workmanship and proper application of the technologies for cable installation and testing requires significant training and demonstration for the workers involved. One of the most important aspects of cable work is the absolute requirement for safety. Workers are routinely involved with power systems that were or could become energized. Many times, the technician is working in one section of switchgear and adjacent switchgears on either side will still be energized. Most of the high-voltage and high-power test equipment used in withstand and diagnostic testing of power cables can produce lethal shock, thus requiring significant safety precautions to ensure the safety of all workers involved in the testing or in the area where testing is being performed. OSHA 29 CFR 1910.269 (o) Testing and Test Facilities provides regulations for workers involved in high-voltage and high-power testing. OSHA further mandates that employees must be trained prior to performing this type of work. Numerous other regulations and standards related to maintenance and testing of power cable systems must be incorporated into the safe work practices and training for working on or near power cable systems. Training in proper cable handling, splicing, and terminating of power cables is necessary, or the same failure modes will reappear

38 in the future. It’s been said many times that about 90 percent of the integrity of a splice or termination is in the cable prepping. Many of the splice or termination failures occur because of inappropriate cable preparation, either by misapplication of the products and tools or some human error in removing and dimensioning the cable layers. Modern splicing kits come with detailed instructions but do not provide the experience nor show the proper tooling for performing the steps of successful splicing. Splicing and terminating of power cables is a craftsmanship issue and must be addressed with a significantly experienced, hands-on mentor or instructed by very competent cable personnel. A significant effort is currently underway to address the issue in large U.S. utilities, as many of their experienced cable personnel have retired and are no longer available to provide the much-needed mentorship to junior personnel. Ramping up cable splicing training, certification, and demonstration of skill and testing technology is a necessity, as we move into a future where reliability and cost of maintenance are significant issues. Diagnostic testing using a partial discharge test set and software to analyze the test data is a long way ahead of technology from a megohmmeter test and a dc hipot test. Test technicians have to be trained not only in all the safety aspects of the job, but also in the technology of the test and how to use the test equipment. Not only is diagnostic testing an issue, but cable fault location is as well, due to technology enhancements in that type of equipment and the constraints of locating faults on service-aged cable systems.

CONCLUSION In summary, we must consider all aspects of a well-planned cable management program. It is imperative that the cable is analyzed to accurately assess its condition. Service-aged cables must be examined and tested to recognize the need for corrective action. Cables have to be tested and prioritized according to condition, using the latest in diagnostic testing technologies. Decisions concerning replacement and rejuvenation should be made by using test data and cable experience. One of the most important parts of the overall cable puzzle is the human factor. It doesn’t make good business sense to install millions of dollars of new cables, purchase expensive test equipment, and repeat the same workmanship issues that will result in the same types of cable failures previously experienced. Of course, safety of personnel is the most important factor, and significant attention must be focused on personnel involved in high-voltage and high-power testing. Safe work procedures, personal protective equipment, live line tools, personal protective grounds, and work area protection are only a few of the items that require training.

Maintenance Vol. 3 REFERENCES Hampton, Nigel and Josh Perkel, NEETRAC; Matthew Olearczyk, Electric Power Research Institute; Neil Weisenfeld, Consolidated Edison NY. Notes From Underground, IEEE Power and Energy Magazine, November-December 2010 Williams, Dean, NEETRAC. Cable Accessory Failure Analysis, ICC Educational Session, Fountain Hill, Arizona, October 1620, 2010 Diagnostic Testing of Underground Cable Systems (Cable Diagnostic Focused Initiative), NEETRAC Project Numbers: 04211/04-212/09-166), December 2010 Effect of DC Testing on Extruded Crosslinked Polyethylene Insulated Cables — Phase II, Product ID: TR-101245-V2, Sector Name: Power Delivery & Utilization, December 1, 1995 Alan Mark Franks is a Senior Safety Specialist at AVO Training Institute. He has over 48 years in the electrical utility industry with an extensive background in electrical safety and power distribution. Mark was instrumental in developing the Pre-OSHA Electrical Safety Audit for industry and the conducting of on-site audits of facilities, installation of electrical equipment and systems, safety procedures, and training records and programs, all based on OSHA and NFPA regulations and other industry consensus standards. He has been an authorized OSHA Instructor for all general industry and construction regulations. Mark is a certified fiber optic technician, certified fiber optic instructor (#839, and a member in good standing of the Fiber Optic Association. His participation in numerous associations include NFPA 70E 2000 Alternate Committee member, International Association of Electrical Inspectors, American Society of Safety Engineers, National Cable Splicer Certification Board, and American Society for Testing and Materials. Mark has provided electrical safety training and performed electrical mine safety audits for general industry, utilities, and mines both underground and surface. He has instructed all aspects of power cable splicing, termination, testing, and fault location for 25 years and has been instrumental in developing the AVO Training Institute Cable Technician Certification Program.

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LESSONS LEARNED FROM A 400KV BUSBAR MISOPERATION USING THE IEC 61850 STANDARD NETA World, Summer 2016 Issue Dhanabal Mani, Vijay Shanmugasundaram and Jason Buneo, Megger The implementation of the IEC 61850 standard for substation design and commissioning is rapidly becoming the dominant method of defining grid protection schemes throughout the world. The protection logic that involves dc control circuits is executed internally in the intelligent electronic devices (IEDs) and effectively communicated between the IEDs via Generic Object Oriented Substation Events (GOOSE) messages. Any error in the mapping of GOOSE signals will result in undesired operation of the protection schemes. The main buses in power substations are designed to carry load currents through the individual feeders, as well as high amplitude currents during bus fault conditions. Any delay in fault isolation or improper relay operation could result in severe damage to the substation buses and the equipment connected to them. Therefore, proper design and testing of the bus-bar protection scheme is required to ensure safe and reliable operation of the substation. The complex protection schemes such as bus-bar and breaker-failure protection are relatively easy to design using the modern IEC 61850 standard. However, the implementation of these schemes in the real world poses certain unique challenges. This article discusses the investigation of the tripping of a 400 kV substation due to improper operation of a bus-bar protection scheme. This incident happened when a zone two fault occurred on one of the 400 kV line feeders, immediately triggering a breaker-failure condition. Under a normal trip scenario, the zone two timer will time out and the line IED will issue a trip signal to the line breaker to isolate the fault. The line IED will also then issue a breaker-failure initiate (BFI) signal to bus-bar IEDs through GOOSE messages. The breaker-failure condition is only declared when the line breaker fails to trip within a specified breaker-failure time. However, in this case, the breaker-failure condition was initiated before the zone two timer expired instead of after. An investigation was carried out to determine the reason for declaring a breaker-failure condition even before zone two tripping of the line IED. Further analysis of the IEC 61850 network and GOOSE configurations led to the conclusion that the BFI signal was mapped incorrectly. The bus-bar IEDs were configured to receive a BFI signal through GOOSE messaging for a fault pick-up signal instead of a fault-trip signal by protection IEDs. This minor error caused the entire substation to be out of service. This article discusses testing methods that would help prevent this situation.

INTRODUCTION The protection schemes used in substations are implemented through protective relays from various manufacturers. Legacy systems that use electro-mechanical relays share critical information such as breaker status, interlock signals, etc., through a network of copper wires monitored by some control center. With the advent of IEDs, data sharing between protective relays and control centers has become possible by using Ethernet and fiber optic cables. This has reduced the amount of copper necessary in substations, making them cheaper to produce and maintain. However, the interoperability between different relay manufacturers has become increasingly difficult, as many IED manufacturers have adopted proprietary standards for data representation and interpretation. In 2005, a common standard was first published by a shared effort from IEC 60870-5-101, -103, -104, and Utility Communication Architecture 2.0 (UCA 2.0), and called IEC-61850. The IEC-61850 standard allowed direct communication between IEDs from multiple vendors in a substation. The IEDs in a substation followed an abstract model for data definition, which could be interpreted by all the compliant manufacturers. A local area network (LAN) switch connected between IEDs passed the data as GOOSE messages. These messages contain essential information such as control signals and acknowledgements. The implementation of the IEC-61850 standard through LAN-based architecture considerably increased the reliability and speed of peer-to-peer communication. Also, a complex protection scheme could be implemented easily through the LAN-based design without increasing the complexity of physical wiring. A protection scheme is implemented by configuring the IEDs to send or receive GOOSE messages from other substation equipment. Depending upon the complexity of the protection scheme implemented, a GOOSE message could pass through a number of switches until the destination IED is reached. After analyzing the received message, further actions are carried out by the destination IED. A redundant network in LAN design prevents data loss by re-routing the path taken by the messages. Numerous network topologies have been adopted to maintain an un-interrupted data flow from the source IED to the destination IED. An IED in the substation can send or receive GOOSE messages to or from many different IEDs in the network. The proper mapping of GOOSE messages between IEDs is essential for execution

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of a protection scheme. The number of signals mapped depends on the number of IEDs and the elements of the protection scheme being implemented in the substation. The IEC 61850 standard ensures that the control functions and message flags seen on the communication network will be the same no matter which manufacturer device is used. However, mapping the IED’s internal logic to the IEC 61850 standard can be tricky, and great attention to detail must be maintained.

change the information to remote network control centers using IEC 60870-5-101 protocol. The bay level system consists of all circuit breakers, current and potential transformers, power transformers, and protective relays. IEDs in the bay level perform all functions including control, monitoring, and protection. The data exchange between bay level and station level happens with fiber optic ring connection according to IEC 61850-8-1 protocol.

THE SYSTEM A newly constructed 400kV IEC 61850 substation was fully commissioned prior to the work on this article. It consists of six D-configuration systems, referred to as a DIA by the customer, and is provided with a distributed busbar protection scheme as per Figure 1. A D-configuration system has three circuit breakers with two outgoing circuits; one circuit is for line and the other circuit is for transformer or bus reactor. Both circuits could be lines as well. For circuit breaker maintenance of any line, the load gets tranferred automatically from one bus to the other bus. No changeover of the line from one bus to another is required. For any bus-fault conditions or scheduled maintenance, all interconnections will be on the healthy bus, and no disturbance will come to the other circuits. Even if both buses become dead, circuits can remain in service through the tie circuit breaker. This is very advantageous in maintaining system stability.

Fig. 2: Bay and Station Level IEC 61850 Communication Architecture This busbar protection scheme is implemented for Main Bus I and Main Bus II. All bay control units are connected with fiber optic cable to their main busbar relay for transmitting each bay’s load current values, isolator, and breaker statuses. An equivalent single-line digram of the substation is configured in the busbar main IEDs for proper replication of the substation and for ensuring correct decision making in the protective scheme. In the case of a bus-fault or breaker-failure condition, the main busbar IEDs make the decision to isolate the faulty feeders by sending a trip command to the bay IEDs and, in turn, the bay IEDs trip the respective bay circuit breakers. This data sharing occurs within the busbar protection relay network; these trip signals are also sent as GOOSE messages over the IEC 61850 bus.

IED ENGINEERING AND SYSTEM LEVEL ENGINEERING Fig. 1: 400kV Substation One-Line Diagram The IEC 61850-based substation automation system (SAS) architecture used in this substation is shown in Figure 2. This architecture is defined in two levels as station level and bay level. A redundant PC-based human-to-machine interface (HMI) is used to control the subsation at station level, which supports communication over IEC 61850-8-1 bus as an IEC 61850 client. An IEC 61850-8-1 inter-bay bus provides station-to-bay and bay-to-station exchanges. In this case, an Ethernet LAN is set up with ring configuration to maintain reliability, availabilty, and interoperability requirements of the system. Reduntant gateways are used to ex-

The IED engineering process involves configuring the protection functions, interlock logic, metering functions, etc., in each of the IEDs. This process is shown in Figure 3. The IED configuration description (ICD) file is then exported from each IED, into the substation configuration language (SCL) file. The SCL output contains the IED’s capabilities (logical devices, logical nodes). It also reports the control blocks available in the ICD files that are used as inputs in the system-level engineering design. Configuration tools are used to set up the communication between various devices. The transmission of the data sets is decided by the report control blocks. Also, GOOSE messages are configured in the system-level engineering tool with GOOSE control blocks.

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Maintenance Vol. 3 400KV SUBSTATION COMMISSIONING

During commissioning of the substation, the protection IED’s operation, busbar protection, and all other trip logic were verified to be in proper working order. Later, an additional bay was added to the existing system. All of the protection schemes associated with the new bay were verified as well.

Fig. 3: Engineering Process for Configuring IEDs in a GOOSE-Enabled Substation Ethernet switch configurations are then defined and downloaded into the switches. In this IEC 61850 network, GOOSE messages have priority over other messages, so Ethernet switches are necessary to support the IEEE 802.1P standard for priority tagging. Finally, once the system-level engineering is completed, the SCL file is re-imported back into IEDs, where all the configured GOOSE inputs coming from other IEDs are connected to the correct functions. Once the configuration is downloaded to the individual IEDs, the complete system architecture is defined. Using the isolator logic, the busbar relay is capable of identifying and isolating respective feeders connected with the faulty bus. Also, this busbar scheme is combined with breaker failure protection. Any protection trip of respective bay protection IEDs will send a trip signal to respective busbar bay IEDs to initiate the breaker failure protection (Figure 4). If the breaker fails to trip, this action will cause a breaker-failure protection trip with BFI initiation and timer timeout. In IEC 61850 substations, a BFI signal may be configured as a GOOSE message from the protection IEDs to the breaker failure protection relays. The busbar IED will trip all feeders connected with the bus of the faulty feeder. Fault selection is processed by the busbar main protection IED with isolator staus [1].

After successful commissioning of the new bay, a feeder was connected to Bus I. Subsequently, there was a zone two line fault on the newly added 400kV line. Both Main I and Main-II distance protection relays in the substation sensed the fault correctly on zone two and started the zone-two timer. The zone-two trip timer is set for 300 ms. It was observed that the busbar protection relay operated within 200 ms for this fault and tripped the feeeders connected with Bus I and Bus II, thereby causing the entire 400kV substation to be taken out of service. After careful physical inspection of the substation and busbar protection relays, it was determined that there was no real bus fault, and the busbar relay had misoperated due to improper breaker-failure protection. The BFI signal was sent to the busbar IEDs through a GOOSE signal. After careful analysis of the IED GOOSE configuration, it was found that the newly added bay had distance-protection GOOSE messages configured with a start signal for breaker-failure initiation instead of a trip signal. Since the breaker-failure initiation started the function block timer with a start input, its timer operated within 150 ms instead of waiting for the 300 ms zone two timer to expire first. This caused the breaker failure to trip before the zone two timer. Due to this small mistake, both the Main-I and Main-II protection operated, leading to an entire substation blockout. The erroneous logic is shown in Figure 5.

Fig. 5: Breaker Failure Scheme Operation Logic with Improper Configuration

Fig. 4: Breaker Failure Scheme Operation Logic

Figures 6 and 7 show the signal configuration of the GOOSE assignment for the breaker-failure initiation sent to busbar protection IEDs. This signal configuration is defined in the IED-level engineering and in the main-line protection IEDs. Figure 6 shows a simulation example of the wrong GOOSE configuration for breaker-failure initiation. In this case, the zone two start signal has been assigned to breaker-failure protection initiation as a GOOSE output. Whenever a zone two fault occurs, the zone two start signal

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will send a BFI and cause a breaker-failure trip before the zone two timer completes and clears the fault. Figure 7 shows the simulation example of the corrected GOOSE configuration for breaker-failure initiation. In this scenario, if there is a zone two fault, the breaker-failure protection will not send any GOOSE signal to the busbar IEDs from the main protection IEDs to initiate the breaker-failure trip. The IED will send a GOOSE signal to the bus bar IEDs only when there is a trip issued by the protection IEDs.

Figure 9 provides an example where the GOOSE signal color is red. It indicates that this signal is high and that the protection function has operated; therefore, this GOOSE will register when the distance protection trip goes high. The mapped IEDs that use this GOOSE signal will process and operate accordingly.

Fig. 6: Example of Incorrect IED GOOSE Configuration Fig. 9: GOOSE Monitoring, Operation of Protection Function

Fig. 7: Example of correct IED GOOSE configuration It is necessary to test the IED’s protection schemes and GOOSE signals properly before commissioning the IEC 61850 substation or adding additional bays in the existing IEC 61850 substations. It is fairly easy to verify copper wire schemes for breaker-failure protection schemes or other protection schemes when adding additional bays into service in a conventional substation. In the case of IEC 61850 substations, it requires special care. GOOSE-monitoring software can test an IED’s GOOSE configurations before putting IEDs and bays into service. Importing the SCL file of the IED under test into the GOOSE monitoring software can assist in verifying the GOOSE signals as required. Figure 8 shows one of the trip GOOSE signals from a distance protection IED. The purple font in this particular data set indicates the non-operation of the distance function and that its signal status is low. This means that this GOOSE signal will be seen by other relays in the substation as non-operative.

With reference to Figure 8 and Figure 9, any GOOSE used in protection schemes can be tested and verified without any risk of misoperation of the relays or unwanted interruption of the substations. The BFI GOOSE signals have been corrected from a start signal to a trip and downloaded to the distance protection IEDs. Since there is no change in data sets, it is not required to update the system-level engineering in the substation level (Figure 3). Necessary validation of signal mapping and GOOSE configuration in line with substation configuration is required in any IEC 61850 substation when adding new bay/feeders into the existing substation.

CONCLUSION IEC 61850 substations are increasing in use throughout the world. Necessary testing procedures, such as one of the methods discussed in this article to validate IEC 61850 GOOSE mappings, are required to follow the commissioning of those stations for proper operation. More challenges lie ahead in IEC 61850 substations, especially when adding additional bays into service within existing IEC 61850 substations. As always, additional care is required at the commissioning stage for any substation.

REFERENCES Krishnan, Rajiv and Bapuji Palki. “First Experiences with Design and Engineering of IEC 61850 Based Substation Automation Systems in India,” CEPSI 2006 Conference, Mumbai, India, November 6 - 10, 2006.

Fig. 8: GOOSE Monitoring, No Operation of Protection Function

Dhanabal Mani received his Bachelor of Electrical and Electronics Engineering from Bharathiyar University, India, in 2001. He commissioned the first 400kV IEC61850 substation in India in Madhya Pradesh as a Lead Commissioning Engineer of the Substation Automation Group at ABB India Ltd. He has also developed custom relay applications as a R&D engineer at

Maintenance Vol. 3 ABB Ltd, Sweden. Dhanabal joined Megger India as an Application Manager in August 2009 and is presently based in Dallas. He has over 13 years of field experience in protective relaying and commissioning, and has published numerous articles and presented at various international conferences on the subject. Vijay Shanmugasundaram received his Bachelor of Technology with distinction in Electrical and Electronics Engineering from Amrita University, India, in 2008. He joined the Defense Research and Development Organization (DRDO) of India as a junior research fellow, specializing in the performance optimization of induction motors. In 2011, Vijay received his Master of Science in Electrical Engineering focusing on power systems, from North Carolina State University. As a part of this program, he worked on IEC61850 substation development in Siemens’s Energy and Automation department. Vijay joined Megger as an Applications Engineer in December 2012 and is currently working on developing IEC61850 applications. He is an active member of IEEE and EPRI, participating in conferences and contributing to the working groups. Jason Buneo received his B.S and M.S in Electrical Engineering from the University of Buffalo. In 2005, he joined GE Energy Services as a Field Service Engineer. He specialized in arc-flash coordination studies, protective relay testing and calibration, and low-/medium-voltage switchgear repair. In 2008, he joined Megger as an Applications Engineer where he assisted Megger’s customer base in their relay testing needs. He became the Applications Development Manager in 2012 and now specializes in developing automated testing applications for protective relays.  Jason continues to work closely with utility and industrial customers to develop new testing solutions. Jason has published several technical papers in industry journals and conferences and is active in the IEEE Power Systems Relaying Committee.

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UNDERSTANDING AND MAINTAINING CRITICAL SERVICE EQUIPMENT NETA World, Fall 2016 Issue John Weber, Hartford Steam Boiler Inspection

All institutions and businesses strive to maintain a reliable and consistent level of service to their customers. Many also establish disaster and recovery plans for unexpected natural disasters or other crisis situations. An often overlooked but foreseeable disaster is the failure of the main electrical service switch for the facility.

the service equipment makes it very difficult to tie in a standby generator at a single termination point. Sometimes the feeder sections need to be subdivided or isolated from the busbars for the standby generator tie in. Recovering from service equipment failures typically includes costs for generator rental and fuel oil, generator power cable rental, overtime electrical trade labor, additional security guard coverage, and equipment transportation. The analysis shown in Figure 1 highlights the total cost associated with standby generator requirements. When long-term outages are expected, temporary transformers or rerouted service conductors may be more cost effective than running generators. Keep in mind that all of these costs are only for the temporary emergency reestablishment of power.

Photo 1: The main switch of a facility can fail catastrophically if the manufacturer’s required maintenance is ignored. Extended loss of electrical power to a facility due to catastrophic equipment failure usually disrupts all business function and creates many unexpected and unplanned expenses. Most service equipment failures are preventable by following manufacturers’ maintenance recommendations or requirements for the installed service equipment. Electrical equipment failures should be included in the disaster plan, and the process begins with conducting an electrical equipment failure risk assessment. When performing an electrical equipment failure risk assessment for a facility, one of the most important considerations is the reliability of the service equipment. The National Electrical Code, NFPA 70-2014 Article 100 Definitions defines service equipment as: The necessary equipment, usually consisting of a circuit breaker(s) or switch(es) and fuse(s) and their accessories, connected to the load end of the service conductors to a building or other structure, or an otherwise designated area, and intended to constitute the main control and cutoff of the supply. When the service equipment fails to perform as intended or fails catastrophically, a complete shutdown of all business activities occurs. A catastrophic failure usually results in expediting standby generators to the site and the use of many electricians working around the clock to re-establish power to the facility. Damage to

Fig. 1: Standby generator rental cost is a fraction of the total cost associated with the use of a temporary generator installation. Additional time and expense is expended working with designers and electrical contractors to determine the extent of the damages and solutions for permanent equipment replacement. Catastrophic service equipment failures are often accompanied by electrical

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equipment meltdown, fire, smoke, and water damage. Depending on the degree of equipment failure, major NEC-code upgrades may be required for the equipment room and electrical equipment before it can pass current electrical and building code requirements.

After a service equipment failure of this magnitude, owners, contractors, engineers, and facilities managers quickly assemble to try to understand how this could have happened. The discussions usually include questions such as:

Required code upgrades can create additional unexpected expenses. Depending on new or used equipment availability, final electrical and building repairs can take weeks or months. In addition to all of the costs for temporary and permanent electrical repairs, the occupants typically suffer a major business interruption. Many key personnel are diverted to expediting activities and emergency resolutions of the current business crisis. Who is left to manage the day-to-day business, and how many customers’ needs are not being met because of this unexpected and untimely electrical failure?

●● Was an electrical risk assessment ever conducted for the site?

Knowing that all of these costs typically follow an unexpected service equipment failure, the best solution is to avoid the failure in the first place. This requires that the owner is aware of the type of installed electrical equipment and the maintenance requirements specified by the equipment manufacturers. As with any type of service equipment, if the manufacturers’ maintenance requirements are ignored, the consequences can devastate a business and result in unrecoverable business losses and crushing financial burdens. One common type of service equipment switch used by a wide range of occupancies is the bolted pressure switch. By evaluating the results of a catastrophic bolted pressure switch failure, the importance of proper service equipment maintenance becomes evident. No business owner wants to respond to an emergency call at their facility to find a bolted pressure switch failure. The bolted pressure switch failure shown in this photo occurred catastrophically with all of the consequences described previously.

Photo 2: Proactive review and execution of main switch maintenance requirements can help prevent switch failures, power outages, and costly business interruptions. What caused this to happen? How could ignoring required maintenance on this switch result in such total destruction of the switchgear? What could have been done to prevent this catastrophe?

●● Were electrical experts included in the risk assessment process? ●● Was there an awareness that the electrical equipment required periodic maintenance? ●● Was any preventive maintenance ever performed on the service equipment? ●● Was it known that a bolted pressure switch was installed on the premises? ●● Were the manufacturers’ service requirements and frequencies known? ●● Were qualified electrical personnel employed at the facility to evaluate and design a comprehensive electrical preventive maintenance program? ●● Was there an awareness of the potentially catastrophic consequences of not performing the manufacturers’ maintenance recommendations? Knowing that service equipment failures typically follow this response pattern, what can be learned in the interest of prevention? After a disaster has occurred, there is always great interest in what can be done to prevent a recurrence. The real benefit of this discussion is to forewarn owners and facilities managers to proactively consider all of the above questions before a catastrophic service switch failure occurs. As an example, bolted pressure switch manufacturers typically require annual inspection and lubrication of the conductive blade parts and the operating mechanism. Depending on the presence of adverse environmental conditions, such as excessive temperatures or dirty or wet conditions, more frequent inspection and maintenance may be required. If a bolted pressure switch is involved in an event where fuses have blown or if it has interrupted a ground fault, a complete switch inspection should be performed. One manufacturer states that, after a switch has interrupted a fault, switch design standards indicate that an unserviced switch is not suitable for reuse. After a fault opening, contaminated lubrication may need to be removed; pitting, splatter, and weld marks may need to be addressed; and arc quenchers and barriers may need inspection and repairs. Contamination from the fault may prevent proper future operation of the opening and closing mechanisms. Each manufacturer provides additional details for the type of lubricants to use for the cleaning and re-lubrication process to follow. Switches should include a riveted nameplate with a large font size and bold lettering to stress the importance of this requirement. Note that the instructions use the word required versus recommended.

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Photo 4: Lack of proper maintenance prevented this switch from closing and clamping completely. Photo 3: Annual lubrication is stressed by the manufacturer on this nameplate. Many owners and facility managers believe that the main switch is “maintenance-free.” Many facilities use bolted pressure switches as the main service equipment for the facility. Annual inspections and servicing of these switches requires planned shutdowns. NFPA 70E, Standard for Electrical Safety in the Workplace requires electrical equipment to be deenergized, locked out, and tagged out before performing electrical work. NFPA 70E also requires personal protective equipment (PPE) for electrical workers. The frequent requirement for annual maintenance on a bolted pressure switch often conflicts with the typical needs of most businesses trying to maintain continual uptime for 24/7 productivity reasons. Options exist when replacing bolted pressure switches with a circuit breaker and can be accomplished without purchasing all new switchgear enclosures. The benefit of the retrofit is that, under normal operating conditions, many new circuit breakers allow for significantly longer maintenance intervals. The differences in the vulnerabilities of the mechanical operating mechanisms account for the extended maintenance-interval requirements. This can be a good option when it is impractical or logistically complicated to perform frequent annual maintenance on bolted pressure switch service equipment. Not performing the required maintenance on a bolted pressure switch should never be an option. Bolted pressure switches typically have two movable blades per phase. When the switch blades rotate vertically to the closed positon, the two movable blades straddle the upper stationary contacts. With continuous motion, the three pairs of movable blades are clamped tightly at the stationary contacts and at the lower hinge points of the switch blades. The clamping action is usually achieved by rotating a screw that is linked to the switch-closing mechanism.

The insulated crossbar picture shown here indicates that the crossbar arm did not complete its stroke. The bar is at a 45-degree angle; it should be in the vertical position when fully closed and clamped. If the required maintenance is not performed, an event like the one seen in this photo can occur. In this case, the switch mechanism did not complete its full stroke to close the blades and clamp them properly. As a result, the switch operated with high-contact resistance at all six of the unclamped switch blade locations. High amperage on the main switch caused excessive heat to occur on the blades. This became a worsening condition with increased heating and increased resistance over time. The loose, overheated connections began arcing. Typically, arcing in a nominal 480-volt switch will result in phase-to-ground and phase-to-phase arcing faults. Arcing faults can destroy the switchgear enclosures and the internal switchgear components. The arcing burned a hole through the thick metal mounting plate for this switch. Many owners may not be aware of the arcing fault phenomenon and the degree of equipment destruction associated with arcing faults.

Photo 5: The six un-clamped switch joints operated with high contact resistance. Excessive heat and arcing destroyed this bolted pressure switch.

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Maintenance Vol. 3 Once established, arc faults tend to travel in a direction moving away from the source. This is caused by the magnetic forces acting between the arc itself and the magnetic flux produced in the busbars. This effect is similar to the electromagnetic forces that cause a motor shaft to rotate. The arc will travel at varying speeds depending on the fault current developed. When the fault currents are over 5,000 amperes, the fault can produce a gun-blast noise. An arcing fault will do the most damage at locations where the arc is physically restrained from traveling due to barriers. In the pair of photos shown here, the insulated fuse sleeves restrained the physical travel of the arc. The intense heat of the arc burned away the thick, switch mechanism crossbar and the insulated switch-mounting panel.

row shows the melted and dislodged ground fault current transformer that surrounds all four of the phase and neutral busbars. The GFPE relay is melted beyond recognition. Conductor insulation is damaged. The smoke and combustion products produced in the enclosure have contaminated the entire enclosure.

HOW TO MAKE A POSITIVE CHANGE It is important to realize that many building owners are not aware of the type of service equipment installed in their facility. In many cases, an owner assumes that a service switch does not require any maintenance. It is understandable that this idea would exist in the owner’s mind. Compare the bolted pressure switch annual maintenance requirements to the extended maintenance interval requirements for the circuit breaker installation. How does the building owner know which one is installed in his facility? Who in the organization is qualified to inspect, identify, and implement the proper preventive maintenance routines for the installed equipment? Although the technical documents for the service equipment and the maintenance requirements probably exist somewhere in an archived file drawer, who is technically qualified to read them and create a maintenance and disaster prevention plan? In this regard, a positive change and a reduction in catastrophic service equipment failures can be achieved when:

Photo 6: The downward traveling arc burned through the insulated crossbar and burned the tops of the fuses. The devastating effects of not performing the required maintenance on bolted pressure switches are evident in the second photo.

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Photo 7: The GFPE current transformer melted and fell from its mounting bracket. The mounting bracket can be seen on the left side above the CT. All three of the main fuses are damaged. The ground fault protection of equipment (GFPE) system is destroyed. The yellow ar-

●● Electrical design engineers specify that new building service equipment consider the manufacturers’ service requirements as being practical or suitable for the intended occupancy and use. Are the future maintenance requirements ever considered in the electrical equipment selection process? For example, if a building is designed for 24/7 intense manufacturing processes, should a service switch requiring annual maintenance or one requiring extended maintenance intervals be selected? Is it realistic to think that 24/7 types of use could accommodate frequent annual service intervals? Will the intense pressures for productivity always overrule the shutdown requirements for maintenance? ●● Electrical contractors proactively notify customers where known service equipment is not receiving the proper maintenance required by the manufacturer. In many cases, the owner and his employees are not technically qualified to make this assessment. If facility operations and schedules cannot accommodate annual shutdowns, then appropriate extended maintenance interval equipment options could be suggested. This would avoid the continued operation of an unmaintained bolted pressure switch. ●● NETA Accredited electrical companies continue a concerted effort to educate owners. Owners and facility managers must be informed of the risks associated with not following manufacturers’ maintenance recommendations for bolted pressure switches and other critical electrical equipment.

48 Owners and facility managers should receive additional resources, such as this article, to explain the destruction of equipment that can occur when a relatively small internal malfunction of a switch mechanism develops into an arcing-fault switchgear meltdown and business interruption disaster. John Weber is Principal Electrical Engineer for Hartford Steam Boiler Inspection and Insurance Company. He has over 30 years of experience in facilities/electrical engineering and management roles. John has a Bachelor’s Degree in Electrical Engineering and has a strong background in electrical engineering, HVAC, energy management, building automation controls, and National Electrical Code compliance.

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GO GREEN OR GO HOME… PowerTest 2013 Noah Bethel, CMRP, PdMA Corporation

ABSTRACT In the wake of sweeping energy regulations and increased competitive strategies, aging facilities are no longer being allowed to perform at sub-energy efficient levels. Ultimatums have been handed down to facilities to either increase their energy efficiency levels or face the inevitable plant closure possibility as corporations choose which facilities are too costly to maintain. For those working at these aging facilities, asset reliability and energy efficiency has never been more important. This paper will follow the efforts of multiple facilities within a corporation to increase their productivity through reliability and efficiency in an effort to survive the corporate axe. Austin Energy Company owned and operated by the city of Austin, Texas, provides electric and natural gas service to 388,000 customers and a population exceeding 900,000 in the Lone Star State’s capital city and surrounding area. The community-owned utility produces 2,600 megawatts of power to an area of nearly 437 square miles through a diverse mix of nuclear, natural gas, coal and renewable energy sources. On its website, the company says it “created the top performing renewable energy program in the nation” and proudly speaks of its ownership of “the nation’s first and largest green building program.” Yet, despite its leadership, the company became convinced it was falling far short of its green goals in plant operation due to outdated maintenance practices and questionable motor efficiency. Austin Energy took that problem seriously enough to consider whether inefficiencies were so irreparable that it should consider shutting down one or more of those plants, meaning one less power resource coupled with a significant loss of jobs. The utility’s challenge was to determine whether the motors essential to power plant operations should be repaired, replaced or reconditioned and, if so, what about the costs? Would they be so prohibitive that continued plant operation would be rendered unsustainable? The survival of each plant was at risk, and company and consultants required an advanced computerized technology that would examine efficiency, reliability and projected costs in ways that could not be determined through even higher mathematics. What Austin Energy needed and got was an Energy Analysis Module (EAM). Because of its analytics, the city wound up saving more than $500,000 in less than one year.

cient. Cables had caught fire due to poor insulation in the facility, which had been constructed in the 1960s. The plant had very few upgrades and, according to studies, nothing much had been done to improve motor and cable efficiencies. The company wondered if it faced a similar situation in 2009 after acknowledging a serious problem in plant efficiency at several of its five remaining power plants. Cable insulation had been breaking down due to age while motors became relatively unreliable at the Decker Power Station. Despite an excellent maintenance program at Decker, there was no way for the electrical maintenance staff to have a clear picture of the state and status of Decker’s motors. Motor issues had also been discovered at Austin’s Sand Hill facility. The city assigned Kelly Ballew, its utility process consultant, to study the operations of motors, cables and other equipment related to the process. Ballew’s charge was to determine the impact on plant operation, analyze whether reconditioning, rebuilding or replacements were acceptable options and even recommend shutdown if the three options proved to be economically unfeasible or untenable. Utilities such as Austin Energy can only sell power at a specified rate and wasted power cannot be sold. There was no doubt in Austin Energy that motors were wasting power, using more energy than they should and draining the utility’s finances. The issue was ascertaining the specific condition of each motor beyond either the efficiency rating on the motor nameplate or results from a standard electric meter testing device. Ballew determined that his examination would require sophisticated software that would factor in all elements besides the motor’s high efficiency rating. For that purpose, the city of Austin agreed with Ballew’s recommendation to purchase proprietary software, which combines static and dynamic testing, with a heavy emphasis on energy efficiency through the use of the Energy Analysis Module. The Decker plant experience was an eye-opener, according to Ballew. “Nearly all of the motors tested failed,” he said. “Resistance-to-ground (RTG) was one of the big failures along with a poor polarization index (PI) and a poor polarization index profile.”

AUSTIN ENERGY’S DILEMMA

Ballew said the data from the software showed that plant reliability was poor in large part due to its continuous leakage to ground. The software determined a similar situation at the Sand Hill plant with data showing failing RTG and poor PIs even though the facility was only seven years old and motors were of fairly recent construction.

In 2007, the utility shut down a 570 megawatt natural gas and fuel oil power facility in Austin after determining it to be ineffi-

At this point, Ballew turned to the EAM. “I was able to use the module by simply entering the motor information to the software,”

50 Ballew said. “Along with the information contained in a motor guide, I was able to enter running data into the software to come up with a more efficient motor.”

UNDERSTANDING THE MODULE It was only because of this advanced software that Ballew was able to access the information he needed to make the best recommendations, so at this point, it’s best to explain the technology that helped Ballew make his recommendations. The EAM is one of the newest analytical tools capable of providing real-time data for every motor application. The module uses measured data to determine the actual running condition before any consideration of reconditioning, rebuilding or replacing the motor. It should also be noted that this technology gives the user running historical data of the application or asset in its environment. The importance of environment here cannot be understated because a motor’s high efficiency rating is no guarantee of optimum performance. High efficiency ratings do not take into account the impact of the environment in which the motor operates. Nameplate efficiency ratings on the motor are based only on the motor running at design voltage and current values with no imbalance or power quality issues. Such issues upset the equation and the rating at that point is relatively meaningless in determining optimum motor performance. Power quality is another factor affecting efficiency. One example is the energy supplied to the motor and the power circuit. Power issues may undermine efficiency and reliability as much as the motor itself for the same reason that potentially troublesome working environment problems impair performance. True high efficiency requires a delicate balance involving the motor, power quality and environment and when the balance is disturbed, the impact is negative. Then there is the question of reliability, and it is here that the EAM played a significant role for Austin Energy. Reliability is never factored in a nameplate efficiency rating, but it is as important as working environment and power quality for the module’s data analysis. “My group is a reliability group and with the module we were able to find several major issues,” Ballew said. The consultant noted such important impairment issues as power quality, surface leakage, capacitance and insulation resistance among those problems that might have escaped detection by other types of analysis. The module is capable of factoring input variables to take into account all other costs associated with repair, replacement or reconditioning decisions. It certainly applied to the situation at two Austin Energy plants. “Having motors replaced or reconditioned before they failed made Decker and Sand Hill more reliable and efficient,” Ballew said.

ANALYSIS OF MOTOR FAULT ZONES The software purchased by the city assesses the motor’s condition under variable situations through analysis of six fault zones, all of which affect efficiency and reliability:

Maintenance Vol. 3 ●● Power Quality. Here the technology evaluates such possible negative influences as power spikes, harmonic distortion and power imbalance, none of which can be overlooked particularly in any determination of reliability. ●● Power Circuit. Studies have confirmed that a high percentage of motor efficiency faults come from its power circuit, which includes conductors and connectors from testing point to motor connection. An accurate circuit picture depends upon an evaluation of all its components. ●● Insulation. This is always an issue and was certainly the case at one of the Austin plants. Insulation should always be kept clean and dry to stay effective, but that’s not always feasible in an industrial environment. In many cases, buildings housing the motors are also repositories of excessive moisture and dirt, both of which spell trouble for insulation in the form of contamination. Left unmonitored, excessive contamination will result in elevated temperatures and reduced efficiencies. ●● Stator. A stator consists of copper windings connected with solder joints between the coils and insulation between every turn. An undetected stator problem can lead to catastrophic outage, waste and downtime. The module’s software analysis examines possible stator issues from imbalance to shorts. ●● Rotor. While a problem with the rotor may not have the immediate impact of other fault zones, increases in reflected impedance due to rotor defects can negatively affect efficiency, which is why it should not be overlooked in any analysis. ●● Air Gap. This gap between stator and rotor can only be efficient when evenly distributed around 360 degrees of the motor. This fault zone is included in the module’s software examination because of the risk of an unbalanced magnetic field in the event of uneven distribution. The result could mean failure of bearings and stator windings. These were the areas that required thorough analysis so that Ballew could have a comprehensive picture of the state of every motor in the Austin plants and determine what to do with each. That is exactly what he got and the results led to eye-opening savings for the utility, city and taxpayers.

ANALYSIS RESULTS LEAD TO HUGE SAVINGS The software uncovered a number of motor problems not likely to be discovered through standard types of electric testing. Ballew cited such complications as an undersized heater drip pump and an oversized circulator motor, easily corrected by having the proper horsepower motor. “That’s a cost saving to the plant and consumers,” Ballew said. At Sand Hill, testing of motors at the lead makeup box detected an issue with the cables that were eventually pulled, resolving losses that limited motor efficiency. “We were able to find several major issues before they became catastrophic,” Ballew said.

Maintenance Vol. 3 Ballew produced a spreadsheet with comparative costs for reconditioning, replacing or rebuilding motors at Sand Hill and Decker since all three choices were possibilities based on the module’s data. At Decker, the figures listed total motor reconditioning costs at $33,000 rebuilding at $112,000 and replacement at $277,000, all based on the various fault zones where the module uncovered problem areas. Since the troubled fault zones could be reconditioned, the city’s choice was easy; it saved more than $243,000 by not having to replace the motors and more than $79,000 by not having to rebuild any of them. The choice was equally telling at Sand Hill where the savings were even greater thanks to data from the EAM. By choosing reconditioning over rebuilding, the city could save more than $132,000; reconditioning savings over replacement costs even startled Austin city officials: the savings—nearly $432,000. “This just overwhelmed the city of Austin,” Ballew said. “Every quarter I have to produce numbers of savings and they are totally surprised with the results.” And, perhaps most important, the city determined it did not need to close any of the plants thanks to the EAM.

KEEPING AUSTIN ENERGY GREEN While the cost savings were enough justification for Austin Energy’s purchase of the software, there was one more factor that made the technology advantageous and that was efficiency’s role in Austin Energy’s green energy program. Austin’s city-owned utility prides itself on its environmentally sensitive energy programs such as GreenChoice®, in which subscribers purchase “electric generation from clean, renewable sources,” and its Green Building™ community outreach offering advice on environmentally-friendly residential and commercial building construction. Recommendations based on the EAM motor analysis had to be consistent with these city programs and policies, and the software played a valuable role with this aspect of the decision-making process. Austin Energy recognized that any green reference must address significant reduction of energy consumption—precisely what the module is designed to clarify. The term used to describe all green-related factors in the over-all decision-making process is “greenwise.” The word refers to all intrinsic influences on efficiency with ratings only a small part of the evaluation. As applied to the EAM, greenwise evaluation includes all variables from operational environment to reliability along with predictive maintenance practices that will extend the useful life of the motor while keeping it running at maximum efficiency with minimal wasted energy. Analysis of this nature projects motor reliability and useful lifespan in addition to reducing energy consumption. That is green technology by every measurable standard. Also there is a point considered crucial for a utility such as Austin Energy—reducing its carbon footprint. Ballew said the city

51 became more receptive toward the software after he explained how “I could cut the carbon footprint and help the green movement here in the city of Austin” through module analytics. Of course, there is always the deal-maker or deal-breaker whenever green technology is debated: return on investment (ROI). In today’s business world, an ongoing philosophical battle wages between those who contend that green considerations make sense economically and environmentally and the other side that believes ROI from a green initiative, particularly if it is long-range, is unacceptable to the bottom line, especially when shareholders are involved. Austin Energy found an alternate solution. It recognized in accepting the recommendations based on the module’s data that it could achieve efficiency through reconditioning, a short-range and long-range ROI solution that kept the city (and no doubt its taxpayers) happy. “Not only that, but because of the savings, the software paid for itself in three months,” Ballew said. Another EAM benefit that pleased Austin Energy was the module’s ability to project energy costs several years into the future through maintaining top-level motor efficiency. Energy ROI varies as the price of energy fluctuates, but at the same time, any effort successful in reducing the motor’s need for power will translate into lower energy costs—a goal that every company wants to achieve. “We could not have achieved these savings without the module,” Ballew said. “There’s just no way we could have done it.” Reducing a company’s carbon footprint is always a worthwhile goal, but it takes more than good intentions to justify the investment. That is why the high technology behind the Energy Analysis Module was so valuable for the decision-makers at Austin Energy who needed a thorough assessment of all factors from actual motor efficiency to working environment to costs of repair or replacement. The module’s value, however, went beyond even those important essentials. It evaluated motor reliability, a critical consideration ignored by most other energy analysis software. The last point cannot be overstated. A company cannot hope to become energy efficient and lessen its carbon footprint if it overlooks reliability, a component that deserves intensive study, which is why it is included in the module. In times like these, when companies demand the leanest of operations and the maximum productivity of worker and machine, the EAM proved itself a valuable tool with real-time analytics of motor and the environment to help maintain motors at maximum efficiency. Just ask Austin Energy. Noah Bethel, CMRP, is vice president of product development for PdMA Corporation, Tampa, Fla., a leader in the field of predictive maintenance, condition monitoring applications, and development of electric motor test equipment for motor circuit analysis. Tel: (800) 476-6463 or visit www.pdma.com.

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THE TRIFECTA OF MOTOR MAINTENANCE PowerTest 2015 Noah Bethel, VP Product Development, PdMA Corporation

The odds are against picking the first place winner of a horse race. The odds of picking the first, second, and third place winners are even less favorable, but when it happens, the trifecta payday is big! In the world of horseracing, guessing the winners is pretty much a gamble. But imagine if a gambler knew in advance the trifecta of the race. It would be a no-brainer, and they would put everything they had on the race knowing they would see huge returns on the investment. Using the same concept of a trifecta (three factors for success), this article provides companies with the winning strategies of motor maintenance, focusing on the three reliability tasks for electric motor testing and the order in which they should be applied. Following these steps will drastically improve their odds in motor reliability and put a big payday at the end of their production goals. Talmadge Ward, a senior engineering technologist with Duke Energy, believes that the trifecta of motor maintenance has saved his company both time and money. “Motor reliability is paramount in the electrical generating business,” says Ward. “Duke Energy has performed motor testing for more than 50 years.”

ELECTRIC MOTORS A basic understanding of the construction of electric motors is essential before discussing the trifecta of motor maintenance. Commonly, an AC electric motor would be a component of a fan, pump, or larger piece of equipment such as a mixer, conveyor or winder. Electric motors have three main parts: the rotor, the stator and the enclosure. The rotor and stator are the working parts of the motor. The enclosure serves to protect these working parts. The stator is the part of the motor that doesn’t move. The core of the stator is made of thin laminations of metal. These laminations are arranged in a hollow cylinder, into which coils of insulated wire are placed. The rotor, as the name suggests, is the rotating piece in the motor. It is also made of thin metal laminations to form a cylinder, and a shaft is inserted into its center. The rotor is inserted inside the stator, but a small air gap ensures they do not physically touch. The enclosure holds the stator and rotor assembly. A yoke supports the stator and rotor assembly, while bearings mounted on the rotor shaft allow the rotor to spin. A cooling fan may also be attached.

Electric motors work on the basic principle of electromagnetism. When an electric current is passed through the insulated wire windings in the stator, it creates a rotating magnetic field. The magnetic rotor, working on the principal that opposite electric charges attract, spins as the electric field moves and pulls the south pole of the rotor toward the north pole of the field (and the north pole of the rotor toward the south pole of the field). This in turn spins the shaft, which allows work to be done, whether the shaft is connected to a pump, conveyor, or other piece of equipment.

TRIFECTA PART ONE: QUALITY CONTROL The first piece of the motor maintenance trifecta is quality control (QC). QC is a general term that impacts a wide variety of people, assets, times, and locations. It’s both the asset being maintained and the environment in which it’s stored. Companies should ask several questions regarding their motors from delivery to installation. First, is the motor tested when it’s delivered, or do the employees in charge of receiving the equipment assume that all is well? Assuming the motor works as specified, a second consideration is how the motor is stored. Is the environment suitable in terms of temperature, humidity, protection from the elements, and easy accessibility? Third, the motor should be tested intermittently during storage. Just because the motor worked when delivered does not guarantee that problems won’t develop as the motor sits idle over time. Additionally, motors should be installed in an overall system that is quality controlled. The electrical distribution system is a vital component. For example a voltage imbalance of 5-10 percent can cut the life of a motor in half. In this situation, replacing a motor isn’t solving a problem. Rather, it’s starting the failure cycle again. This leads to the old adage cited by veteran employees in work environments without adequate QC: “Let the new guy start it.” Duke Energy’s Ward says that all motors are checked before storage or installation. “In the case of our most critical large motors we review the vendor test reports for both new and repaired motors as a quality check based on our purchase or repair specifications for motors.” Adds Ward, “For these motors, we also perform our own motor testing once they arrive at the generating station. All of the large stations have staff, and they are qualified to perform these tests and evaluate the data. These tests are also done once the motor is installed and ready for service.”

Maintenance Vol. 3 TRIFECTA PART TWO: TRENDING Once a motor is in place and operating, it’s not a good practice to leave well enough alone and assume there are no problems if everything seems to be running smoothly. While many motor failures are mechanical, nearly half are electrical in nature. A 1985 EPRI/ GE study showed that 41 percent of motor failures were caused by bearings and 12 percent by “other” problems, while a whopping 47 percent of failures were caused by rotors (10 percent) and stators (37 percent). Data collection is the key to preventing these failures. Machine operators often call a repair company with just one data point. Trending is a term that refers to taking data points on a regular basis, so that potential problems can be identified well in advance, and a detailed history of the problems can be assembled. For example, it’s smart to monitor one’s health over time rather than wait until a problem develops which requires a visit to the doctor. Just like machines, as people age, certain problems are common. With regular visits, physicians can monitor indicators such as cholesterol levels or blood pressure over time. If the doctor sees a trend developing, for example, cholesterol levels steadily rising at each yearly checkup, the physician can advise the patient to take preventive actions such as modifying diet, increasing exercise, or taking cholesterol-lowering medications. Without these frequent data snapshots and preventive measures, the doctor may end up working with a heart attack victim in rehab—or worse. What types of trending data should be gathered, and how often? When it comes to data collecting, “trend is your friend.” Using software and testing equipment that can analyze both dynamic and static data a detailed history can be obtained for a motor that shows potential problems before a catastrophic failure occurs. There are six fault zones that should be analyzed regularly to obtain trending data: ●● Power Quality: Power quality relates to the quality of the voltage (which is determined by the power system) and the quality of the current (which is determined by the load). Factors that can be analyzed include low or high voltage, harmonic voltage factor, crest factor, and total harmonic distortion for both the voltage and current. ●● Power Circuit: The power circuit fault zone contains everything from the test point down to the motor, including things such as circuit breakers, fuses, and disconnects. Measurements of voltage imbalance and resistive imbalance can be taken to analyze the power circuit fault zone. ●● Insulation: Insulation can be affected by old age, moisture, temperature, vibration, and other factors. In the insulation fault zone, appropriate hardware and software can measure resistance-to-ground, capacitance-to-ground, polarization index, and step voltage. ●● Stator: In the stator fault zone, inductive and impedance imbalances are measured to indicate the health of the insulation between the turns of wire in the stator coils.

53 ●● Rotor: Current signature analysis (CSA), in-rush current, inductive imbalance, and a rotor influence check (RIC) test are performed in the rotor fault zone. ●● Air Gap: In the air gap fault zone, CSA and RIC tests determines levels of static eccentricity and dynamic eccentricity in the shaft. How often these tests are performed will depend on the type of motor being used, the frequency, intensity, and duration of use, and the company’s seasonal production patterns. Other factors may include the environment in which the motor is run. Whatever the interval, consistency is the key. Quarterly or semi-annual trends may be much more valuable than tests performed at random intervals or whenever the staff remembers to have the data collected. Duke Energy’s Ward has found that an annual interval works best for his company. “Testing motors for trending is done as frequently as every year for the most critical population of motors, but for less critical motors we use a scalable approach which we base on the probability and consequences of a motor failure. Our goal is to plan motor service rather than be forced to limit generation for motor repairs because they have reached end of life.” Duke Energy’s trending data collection has paid off. “Recently we found a large difference in resistance in the circuit of a critical 125 HP AC induction motor during a routine off line test,” says Ward. “The cause was loose field cable connections. After the connections were properly torqued the follow up test showed only a 0.1 percent resistive imbalance verses the 9 percent imbalance first observed.”

TRIFECTA PART THREE: TROUBLESHOOTING All motors have a limited lifespan. Eventually, a motor will fail. What happens at this point is heavily dependent on whether or not the company has been diligent with parts one and two of the trifecta: quality control and trending. If so, the third part of the trifecta, troubleshooting, will be much easier. Troubleshooting refers to what happens when a motor fails or performs poorly enough that it causes a problem. A good example is the case of the local coal mine that experienced trouble with a wound rotor motor…on a Saturday. The local electrical company was dispatched to the mine, where production had ground to a halt and dollars began to bleed from the operation. This motor type generally couldn’t be fixed in the field, but the mining company had the foresight to have a spare motor on hand. By Monday afternoon, a crane was in place to swap the motors, and by midnight, the new motor was installed and ready to start. The miners waited with bated breath under the stars as the start button was pressed, and…a growl and a blown $1,000 fuse resulted. Adjustments were made, and another $1,000 fuse blew. By 4:30 in the morning on Tuesday, the third $1,000 fuse blew. At 7 pm Tuesday—more than four days after the initial failure— the electrical company prepared to remove the spare motor and

54 take it to the shop for inspection. However, someone had the idea to use electric motor testing equipment and software to identify the problem. On Wednesday morning, testing revealed that two leads were reversed. The problem was quickly fixed and the spare motor started. Needless to say, this scenario could have been avoided had the three parts of the trifecta been in place. QC would have detected faulty wiring in the spare motor at delivery or while in storage, trending would have identified problems in the original motor before it failed, and troubleshooting—what to do when a problem arises—would have saved the miners five days of downtime. When it comes to troubleshooting, the first key is having written instructions, in a manual, that spell out the company’s policies on motor failures. This includes employee training. Second, the policy should require that the job site have the technology available to assist in diagnosing the problem. If the miners and the electric company had used the electric motor testing equipment on Monday morning, down time on Tuesday and Wednesday would have been avoided. The plan should also stipulate calling in outside experts when the scope of a problem exceeds the training or knowledge of the employees. “Critical motor failures are very rare in our generating stations,” says Ward. “What is more common is to find a degraded motor and determine the cause and contribution factors. Then we develop an increased testing plan. Degraded motors require more frequent testing to understand the cause and understand the rate of degradation. With an understanding of both the cause and the rate of degradation we can have a high degree of confidence we will avoid an in-service motor failure.”

MANAGEMENT, PREDICTIVE MAINTENANCE AND THE BOTTOM LINE Management also plays a key role in successful troubleshooting. Creating manuals takes time, which costs money. Training employees may result in reduced labor available, which may cause scheduling conflicts. Calling in experts is expensive. However, it’s much more costly to lose extra time due to fumbles and false starts than it is to do things correctly in the first place. For example, studies show that industrial rotating machinery failures cost $17 per horsepower of the motor per year for companies practicing only reactive maintenance—in other words, if it breaks, fix it. Compare that with $12 per hp for companies practicing preventative maintenance (regular maintenance without the benefit of data), and $8 per hp for companies using predictive maintenance. The maintenance trifecta is the very essence of predictive maintenance: using QC and regularly collected data to fend off and forecast problems before catastrophic failures occur. And the impact on the bottom line? Repair costs reduced by more than 50 percent over companies with a “close our eyes and hope it turns out okay” approach.

Maintenance Vol. 3 Predictive maintenance saves money in other ways, too. With predictive maintenance, there are fewer unexpected motor failures and less need to keep extra motors and parts on hand, resulting in less costly inventory and need for storage space. And repairs and maintenance can be scheduled during the company’s slow periods—not at peak production on a Saturday. “In the last 20 years we have secured the support of senior management. With this support we have developed specification, procedures, motor alliances with repair shops, budgets for purchase of motor test equipment, and what we consider to be a solid motor maintenance program,” Ward reports.

WINNING THE TRIFECTA All business involves risk. Some risk, such as entrepreneurial risk, is beyond anyone’s control. But other types of risk can be alleviated and mitigated with best practices. By putting their money on the trifecta of motor maintenance—quality control, trending, and troubleshooting—companies can “hedge their bets” and increase their chances of a big payday. Noah Bethel, CMRP, is vice president of product development for PdMA Corporation, Tampa, Fla., a leader in the field of predictive maintenance, condition monitoring applications, and development of electric motor test equipment for motor circuit analysis. Tel: (800) 476-6463 or visit www.pdma.com.

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DESIGNS, METHODS AND LIMITATIONS FOR TEST ISOLATION DEVICES PowerTest 2015 Scott L. Short P.E., Director of Protection and Automation Technologies, Doble Engineering Company

ABSTRACT This technical paper presentation will cover the various designs and practices to isolated VT and CT circuits in operational use today by various utilities and commercial applications. The presentation will describe the concept and point out the pros and cons for using each type device. It will also discuss the correct means to properly use the devices and the procedural steps to isolate circuits for test. It will discuss known issues related to those devices and any safety or design defects that have been associated with the designs. Additionally, it will discuss the new challenges related to IEC61850 and how those techniques and standard are evolving to meet the challenge to allow isolation to test IEDs in digital substation designs.

INTRODUCTION Since the early beginnings of electric power systems, protective devices have been developed to help reduce or possibly eliminate physical damage to assets while giving some reliability to healthy circuits. The designs of these devices have not changed a great deal, and are stable in operation when properly applied and maintained. The maintenance of the protective devices is a crucial and required part of a successful operating system. Verification of these devices helps provide a reliable and stable electrical system so that faults can be properly isolated. To verify the proper operation of protective elements, the use of test isolation devices to isolate voltage and current transformers sources was developed from the very early days of the power industry. Information provided will cover the major test isolation devices used from the early designs of the electromechanical relays, both General Electric and Westinghouse. Additionally, I will discuss known issues with designs and improper installation of the isolation devices that users should be aware of when testing. Improper application and limitations of use with different technologies, electromechanical, and microprocessor based applications will be discussed.

PRE-TESTING PRACTICES Some commonly applied preliminary testing steps are followed and observed for any type of control or protective testing. To en-

sure that the appropriate tests are conducted safely for compliance reporting, proper set-up is needed. Although they may vary slightly from organization to organization, some common practices include: ●● Familiarization of System Condition ○○ Is the asset remaining in service during the testing of the protective device? This requires manipulation of secondary sources to prevent interruption during testing. ○○ Is there more than one protective device connected to a given CT circuit? This requires different shorting practices for testing. ●● Proper Isolation of Device Under Test ○○ Review of associated AC & DC wiring prints ○○ Familiarity with and identification of associated isolation devices ○○ Isolation of trip circuit always first ○○ Correct shorting of current circuits second ○○ Removal of potential circuits third, to ensure voltage restraint ○○ Isolation of monitoring circuit fourth ●● Test Block Strapping Verification ○○ Test plug or paddle, proper design and correct vintage ○○ Visual inspection of short strips to test plugs. Ensure shorting of field wiring or through strapping for in-service devices ●● Physical Inspection of Isolation Device ○○ Loose parts ○○ Burn marks ○○ Electrical tracking ○○ Wiring discrepancies. Addition or removal of wires not indicated on the prints ●● Double-check your Work ○○ Don’t assume all circuits are the same. ○○ Have a second person check work, when available.

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ISOLATION DEVICES Several test isolation devices have been used over the last fifty years, and many are still used today. Three of the more common types used are the Slide Link, PK-2 Block, and Flexi-Test type isolation devices with associated test plugs. All though there are several different test plugs available for use, many companies try to standardize for training and familiarity. Additionally, many electromechanical protective devices were designed to have isolation devices built into their draw out cases.

●● Short current circuit by connecting the lower links 5-8 (in that order) to the right by loosening the slide screw and retightening it in the shorted or closed position.

Sliding Link Isolation Block

●● Isolate protective device by sliding the upper links 1-4 to the right by loosening the slide screw and retightening it in the open position.

The sliding link blocks (see Figure 1), are manufactured by a variety of companies. Sliding link terminal isolation blocks are a common method for isolating AC and DC voltages. The link blocks are used in some CT current circuits, but are commonly not used for this application.





OPEN

OPEN

SLIDE LINK

SLIDE LINK

CLOSED

CLOSED

●● Isolate the voltages in a similar manner, to remove voltage AC and DC. Fig. 1: Shown with wiring label positioned down on left When changing from a shorted to open position, the shorting link is loosened by the internal screw. The sliding link is then moved across to make or break the connection. The sliding link is locked in place by tightening the internal screw. However, current circuits must be designed differently. A combination of links is used when isolationing CT circuits. (see Figure 2) A Phase Primary

Relay Current Elements

B Phase Primary C Phase Primary

A B C

To return the protective device to its operational condition, reverse the process. Not all systems are the same, so the process may vary slightly. However, the same general procedures are followed.

Advantages/Disadvanges The biggest advantages of the sliding link are typically: ●● Economical cost ●● Versatility and ease of use ●● Front panel space savings ●● Higher Steady State current ratings ●● Moderate # of isolations per length Some of the disadvantages are: ●● Locking Sliding link. Screws can be hard to get to and operate. ●● Special precautions are needed to understand shorting for CT circuits. ●● Moveable wiring labeling arm covers the sliding link, restricting view. ●● Sliding links mount is typically at the rear of the panel, which is more difficult to access.

Industry Concerns / Misoperations Fig. 2: Shown in normal operating condition To properly isolate the protection device for test, follow these steps: ●● Open all associated trip paths.

Sliding link isolation blocks are also known to have some imitations and failure modes. Additional proceedures should be implemented to prevent false operations or equipment damage. One example of this is improper installation due to environment conditions. Sliding links are fairly secure when properly mounted vertically. Over the years of operational use, the link screws

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Maintenance Vol. 3 can become loose due to wear of the tightening screw. Gravity has been known to cause some sliding links to open or close accidentally, if improperly tightened or mounted incorrectly. If the slide link terminal block is installed in an environment where vibration can be felt (such as near rotating machinery or railroad facilities), care must be taken. The vibration, mounting and in-service wear of the slide link and set screw can accelarate potential false operations which can cause damage to the equipment and possible lengthy outages. Physical damage or pitting is usually evident when connections are beginning to loosen with use, and should be considered for maintenance repair when warranted.

To properly isolate the protection device for test, follow the PreTest Practices stated previously, and apply them to the PK block design. Physical inspection of the covers, studs and block assembly is important in the life and performance of the product. After physical inspection is completed, it is important to match up the appropriate test plug and guide tracks to the test block. The block and test plug are keyed to prevent insertion of the block rotated 180 degrees. But, it is common to wire jumpers and test leads upside down. Ensure proper jumpers are applied to the outside of the test plug and insert on the block assembly. (See Figure 5.)

Another example of misoperations caused by the inherent position of the label arm and plate is when the line of sight for the sliding links view being block has caused many missed positions of links for testing or return to normal operation. Extra care and a second verification system is required when placing the links in the correct position, especially under high pressure circumstances.

PK – 2 Test Block The PK block and test plug are useful and well-established isolation devices. (See figure 3.) They are used extensively to allow easy isolation of panels from CT and DC trip circuits for testing. Many electromechanical panels used the PK block prominently. The PK block can have 4 or 6 poles to isolate circuits. The construction is of a non-conductive material for proper low voltage isolation, such as secondary circuits, and has silver-plated contacts for good conductivity.

Fig. 5: Properly strapped test block Strapping of the block is the most important step to ensure trip and current circuits are isolated properly.

Advantages / Disadvantages The PK-2 block is a sturdy isolation block with the following advantages and disadvantages: ●● Rugged Design ●● Key design for proper connection. Misconnection is not possible, if strapped correctly. ●● Easy visual verification of correct shorting necessary for testing

Fig. 3: 6 pole PK The PK Block is configured to allow shorting of current circuits with the cover removed, via permanently installed shorting links. The connections from the field VT and CT supplies are wired to the bottom studs on the rear of the isolation device in most applications. Four different links are used for different applications. (See Figure 4.) Each link is screwed into a support post running through the middle of the block.

Fig. 4: Shorting links, PK Block Shown with Cover removed

Some of the disadvantages are: ●● Has limited number of isolation points per area. ●● Takes more panel space for large number of isolation devices. ●● Common design wiring practices can cause failures.

Industry Concerns / Misoperations Although the PK -2 test block is time-tested, like any device, there are some common concerns that require procedures to be observed before testing. The first example is tracking and chemical contamination. PK Test blocks have been in place for more than half a century. With such a long lifespan, many of the test blocks are installed in older power plants and substations. A series of incidents started occurring approximately 25-30 years after the blocks had been in service. The block would malfunction and trip. After investigation, it was determined that there was a combination of factors causing the misoperations. The first problem was a white stain present on the PK block, between two studs on both the malfunctioned blocks and on several others still in operation. (See Figure 6.)

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Fig. 6

Fig. 9: PK Block Contact sample Electrolysis was evident. Further review discovered that the positive and negative DC circuits were isolated on adjacent studs. (See Figure 10.)

Fig. 7 Further tests were conducted on a fly ash sample from the locations. The results are shown in figure 8.

Fig. 10: Failed Block view The sequence of events was set up by many years of an electrolysis process that allowed the Ag to plate off from a difference in potential, set up by a weak electrolyte formed from the sulfur in the fly ash and moisture in the air. Numerous blocks were replaced and the strong DC sources were separated to different ends of the block to prevent the condition from creating further problems. The reaction that took place is as follows: S + O2 --- SO2 forms Sulfur dioxide. 2SO2 + O2 --- 2SO3 forms Sulfur trioxide SO3 + H2O --- H2 SO4 forms Sulfuric Acid 2Ag + H2 SO4 = Ag2 SO4 + H2 creates a chemical solution

Fig. 8: Fly Ash Sample A sample of the plate from the contacts revealed the Ag silver content as seen in figure 9.

Ag2 SO4 + 2e- = 2Ag + SO4-2 electrolysis process is completed with the applied potential between the terminals. Physical inspections were implemented, and maintenance actions have reduced further faults. The second example is metal fatigue of the studs. In the early 1980s, several bridle fracture failures of the terminal studs were seen in the PK block. GE issued a service advisory (Advisory 182.1, dated May 28, 1986, and a memorandum, dated October 2,

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Maintenance Vol. 3 1992) informing the customer of the problem, but many devices were already installed in operational sites. The cause of the failures was linked to the changing of the manufacturer and the composition makeup of the terminal stud alloy. The copper content had been reduced by 3-4%, resulting in a change in ductility of the metal. With visual inspection, the studs can be identified before installation. However, in-service equipment required operations and maintenance to add an inspection with infrared cameras to help locate fails or studs that need to be replaced. Visual signs are rounded edges of the hex nut and lateral stamping marks, as shown in Figure 11. Lateral Stamping Marks

Fig. 13: 12XLA13A1 Half Paddle

Advantages / Disadvantages The test paddles have been in existence for a number of years. Their advantages include: Rounded Edges

Fig. 11: PK Block Terminal Stud

GE Insertion Test Paddles For many years, General Electric has designed electromechanical relays in draw out cases. The relay could be tested in the case or removed from the case and placed on a test block pad to be tested with a test paddle. However, depending on the type and complexity of the relay, the pickup values could be affected if not tested in the case and allowed time to warm up. At the same time, GE introduced a different set of paddles to help facilitate safe testing. Not all test paddles are the same, so care must be given to ensure correct selection when testing. GE manufactures a full paddle, such as the XLA12A and 12XCA28A, which allows access to source and load sides. (See Figure 12.) They also make a half paddle, the XLA13A test plug, which allows access to only the load side or relay. (See Figure 13.)

●● They are easy to insert and connect jumpers. ●● They allow access to the relay in the case, for testing in service for load checks and calibration. ●● They can be used reversed, for upper block removal and testing. ●● Proper order for insertion and removal should be followed when testing a dual paddled relay. The removal of the lower paddle is first, then the upper paddle must be followed to ensure the correct isolation with dual test paddles are injected. The trips and current isolations are on the lower paddle; voltage restraint is located on the upper paddle. Some disadvantages include: ●● Older test paddles have a tendency to slide out of the relay, and can cause possible false operations. Worn paddles should be repaired or replaced. ●● Care must be taken when dealing with full paddles. Shorting bars must be placed under the RED field screw, to prevent open circuiting of CT circuits. ●● Test paddles must not be forced into the relay case. A forced paddle usually indicates a reversed test paddle or a damage metal component in the relay case.

FT / FT-19R Flexi Test

Fig. 12: 12XCA28A Full Paddle

The FT and FT-19R flexi-test switches are very popular and come with different configurations of poles to give flexibility in the design process. The FT switches (see Figure14) have 10 poles and different pole types (potential, current, and current shorting combinations) available. Additionally, they have different color handles for easy visual identification of trip circuits (red). Isolating the red handle first, when removing an in-service relay, is the first lesson learned when handling relays.

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Multifunction relays increased the number of required isolation points, and the FT-19R switches were developed to give flexibility of 30 possible isolation poles for mounting on a 19” rack panel (see Figure 14).

●● Maximum panel space usage ●● Various color handles to identify function ●● Various pole type arrangement (P, C, C-C, others) Disadvantages include: ●● Field input cannot be accessed from test plug, relay side only. ●● Many different arrangements cause complexity to isolation. ●● Not all switches use a standard layout, so there is a need for strong standards. ●● Tester may become too comfortable with pre-conceived operational use and cause misoperations or trip.

Fig. 14: FT Switch

Fig. 15: FT-19R Switch The FT switch test plug, shown in Figure 16, allows access to 10 poles of a FT or FT-19R switch. Due to the flexibility of a FT/FT-19R switch, different companies have different standards. So it is extremely important to work with your prints when isolating the protective device. The current non-shorting pole type (see Figure 16) is for measuring only. It does not have a shorting blade, and will open a CT circuit if a test block is inserted without proper strapping and the circuit is energized. Testing a relay in service can damage equipment when the improper test block or probe is inserted.

Industry Concerns / Misoperations The first example is test plug sliding. The design of the test plug to be used for the FT-19R type isolation blocks is tight and can slip out during testing. The test block shown in Figure 18 does not have a locking screw or a clamp that will securely place the test block in the isolation block. While testing, the block can slide and pull back, causing the relay to calibrate incorrectly and, if testing on an energized circuit, can lead to misoperations or equipment damage. Part of the issue is the space and design of the different arrangements and the weight of the test leads. Typically test leads hang unsupported from the test block. When current leads and contact sensing test points are attached to the block, they will tend to slip backwards out of the test block. The backward movement allows a ground or alternate path of current. The current splitting can cause misoperations or incorrect test results. The second example is due to a design in the wiring arrangement, so that the knife switch would not be energized when open. A concern over safety, with potential possibly being touched with an open knife switch, caused the design department to wire the source side of the FT switch to the relay side and the relays side to the source side of the block. The concern was not having an energized switch post. The tester inserted a test block and connected leads, which tripped a main transformer. Deviation from the intended use of the isolation switch resulted in routine test becoming a misoperation. Checking the wiring diagrams, as part of the pretest routine, could have prevented this problem and standards should have caught this issue.

The current shorting paired current poles (see Figure 17) have a shorting blade that will short the CT circuit to ground. A bottom cam of the shorting blade makes contact with the shorting spring before disengaging main contact. This allows a “make before break” contact. Many companies have now stopped using the standard red handle trips to force a review of prints to verify proper isolation. Due to the number of uses, a company will have many designs and arrangements across a system or plant.

Advantages / Disadvantages The FT/FT-19R switch has: ●● Flexibility of isolation arrangements

Fig. 18: FT/FT-19R Test block

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Maintenance Vol. 3 Proper insertion and removal of test plugs and blocks An increasing industry pattern of misoperations occurs when inserting or removing test plugs from a circuit that is in service with incorrect shorting straps or connected test leads from the test equipment. When inserting or removing test blocks or plugs into test isolation blocks, it is important to remove the wires from the test equipment. Failure to remove the wires has caused numerous false trips and test equipment damage. As the relay technology has changed and evolved over the years, the sensitivity and speed of operation have increased. Figure 20 shows the normal current flow of a designed differential test circuit with an installed backup relay.

When inserting test blocks with test leads attached, the current flow can momentarily be redirected to the test set through the common ground of the instrument. It is advised that the test leads be disconnected when inserting test blocks into energized and de-energized circuits, to prevent misoperations. Sensitive circuits such as differential or sensitive earth fault detection can operate on any protection using the same CT circuit. Companies have instituted strict policies for the handling of test blocks and interruption to the power system.

A PHASE

A PHASE B PHASE

B PHASE

A PHASE

A PHASE

C PHASE C PHASE

B PHASE

B PHASE

Differential Relay

C PHASE C PHASE

Differential Relay Source Outputs Source Outputs

doble doble

VA VCVC 69 69 240240 VA 69690 0VBVB6969120 120 I1I10.05.5330 I2 I20.50.150 I3 I0 330 5 150 3.50.240 5 240

e e F6150 F6150 POWER SYSTEM POWER SYSTEM SIMULATOR SIMULATOR

USB

Battery Battery Simulator

USB

Simulator 1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8 Logic Logic Outputs

Outputs

1

2

1

3

2

4

3

5

4

6

5

7

6

8

7

8 Logic Inputs Logic

Inputs

AUX LOGIC I/O AUX

V

V

GPS

A

A

DC Meter Inputs DC Meter

Inputs

Backup Relay

Backup Relay

Fig. 22: Normal Protection Current flow through secondary

LOGIC I/O LOW LEVEL SOURCES LOW LEVEL GPS SOURCES

INPUT /OUTPUT & COMMUNICATION INPUT/OUTPUT &

COMMUNICATION

Test set Grounded through Power cord

Fig. 22: Momentary current flow interruption inserting test block with leads connected

The current flow through the test blocks can be affected when inserting a test plug, if jumpers or test leads are attached. The insertion will cause improper current flow through fast and sensitive relay elements. Figure 21 shows open/closed and modified circuits with insertion of test block with jumpers installed.

Current Flow Through Closed FT Switch

Current Flow Through Open FT Switch

Current Flow Through Closed FT Switch

Current Flow Through Open FT Switch

Changed Current flow inserting test plug with C phase shorting Jumper

Fig. 21

Changed Current flow inserting test plug with C phase shorting Jumper

Fig. 23: Test Plug Precautions

INTERNATIONAL ELECTROTECHNICAL COMMITTEE (TC57), IEC 61850 ISOLATION FOR GOOSE AND SAMPLED VALUES TEST The IEC61850 standard consists of two digit systems, GOOSE or Station Bus and Sampled Values or Process Bus. The Station bus or GOOSE / GSE portion are the status/trip signals that are transmitted and networked over an Ethernet system, using TCP/ IP protocol. The Sampled Values or Process buses are the voltage and current measurements from CTs being digitized by a merging unit and sent over Ethernet to the protective device. The digitized values are transmitted to the protective device via Ethernet. Figure 24 shows the two parts of the IEC61850.

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+

Z1 Trip

Relay Input

Z2 Trip OC Trip Etc….. OR

CBF from X relay via Goose

CB Trip

AND

Test Isolation from X Relay via GOOSE CBF from Y relay via Goose

AND

Test Isolation from Y Relay via GOOSE

Relay Input

-

Relay LED Published on GOOSE

Fig. 25: Test Isolation Logic

Fig. 24 There are several parts of the standard, but typically they are referred to as Edition 1 & 2. The many benefits of IEC61850 Edition 1 are cost, system supervision and functionality. The GOOSE, or substation bus, can have many signals, while additions and modifications can be made easily without physical changes. All signals can be supervised to allow for smart decisions made automatically to adjust from system failures. The network replaced the binary signals wired with conventional copper wiring. Although the first standard had several benefits, there were some issues with implementation. The GOOSE portion needed an isolation method, although it provided a test mode. The test mode applied to the whole message and didn’t allow for a signal state to be available. The test mode was not always reported by the receiver of the message. Additionally, the quality test bit was not always implemented, and the initiation of the bit via local, remote or from relay menus is difficult. Additionally, manufacturers varied on the implementation and design causing interoperability issues. To account for these interpretations of the standard, companies designed the equipment to send an additional test isolation bit in the GOOSE message. (See Figure 25.) They will set the test isolation bit by a push button, optical input, HMI, or remote or SCADA input on the local device.

The additional isolation status logic would be used in the receiver for tripping and local indication, as seen in Figure 26. This was a simple solution solving the need to know the state of the system in Edition 1.

Fig. 26: Programmed Status of Test Mode The release of Edition 2 helped clarify the test isolation with a clarity bit. The quality bit was clarified as the correct method for isolation and the test bit is now used for isolation. This allows the capability to control this bit with the preferred initiation method of a push button, remote bit or optical input. The test mode is now used as part of the quality bit. The quality bit is good when all bits are “OFF” and the test bit “ON” sets the Quality “OFF”. The receiver will still need to program logic for tripping, as seen in Figure 27. GOOSE Trip

&

Virtual Input 1 Quality VIP 1

Fig. 27

Trip outputs 3Ph

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Maintenance Vol. 3 This allows the isolation state to be known from its associated quality, but the test set must be able to report on the status of the quality. The test set and software additionally must be able to simulate the required number of SV streams (9-2 LE) and subscribe to multiple GOOSE messages and their individual dataset members. Also, they must be able to publish multiple GOOSE messages and control the status of their individual dataset members. They must be able to set the test/simulation bit of messages and set the quality test bits of associated data signals. The testing of merging units provided conventional voltages and currents, digital inputs and outputs simultaneously with IEC 61850 SV and GOOSE messages.

REFERENCES: General Electric Instructions GEK-49803, Test Plug for Molded Case Drawout Relays Types 12XCA11A1, 12XCA11A2, 12XCA28A1 General Electric Instructions GEI-25372D, Test Plugs for Drawout Relays and Meters XLA12A and XLA13A General Electric Instructions GEH-1023, Test Blocks and Plugs Types PK-2, 1953 Information Notice No. 85-83: “Potential Failures of General Electric PK-2 Test Blocks” NRC , October 1985 Southern California Edison SC&M Advisory, “Test Plug –Work Safe Practice”, November 2008 Test Field Manual Volume 1- Book 1 Relays Tennessee Valley Authority, PK Block Failures, 2010. IEC 61850 Edition 2 - "What does it mean for the end user?" By Christoph Brunner – IT4Power Consulting. By Rodney Hughes - Rodney Hughes Consulting, SEAPAC, CIGRA Australia Panel, March 2011

Fig. 28

Fig. 29: Selecting data set items for test as virtual in/outputs for test set

CONCLUSION Flawless test isolation is the most important task any tester must perform to prevent damage to equipment and to keep the tester safe. As technology has changed from electromechanical to digital systems, so has the need to understand and perform isolation for testing. Familiarization of isolation tools and new standards, such as IEC61850, the protective device and the power system, is essential to perform the job correctly.

Scott L. Short has worked for Doble Engineering since 2000. From 2002 to 2011, he was Regional Sales Manager for the Central United States. From 2011 to present, he has been the Director of Protection and Automation Technologies. Prior to his work with Doble Engineering Scott worked for the FirstEnergy Corporation in Akron, Ohio, as Principal Electrical Engineer supporting the distribution and transmission operating companies with substation technical testing and support. He also worked for the Tennessee Valley Authority in Chattanooga, Tennessee, as the Relay and Control Substation Maintenance Specialist. Other responsibilities include area engineer in Muscle Shoals Alabama. Scott was a Naval Nuclear Submarine Operator for the US Navy for the USSBN Casimir Pulaski and USSN Batfish. Scott’s experience includes Nuclear, Hydro, Gas and Fossil power generation. Scott is a Graduate of the University of Alabama, where he studied Electrical Engineering. Scott is a register member of the IEEE and a Professional Engineer.

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GAPS IN YOUR ELECTRIC MOTOR RELIABILITY PROGRAM PowerTest 2016 Noah Bethel, VP Product Development, PdMA Corporation

Businesses invest millions of dollars in what they believe will be a fail-safe maintenance program for their electric motors. Regular tests are scheduled for each motor; engineers dutifully record the data when required and then move on to the next motor. But collected data is meaningless unless it is analyzed, and frequently analysis is nonexistent. Here’s an example: data from testing may have uncovered a problem in a stator winding or rotor assembly, but there is no alarm in the testing mechanism because settings have not been updated for several years. The motor seems to be working normally even though the problem is worsening. When it fails as it inevitably will, the business is headed for a costly repair or …worst case scenario…catastrophic motor failure. The usual question that accompanies a call to repair facilities or support vendors: “how could we have missed this?”

The expenditures can be startling. A study published in Reliable Plant in February 2010 calculated average motor downtime costs per hour in several industries. The findings, based on a study conducted in the previous decade, are still relevant today. The statistics: Industry

Average Downtime Costs per Hour

Food processing

$30,000

Petroleum and Chemical

$87,000

Metal Casting

$100,000

Automotive

$200,000

There are, in fact, three areas where these gaps continually occur: quality control, trending and troubleshooting. Yet, all of these gaps can be averted and avoided through application of sophisticated technologies and a greater delineation of the responsibilities that will ensure a successful and cost-efficient motor management program.

Companies that expect technology to play a vital role in curbing these costs and greatly improving motor lifespan have relied on various software programs to provide data for specific purposes; i.e. motor problems or asset information management. The information is helpful but limited because it is not integrated with all of the other elements of motor management. Today that is not enough. Businesses are demanding intuitive and integrated software that tracks the history of repairs, mean times between failure and something more: identification of faults that can be corrected or remedied. What is needed is comprehensive software that meshes seamlessly with all elements of motor management. Businesses should not have to rely on separate technology systems that, despite the vital data they generate, are incapable of integrating data into one comprehensive motor management and maintenance model.

ELECTRIC MOTOR RELIABILITY PROGRAM BASICS

UNDERSTANDING ELECTRIC MOTOR FAULT ZONES

Every company regardless of size requires a world-class “cradle to grave” strategy and plan implementation for thorough motor management and maintenance. These steps ensure a lengthy and productive motor lifespan. To begin, start with qualification and asset tracking, including analysis of the systems in which the motors operate. Without this vital information, a company risks repeated expensive repairs or motor replacement. Worse yet, the actual cause of the motor’s issues may remain undetected—another gap example bound to anger the firm’s financial officers anxious to stem the cash outflow.

There can be no comprehensive motor management program without accounting for the role of the six fault zones that apply to all electric motor operations. The functions of each one and their relationship to the other five impact the motor’s efficiency and reliability in both the short and long term. Data analytics for each fault zone will help businesses uncover potential problems before they become catastrophic. The six fault zones consist of power quality, power circuit, insulation, stator, rotor, and air gap. Each of the six requires testing for signs of potential motor failure such as resistive imbalance in the power circuit, problems with insulation between the coils and phases in the stator, and defects in the rotor.

Costly oversights occur repeatedly despite thoughtful planning dedicated to maximizing the operation and lifespan of the motor. One unsettling realization is that testing, considered part and parcel of preventive maintenance, is not preventing anything because there is nothing to indicate that analyzing the data was even considered. This is a major pitfall and a classic example of a gap in a company’s motor management program.

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Maintenance Vol. 3 Tests for each of these fault zones depend on a number of variables such as motor age, intensity of use and, of course, the environment in which the motor operates. Despite the variables, testing has to be consistent to develop a clear picture of the data generated in each fault zone and the trends the information indicates.

QUALITY CONTROL Quality control (QC) is presumably paramount for asset management, yet it is here where some of the most costly gaps manifest themselves. Faulty assumptions play an underlying role particularly in one common QC oversight. A new motor is delivered from the warehouse but is not tested after installation. The faulty and potentially costly assumption is that brand new, mint condition motors are in perfect working order so testing at the start-up stage is unnecessary. When companies are so heavily invested in the reliability of their electric motors, it is almost shocking for immediate testing to be disregarded. Yet that is alltoo-often the case perhaps because of limited time and/or resources. The gaps will likely worsen when no one bothers to examine whether the facility supplying the motor has the same quality control standards as those of the company that purchased it. Alarm set points are another example. Pre-defined alarms and set points are based on an existing knowledge base and respected industry standards. Nonetheless, they should not be considered permanent. Industry standards tend to change especially when further study indicates that modification of set points is essential to avoid the possibility of parts failure. A robust quality control plan should contain the following: ●● Immediate testing after a new, refurbished or spare motor is installed. Avoid the assumption that testing isn’t necessary for a new installation; it always is. ●● Clearly defined quality control agreement with your motor repair facility. Ensure the shop has technology that can duplicate your testing capability. In addition to the obvious benefit, the agreement will allow the QC program to be fluid. Data can be trusted if it was derived from the same technology application. Ensure that the motor supplier or repair facility has the ability to perform the same testing. The QC plan should also contain a provision where the company’s data can be shared over the Internet with the motor shop, particularly in digital form so it can be stored as an historical trend. ●● Well-defined acceptance criteria. All values of motor quality control have to be worked out and accepted by the motor repair facility and supplier. A poorly defined plan is likely to contain less than acceptable values, which jeopardize the operation and lifespan of the motor. ●● A warehouse storage and maintenance plan to ensure reliability of assets. Spare motors that have been unused, particularly for lengthy periods, can also be at risk for failure and the time to find out is before they replace another motor. There are two

inexpensive ways to maintain quality control for spare assets. Manage the climate control as closely as possible, especially the humidity. Another valuable warehouse maintenance tactic: minimize vibration and rotate bearings to prevent bearing damage from the ball of the bearing sitting on the same spot of the housing in a vibrating environment.

TRENDING Trending refers to data collection on motors taken on a regular and consistent basis. Its purpose is to identify potential problems and, at the same time, develop a detailed history of any issues uncovered by the data. It is the latter where the gap most often occurs. Data is rarely analyzed because those who record it are not trained to analyze it. The result is data imbalance—a mass of statistics is collected but never analyzed. Technicians are often test takers and have not been trained in data analysis. The technicians follow designated “routes” or watch lists. They rely on their technology to explain what is happening with the motor. Their data may, in fact, indicate that something requires further examination. However, if there is no indication or alarm triggered during testing, technicians may log the information as “normal recurring events.” The data is stored and forgotten much like obsolete equipment in a vast warehouse. Companies may not be totally cognizant of the need for trending despite their financial commitment to motor management and maintenance. It is not the fault of the technicians, who have been trained to react promptly if their testing technology indicates alarms. If there is no alarm, undertrained technicians may presume that nothing is wrong so they move on to the next test. Perhaps cost controls and limited resources might explain why such testing is assigned to less knowledgeable resources. Because of the importance of trending to motor viability and longevity, companies should educate their technicians to go beyond the act of test-taking and recognize values that warn of fault zone issues that must be rectified. The point of motor trending is to identify problem areas before they become catastrophic and prohibitively expensive. That is unlikely when there is no consideration of data value that indicates a trend and potential costly oversight. Due to the existence of more sophisticated and automated technologies, management can take advantage of tools like the Site Condition Window that can open motor testing databases and conduct its own analysis. For management, the window is vital particularly for accessing data that was never analyzed and uncovering trends in fault zones that need to be addressed.

TROUBLESHOOTING Troubleshooting occurs after a component of the motor shows signs of malfunction, the motor is performing poorly or has failed. All motors will eventually reach an end of life condition no matter how well they have been maintained. The severity of the defect,

66 however, may depend upon how well the company maintained its QC and trending analysis. Troubleshooting will identify the defect and determine whether the problem is fixable (acceptable downtime and cost balanced against motor age and condition). It will also conclude that the asset is finished and must be replaced. As is the case with QC and trending, a well-defined troubleshooting plan is essential if there is any hope of restoring the motor to operational effectiveness. It is incumbent upon the company to include vendors in a written troubleshooting plan at its inception. This is a more preferable approach rather than a reactive and more expensive one, which occurs when companies call for help only when the motor is failing. The vendor can be a valuable resource in getting at the root cause of the problem before it occurs. Above all else, troubleshooting is not likely to be effective without a guideline—a detailed checklist that enables identification of root causes and minimizes time to return to productivity. There has to be a troubleshooting procedure that differentiates a fixable repair from end of life. An end of life situation in a fault zone may not necessarily mean permanent replacement of the entire motor or the expense of hiring a crane to remove the troubled asset to the repair facility. A power circuit anomaly, for example, can be fixed in place. Fault zone issues such as a stator winding anomaly may or may not be fixable in the factory. A western coal mine company can vouch for the importance of a troubleshooting guideline. Its coal conveyor belt motor blew the low voltage slip rings and could not be repaired in place. The company had a replacement motor on site and called for the crane for movement and installation because it assumed that start-up would be routine. The assumption was erroneous. The motor blew a fuse at start-up and appeared to be trying to turn in reverse of the desired direction. When the direction was changed, the motor blew another fuse. Similar efforts led to the same result—a total of six fuses, each valued at $1,000, were ruined, forcing the company to call for help on a Saturday, a day when repair charges are always at their highest. The electric company that responded used a state of the art technology in electric motor testing that uncovered an inductive imbalance in the stator winding. The technology then promptly identified the culprit—two reversed leads causing a phase inversion and a reverse torque that opposed the normal rotation. When the leads were corrected, the motor functioned normally. The coal company spent approximately $150,000 to correct a problem that would have been identified by a three-minute test before moving the motor into place.

Maintenance Vol. 3 MOTOR MANAGEMENT IN A CHANGING INDUSTRY Productive and long-lasting operation of motors in today’s business environment is the reason for development of advanced technology and site procedures to increase reliability and assure a quick return to productivity in the event of troubleshooting and repairs. The transition of data to usable information becomes more efficient when the analyst has help to make the right decisions. The most effective software creates an environment from point of data, point of analysis and point of decision through data integration and proper alarm set points. So the original question “How could we have missed this?” may best be answered by filling in the gaps. Noah Bethel, CMRP, is vice president of product development for PdMA Corporation, Tampa, Fla., a leader in the field of predictive maintenance, condition monitoring applications, and development of electric motor test equipment for motor circuit analysis. Tel: (800) 476-6463 or visit www.pdma.com.

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SYSTEM TESTING OF PROTECTION DEVICES AND SCHEMES – WHAT IS IT AND WHY DO WE NEED IT? PowerTest 2016 Alexander Apostolov and Will Knapek, OMICRON Electronics

INTRODUCTION

WHAT IS SYSTEM TESTING?

The IEC 61850 standard for communication networks and systems in substations allows the development of high-speed peerto-peer communications based distributed protection applications that result in significant changes in the ways protection functions are implemented. This replacement of functions implemented in a single device with equivalents using exchange of analog and status information over the substation local area network requires new technology also for their testing.

In order to properly define the methods for testing of complex IEC 61850 substation automation systems it is important to properly define what a system definition is and to consider what existing methods for system testing are known. Complex systems are not specific to the electric power systems domain only. They exist in industry, communications, computing and many other fields. Software development can be considered the development of complex systems that exchange information between different functional modules. Modern substation automation systems in reality are complex distributed software applications based on exchange of information over the substation local area network. That is why there are significant similarities between the testing of complex software tools and substation automation systems.

The paper describes in detail the principles of different IEC 61850 distributed applications and systems and analyses the factors that will affect their performance. The definitions of the individual components of distributed systems are presented in detail, including the different possible allocations of sub-functions and functional elements in physical devices. Each complex function actually represents a system with a different level of complexity depending on its design. Definitions of function boundaries and methods for testing dependent on the purpose of the test are then described. Type, acceptance, commissioning and maintenance testing are considered. It later discusses the requirements and principles of their testing. A comparison between the functional testing of conventional devices and testing of communications-based Intelligent Substation Devices (ISD) is described later in the paper. The paper then discusses some examples of distributed applications based on GOOSE messages and sampled analog values from the point of view of the requirements for their testing. Methods and tools for functional testing of distributed IEC 61850 based systems are presented at the end of the paper. Full, partial and hybrid implementations of IEC 61850 are analyzed. The different steps in the testing process are described. They include the configuration, simulation, operation detection and results analysis. The impact of non-protection related events on the performance of distributed functions and how it can be covered in the test process is presented at the end of the paper.

IEC 61850 defines a system as “The logical system is a union of all communicating application-functions performing some overall task like “management of a substation,” via logical nodes. The physical system is composed of all devices hosting these functions and the interconnecting physical communication network. The boundary of a system is given by its logical or physical interfaces. Within the scope of the IEC 61850 series, "system" always refers to the Substation Automation System (SAS), unless otherwise noted”. This is not very far from an abstract definition of a system as a group of interacting, interrelated or independent elements forming a complex whole. Each component of a system is interacting or related to at least one other component/element. Any object which has no relationship with any other element of the system is obviously not a component of that system. Depending on the complexity of the system, its components can be simple functional elements, subsystems or combination of the two. A subsystem is then defined as a set of elements, which is a system itself, and also a part of the whole system. In the substation protection and automation domain we can consider different functions performed by the system as subsystems. The hierarchy of a complex system is shown in Figure 2 as a UML diagram.

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Maintenance Vol. 3 Functional testing of any function or subfunction requires from the test designer to select a set of valid or invalid inputs and determine the correct expected output for each test condition defined in the test plan. This will serve to define the evaluation criteria to determine if the test result is PASS or FAIL. The purpose of functional element testing is to determine if the tested element has the expected behavior under different realistic test conditions. The functional elements in system testing are considered units, i.e. the smallest components of the system that have visible interface and defined behavior. From the testing point of view we can say that a unit is the smallest testable part of any system. Integration testing is used to detect any potential interoperability problems between the functional elements and/or subfunctions that are integrated together in a function or a system. It not only tests the performance of the system, but also observes the exchanges between the different components being integrated into a system. Fig. 1: System hierarchy UML diagram

From Figure 1 it can be seen that the system can contain 1 to many functions, that can have several layers of 1 to many subfunctions and at the bottom – a subfunction can contain 1 to many functional elements. The functional elements correspond to the IEC 61850 logical nodes. System testing is testing conducted on a complete, integrated substation automation system, subsystem or distributed function. Its goal is to evaluate the system’s compliance with its specified requirements. System testing falls within the scope of Black Box Testing. This means that the test system does not have to have any knowledge of the internal logic and the behavior of the different subsystems or functional elements included in it. System testing can be performed in a top-down or bottom-up approach. This is to a great extent dependent on the purpose of the test. If the test is a factory acceptance test it might be a good idea to use the bottom-up approach. In this case the testing starts first with the individual parts of the system – the functional elements. They are then grouped together to form sub-functions or functions, which are in turn linked into more complex functions until the complete system is tested. When we do commissioning or maintenance testing we assume that the individual functional elements are operating properly, especially if there are no alarms in any of the IEDs that are included in the system test. In this case a top-down approach is suitable, since we are interested in the overall performance of the tested system function and not in the behavior of the components of the system. Most of the time it fits the Black Box approach, which means that we take an external perspective of the test object to derive the test cases and analyze the results.

Fig. 2: Function boundary definition System testing looks at the overall performance of the system from an external observer point of view. In the top-down testing model the system is defined as a whole with its boundaries and behavior, without considering the details for any part of it. Each sub-part of the system then can be tested using the same approach until we get to the bottom of the functional hierarchy where we perform the functional elements testing. In bottom-up testing we start with the functional elements testing and then go up the functional hierarchy testing sub-functions until we finish with the overall system testing. In all cases it is important to clearly identify the system or function boundary that will define the requirements for simulation by the test system and monitoring the behavior of the tested function. In Figure 2 above SF indicates a subfunction that contains K functional elements. The functional elements are the smallest component in the system that can be defined with a function boundary, interface and behavior, i.e. that can be tested.

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Maintenance Vol. 3 All the above described principles can be used in the testing of IEC 61850 based substation protection and automation systems.

The following sections discuss in more detail the different testing methods listed above.

FUNCTIONAL TESTING METHODS

BLACK BOX TESTING

Functional testing methods can be divided into several categories. They are related to the complexity of the functionality of the individual devices being used in the different levels of the hierarchical system, as well as the types of distributed functions implemented in it.

Black Box Testing is a very commonly used test method where the tester views the test object as a black box. This means that we are not interested in the internal behavior and structure of the tested function.

The following are the more commonly used testing methods: ●● Functional element testing ●● Integration testing ●● Function testing ●● System testing A function in this case can be considered as a sub-system with different level of complexity; for example a system monitoring function, while the system is the complete redundant scheme. Regardless of what is being tested, the test object needs to meet the requirement for testability. This is a design characteristic which allows the status (operable, inoperable, or degrade) of a system or any of its sub-systems to be confidently determined in a timely fashion. Testability attempts to qualify those attributes of system design which facilitate detection and isolation of faults that affect system performance. From the point of view of testability a functional element in a scheme is the unit that can be tested, because it is the smallest element that can exist by itself and exchange information with its peers in the scheme.

In the case of black box testing the test system is only interested in finding conditions under which the test object does not behave according to its specifications. Test data are derived solely from the specifications without taking advantage of knowledge of the internal structure of the function. Black box testing is typically used for: ●● functional elements testing ●● scheme factory testing ●● scheme site acceptance testing Since functional elements are defined as units that are the smallest that can exist independently and are testable, it is clear that black box testing is the only method that can be used for their testing.

Another consideration is the purpose of the test and needs to clarify if the tests are performed in relation to acceptance of a new product or function to be used as a system monitor or process controller (or both), the engineering and commissioning of a substation component or the complete scheme or its maintenance. From that perspective different testing methods can be implemented even in the testing of the same functional element or function. For example the testing of a function during the user acceptance phase may focus on the testing of the measuring element characteristic using search test methods, while during the commissioning the operating times for different system conditions be the important ones achieved through transient simulation methods. The knowledge of the internal behavior of the test object or more specifically the logic or algorithms implemented determines how the tests are being executed. The most commonly used test methods from this point of view are: ●● Black box testing ●● White box testing An important aspect that needs to be considered during the testing is the availability of redundant devices performing the different scheme functions.

Fig. 3: Black Box Testing The response of the test object to the stimuli applied to the test object inputs can be monitored by the test system using the operation of physical outputs, communications messages or reports.

WHITE BOX TESTING White box testing is a method where the test system is not only concerned with the operation of the test object under the test conditions, but also views its internal behavior and structure.

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Maintenance Vol. 3 the test system to be able to simulate their operation as expected under the test scenario conditions. In this case the test system creates the so called Stubs for functions or functional elements that are not yet available. Top-down testing results in re-testing of higher level elements when new lower level elements of the system are added. The adding of new elements one by one should not be taken too literarily. Sometimes a collection of elements will be included simultaneously, and the whole set of elements will serve as test harness for each functional element test. Each functional element is tested according to a functional element test plan, with a top-down strategy.

Fig. 4: White Box Testing In the case of SCHEME it means that it will not only monitor the operation of the system at its function boundary, but also monitor the exchange of signals between different components of the system. The testing strategy allows us to examine the internal structure of the test object and is very useful in the case of analysis of the behavior of the test object, especially when the test failed. In using this strategy, the test system derives test data from examination of the test object’s logic without neglecting the requirements in the specification. The goal of this test method is to achieve high test coverage through examination of the operation of different components of a complex function and the exchange of signals or messages between them under the test conditions.

A testing stub is a module which simulates the operations of a module which is invoked within a test. The testing stub can replace the real module (for example a line monitor) for testing purposes. The testing of the individual components of a system function might be required in the case of failure of a specific test, which is shown in Figure 5. The function boundary for each of these tests will be different and will require a different set of stimuli from the test system, as well as the monitoring of the behavior of the functional elements using different signals or communications messages. For example if Test 1 (see Figure 5) of the complete scheme fails, the user needs to start testing subfunctions down the scheme functional hierarchy. If any of these Test 2 level tests fails, then Test 3 level tests need to be performed, until eventually a failure of a function element at the bottom of the hierarch is detected.

This method is especially useful when we are testing distributed functions based on different logical interfaces. The observation of the behavior of the sub-functions or functional elements is achieved by the test system through monitoring of the exchange of messages between the components of the test object. The test scenarios however do not have to be different from the ones used under black box testing.

TOP-DOWN TESTING Top-down testing is a method that can be widely used for a scheme, especially during site acceptance testing, when we can assume that all the components of the system have already been configured and tested. Top-down testing can be performed using both black box and white box testing methods. The testing starts with the complete system, followed by function or sub-function testing and if necessary functional element testing. In the case of factory acceptance testing, when not all components of a system or sub-system are available, it is necessary for

Fig. 5: Top-down testing of a system monitoring function

BOTTOM-UP TESTING Bottom-up testing is a method that starts with lower level functions – typically with the functional elements used in the system – for example FE1, FEi, etc..

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Maintenance Vol. 3 This method is more suitable for type testing by a manufacturer or acceptance testing by the user. When testing complex multilevel functions or systems, driver functional elements must be created for the ones not available. The test system must be able to simulate any missing component of the system when performing for example factory acceptance testing.

The first component of the test system is the test Configuration Tool. It takes advantage of one of the key components of the IEC 61850 standard – the Substation Configuration Language. The Configuration Tool is used to create the files required for configuration of different components of the test system. It imports or exports different configuration files defined by Part 6 of IEC 61850.

There are many similarities in the test scenarios used in the bottom-up, compared to the top-down method. The main difference between the two methods is the order that the tests are performed and the number of tests required.

The test system Configuration Tool reads the information regarding all IEDs, communication configuration and substation description sections. This information is in a file with .SCD extension (for Substation Configuration Description) and is used to configure the set of tests to be performed.

TESTING OF IEC 61850 SYSTEMS

The overall functionality of any IEC 61850 compliant device is available in a file that describes its capabilities. This file has an extension .ICD for IED Capability Description.

The method for testing of both types of systems is proposed based on the following order of system components tests: ●● Testing of IEC 61850 protocol compliance of the individual components of the system ●● Testing of merging units ●● Testing of IEC 61850 compliant IEDs ●● Testing of bay level distributed applications ●● Testing of substation level distributed applications The goal of conformance testing is to ensure that IEC 61850 with all its models and services is properly implemented. The test procedures and tools used are based on the definitions in Part 10 of the standard. This improves the chances for interoperability between the individual devices integrated in the system. A test system designed for IEDs or distributed systems based on IEC 61850 have multiple components that are needed for the testing of the individual functions, as well as a complete application. A simplified block diagram of such a system is shown in Figure 7.

The IED configuration tool sends to the IED information on its instantiation within a substation automation system (SAS) project. The communication section of the file contains the current address of the IED. The substation section related to this IED may be present and then shall have name values assigned according to the project specific names. This file has an extension .CID (for Configured IED Description). The second component of such a system is a Simulation Tool that generates the current and voltage waveforms. The specifics of each simulated test condition are determined by the complete, as well as the configured functionality of the tested device or application. The simulation tool requirements will also be different depending on the type of function being tested. For example, if the tested function is based on RMS values or phasor measurements, the simulation tool may include a sequence of steps with the analog values in each of the steps defined as Phasors with their magnitude and phase angle. Based on these configuration parameters the simulation tool will generate the sine waveforms to be applied as analog signals or in a digital format to the tested components or systems.

CONCLUSIONS System testing requires a very good understanding of the functionality and the hierarchy of the protection, automation and control system. The definition of a function or a system boundary and the behavior of the test object is essential for the proper definition of the different test cases, the testing system and the evaluation of the performance during the testing. Depending on the purpose of the test, different methods can be used: ●● Bottom-up Fig. 7: Test system/configuration tool, simplified block diagram

●● Top-down ●● Black box ●● White box

72 Testing of an IEC 61850 based system adds another dimension and requires the availability of a test system that can support both GOOSE and sampled values publishing and subscriptions based on SCD files for its configuration. Alexander Apostolov received MS degree in Electrical Engineering, MS in Applied Mathematics and Ph.D. from the Technical University in Sofia, Bulgaria. He has more than 35 years’ experience in power systems protection, automation, control and communications. He is presently Principal Engineer for OMICRON electronics in Los Angeles, CA. He is IEEE Fellow and Member of the Power Systems Relaying Committee and Substations C0 Subcommittee. He is past Chairman of the Relay Communications Subcommittee, serves on many IEEE PES Working Groups and is Chairman of Working Groups C2 “Role of Protective Relaying in Smart Grid” and D21 “Contribution to IEC TC 95 WG MT4 Protection Functions Testing”. He is member of IEC TC57 and Convenor of CIGRE WG B5.27 ”Implications and Benefits of Standardized Protection Schemes” and member of several other CIGRE B5 working groups. He holds four patents and has authored and presented more than 400 technical papers. He is IEEE Distinguished Lecturer and Adjunct Professor at the Department of Electrical Engineering, Cape Peninsula University of Technology, Cape Town, South Africa. William Knapek received a BS degree in Industrial Technology from East Carolina University in 1994. He retired from the US Army as a Chief Warrant Officer after 20 years of service in 1995. During his time with the Army Corps of Engineers, he held positions as a power plant instrumentation specialist, a writer/instructor for the Army Engineer School, and a Facility Engineer for a Special Operations compound. He has been active in the electrical testing industry since retiring in 1995. He worked for NETA companies in the Nashville, TN area until joining OMICRON electronics as an application engineer in April of 2008. He is currently the Sales Manager for the Southeast Area of North America for OMICRON electronics Corp, USA. He is certified as a Senior NICET Technician and a former NETA Level IV technician. Will is a member of IEEE and vice chair of WG I23 of the PSRC.

Maintenance Vol. 3

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

6

alabama 1

2

3

4

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

22

23

29

Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

26

27

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

36

37

30

Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

46

47

48

49

Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

58

florida 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

missouri 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

151

152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

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Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

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POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

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tennesee 181

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189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

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Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

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Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

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CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

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235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

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ANDBOOK

VOLUME 1

SERIES III

PROTECTIVE RELAY

PROTECTIVE RELAY Vol. 1 HANDBOOK

SERIES III

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PROTECTIVE RELAY VOLUME 1

HANDBOOK

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InterNational Electrical Testing Association

PROTECTIVE RELAY–Vol. 1 HANDBOOK TABLE OF CONTENTS Applying 100% Stator Ground-Fault Protection for Generators via Low Frequency Injection............................................................... 5 Steve Turner

Meaningful Testing of Protection Schemes........................................................... 10 J. P. Gosalia

How to Implement Symmetrical Components into Relay Testing.............................. 16 Jason Buneo

Simplified Motor Relay Testing........................................................................... 22 Chris Werstiuk

Test the System, Not the Elements...................................................................... 48 Will Knapek

Open-Circuited CT Misoperation and Investigation.............................................. 52 David Costello

Understanding and Testing Motor Overload Protection and Thermal Models............ 62 Nestor Casilla

Application of a Multifunctional Distance Protective IED in a 15kV Distribution Network............................................................................... 69 Jack Chang, Lorne Gara, Yordan Kyosev, Peter Fong

Interconnection Issues....................................................................................... 75 James G. Cialdea

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InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

Fault Clearance on Grounded Conductors.......................................................... 76

Jeff Jowett

Electrical Commissioning: Top Priorities to Ensure a Successful Project.................... 80 Dan Hook and Tim Conley

Modern Advances in Testing Multifunction Numerical Transformer Protection Relays............................................................................ 83 Steve Turner

Testing Numerical Distribution Relays Using Relay Vendor Software Tools................ 90 Steve Turner

Acceptance, Commissioning, and Field Testing for Protection and Automation Systems.................................................................................. 94 Michael Obrist, Stephan Gerspach, and Klaus-Peter Brand

Condition Monitoring: Automating Response....................................................... 98 Tony McGrail

Evaluating Digital Relay Testing Strategies........................................................ 100 Brian Cronin

Going Beyond Automated Relay Testing: Using Power System Models.................. 103 Steve Turner

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Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Protective Relay Vol 1

APPLYING 100% STATOR GROUND-FAULT PROTECTION FOR GENERATORS VIA LOW FREQUENCY INJECTION Powertest 2013 Steve Turner, Senior Member, IEEE

INTRODUCTION

GROUNDING TRANSFORMER TURNS RATIO (N):

One hundred percent stator ground-fault protection is provided by injecting a 20 Hz voltage signal into the secondary of the generator neutral grounding transformer through a band-pass filter. The band-pass filter passes only the 20 Hz signal and rejects out-ofband signals. The main advantage of this protection is 100% protection of the stator windings for ground-faults―including when the machine is off-line (provided that the 20 Hz signal is present).

APPLICATION Fig. 1 illustrates a typical application. A 20 Hz voltage signal is impressed across the grounding resistor (RN) by the 20 Hz signal generator. The band-pass filter only passes the 20 Hz signal and rejects out-of-band signals. The voltage across the grounding resistor is also connected across the voltage input (VN) of the 64S relay. The current input (IN) of the 64S relay measures the 20 Hz current flowing on the grounded side of the grounding transformer and is stepped down through a CT. It is important to note that the relay does not measure the 20 Hz current flowing through the grounding resistor. The 20 Hz current increases during ground-faults on the stator winding and an overcurrent element that operates on this current provides the protection.

20 Hz Generator

20 Hz Band Pass Filter 1B1

RN L

K

l

k

1A3

-VAux

2A3

Wiring Shielded

3A3 4A3

CAPACITIVE REACTANCE The total capacitance to ground of the generator stator windings, bus work and delta connected transformer windings of the unit transformer is expressed as C0. Generator step up transformers have delta-connected windings facing the generator so capacitance on the high side is ignored. The corresponding capacitive reactance is calculated as follows:



(2)

The capacitive reactance for 1 micro-Farad is equal to:

Reflect the capacitive reactance to the secondary of the grounding transformer:

The ohmic value of the grounding resistor can be sized as follows to avoid high transient overvoltage due to ferroresonance:

3A2 1A4

N = 8,000 (1) 240

GROUNDING RESISTOR (RN)

2A1

Bl 1A1 Neutral Grounding Transformer

1A2 1A3

4A1

1B4

1A1

Supply Voltage DC +VAux

Assume that the turns ratio of the grounding transformer is equal to:

3A1

High Voltage

20 Hz CT

64S Relay Low Voltage

44

45

52

53

59N

VN IN

Fig. 1: 20 Hz Voltage and Current 64S Relay Measurements The following shows how to calculate the 20 Hz voltage and current measured by the 64S relay.

This example uses a 2.5 ohms secondary value.

6

Protective Relay Vol 1

20 HZ SIGNAL GENERATOR AND BAND-PASS FILTER CHARACTERISTICS Assume that the 20 Hz signal generator outputs 25 volts. The band-pass filter has a resistance equal to 8 ohms.

(4) (5)

STATOR INSULATION RESISTANCE (RS) RS is the insulation resistance from the stator windings to ground. A typical value for non-fault conditions is 50,000 ohms primary.

20 Hz Current (IN) Measured by 64S Relay The current input (IN) of the 64S relay measures the 20 Hz current flowing on the grounded side of the grounding transformer and is stepped down through a CT. As noted previously, the relay does not measure the 20 Hz current flowing through the grounding resistor. Total 20 Hz Current Supplied by Signal Generator―The 20 Hz signal generator looks into the band-pass filter resistance (RBPF) which is in series with the parallel combination of the following: Zco RS RN Therefore, the total loop impedance of the 20 Hz grounding network can be expressed as follows:

CURRENT TRANSFORMER

(7)

(3)

The current input (IN) of the 64S relay measures the 20 Hz current flowing on the grounded side of the grounding transformer 1 and is stepped down through a CT. CTR = 80/1

The total 20 Hz current supplied by the signal generator is determined as follows:

(6)

(8)

GROUNDING NETWORK Now there are all of the elements needed to mathematically represent the grounding network and determine the 20 Hz signals measured by the 64S relay. Fig. 2 shows the insulation resistance and the stator windings referred to the primary of the grounding transformer. RFilter = 8 Ohms

N XCP

RN

RStator

V

25 V 20 Hz

20 Hz Current Measured by 64S Relay (IN) during Non-Faulted Conditions―The 20 Hz current measured by the 64S relay is the ratio of the total current that flows into the primary side of the grounding network (Zco//RS):

(9)

CT = 400:5

Fig. 2: 20 Hz grounding network –referred to primary of grounding transformer Fig. 3 shows the insulation resistance and the stator windings referred to the secondary of the grounding transformer. 8 Ohms

XCS

RS

It

RN

V

25 V 20 Hz

CT = 80:1

Fig. 3: 20 Hz grounding network–referred to secondary of grounding transformer

20 Hz Current Measured by 64S Relay (IN) during Ground-Fault on Stator Windings―A typical value to represent the insulation resistance of the stator windings breaking down during a groundfault is 5,000 ohms primary. If the calculations for Equations (7) through (9) are repeated for a fault resistance equal to 5,000 ohms primary (4.5 ohms secondary), then the 20 Hz current measured by the relay is as follows: |IN| = 13.486 mA (5,000 ohm primary ground-fault) If the calculations for (7) through (9) are repeated for a fault resistance equal to 1,000 ohms primary (0.9 ohms secondary), then the 20 Hz current measured by the relay is as follows: |IN| = 26.640 mA (5,000 ohm primary ground-fault)

7

Protective Relay Vol 1 Table 1 summarizes the 20 Hz current measured by the relay for non-faulted and faulted conditions. RS (primary)

(10)

|IN| (secondary)

50,000 Ω

09.779 mA

5,000 Ω

13.486 mA

1,000 Ω

26.640 mA

(11)

Table 1: 20 HZ Current Measurements Set the pickup of the 64S relay overcurrent element above the current measured during normal operating conditions but below the current measured for a ground-fault equal to 5,000 ohms primary.

Real Component of 20 Hz Current Measured by 64S Relay Calculate the real component of the relay current based upon the angle between the relay voltage and current. (12) (13)

PRACTICAL CONSIDERATIONS There are three additional important aspects to consider when applying 100% stator ground-fault protection by 20 Hz injection: ●● Slight change in fault current measured by relay

RS (primary)

Re(IN) 0.198 mA 1.900 mA 8.001 mA

|IN| (secondary)

●● Rejection of fundamental frequency (50 or 60 Hz) voltage and current signals

50,000 Ω

12.465 mA

0.198 mA

5,000 Ω

12.096 mA

1.900 mA

●● Under-frequency inhibition

1,000 Ω

12.863 mA

8.001 mA

Slight Change in Fault Current A very large system capacitance (C0) and a small value for the grounding resistor (RN) can result in very little margin between the fault and non-fault current measured by the relay. Consider the following grounding network parameters:

Determine the 20 Hz current measured by the 64S relay for non-faulted and ground-fault conditions using the equations presented in the application section. RS (primary)

|IN| (secondary)

50,000 W

12.465 mA

5,000 W

12.096 mA

1,000 W

12.863 mA

Table 2: Current Measurements for High Capacitance The 64S relay overcurrent element pickup cannot be set such that it can reliably discriminate between non-faulted and groundfault conditions. The solution is to calculate the real component of the 20 Hz current measured by the 64S relay. To do so, first determine the 20 Hz voltage measured by the relay voltage input (VN). The 20 Hz voltage is equal to the drop across the grounding resistor due to the ratio of the total current flowing through this branch of the grounding network.

Table 3: 20 HZ Current Measurements for High Capacitance Including Real Component An overcurrent element that operates on the real component of 20 Hz current measured by the 64S relay can reliably distinguish between non-faulted and ground-fault conditions when there is high-capacitive coupling to ground on the stator winding. To decide if the real component of 20 Hz current is necessary, a good rule of thumb is if C0 is greater than 1.5 micro-Farads and the grounding resistor is less than 0.3 ohms secondary. The user can follow the commissioning instructions that appear at the end of this paper to determine the total capacitance to ground (C0). If the values for RN and C0 do not clearly fall under the category defined by this rule of thumb then use the equations provided earlier in this paper to determine if the real component of neutral current is necessary. The 64S should have an overcurrent element that operates on the total neutral current IN and another overcurrent element that operates on the real component of IN. The user should be able to enable either overcurrent element.

Rejection of Fundamental Frequency (50 or 60 Hz) Voltage and Current Signals Fundamental component voltage and current present at the relay measuring inputs during stator ground-faults can cause the 64S relay to not operate properly unless they are well rejected. Note that these signals are not eliminated by the band-pass filter since they are due to the voltage drop across the secondary of the grounding transformer. Fig. 4 illustrates the fundamental voltage drop (50 or 60 Hz) across the grounding resistor as a function of the ground-fault location along the stator windings. Table 4 shows the voltage drop as

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Protective Relay Vol 1

the fault location moves from the neutral side of the stator windings to the phase side. Assume the grounding transformer is rated 110 volts secondary, the grounding resistor is sized 0.32 ohms secondary and the CT ratio is 80:1. The corresponding fundamental component circulating current is shown as well. If the fundamental current is not well rejected, then high current can saturate the CT inside the 64S relay and the protection will measure a value of 20 Hz current less than the actual. Saturation causes the following problems:

runs downhill to another reservoir and turns a generator turbine to provide power during periods of high demand. The machine is operated as a motor during lightly loaded system conditions and pumps the water back up to the top reservoir. The machine is brought online and up to full speed via a back-to-back start from another running machine.

●● Delayed operation or, even worse, no operation at all. ●● Less than 100% coverage of the stator windings as the ground-fault location moves towards the phase side. Saturation is most likely to occur when the grounding resistor is sized less than one ohm secondary. 100%

0% FAULT LOCATION

Stator Windings

NEUTRAL

TERMINAL

Is Rn

Vs

Fig. 5: Voltage and current measured by 64S relay during start-up

400/5 A

Fig 4: Fundamental voltage across RN as function of ground-fault location Fault Location

VS

IS

IS/CTR

Table 5 provides a description of each channel and the magnitude. Channel

|Frequency

Magnitude

VN

Total

3.986 volts

100% (phase side) 110 V

(110 V)/0.32 Ω = 343.75 amps

4.297 amps

VN

20 Hz

98 mV

90%

99 V

(99 V)/0.32 Ω = 309.375 amps

3.867 amps

IN

Total

68.550 mA

80%

88 V

(88 V)/0.32 Ω = 275 amps

3.438 amps

IN

60 Hz

62.847 mA

70%

77 V

(77 V)/0.32 Ω = 240.625 amps

3.008 amps

IN

20 Hz

3.253 mA

60%

66 V

(66 V)/0.32 Ω = 206.25 amps

2.578 amps

50%

55 V

(55 V)/0.32 Ω = 171.875 amps

2.148 amps

Commissioning Instructions

40%

44 V

(44 V)/0.32 Ω = 137.5 amps

1.719 amps

30%

33 V

(33 V)/0.32 Ω = 103.125 amps

1.289 amps

20%

22 V

(22 V)/0.32 Ω = 68.75 amps

0.859 amps

10%

11 V

(11 V)/0.32 Ω = 34.375 amps

Fig. 6 below illustrates how to configure the grounding network during initial commissioning. You can determine the total capacitance to ground and calculate the overcurrent pickup setting based upon these field measurements.

0.430 amps

0% (neutral side)

0

0

0

Table 5: Channel Description and Magnitudes

Table 4: Fundamental Voltage Drop Across Grounding Resistor and Circulating Current Fig. 5 shows the voltage and current measured by a 64S relay during start-up of a generator at a pump storage facility. Pump storage works as follows. A large body of water held in one reservoir

Fig. 6: 20 Hz grounding network for Commissioning

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Protective Relay Vol 1 Normal Operating Conditions Configure the power system as follows: ●● High side breaker is open ●● Generator terminals are connected to delta windings of the generator step up transformer Switch F1 is open Switch F2 is open ●● 20 Hz signal generator is online Measure the following 20 Hz signals: VN (neutral voltage) IT (total 20 Hz current supplied by the signal generator) IN (neutral current) VN and IN are the 20 Hz signals applied to the relay inputs. Record IN as IN NOC. Modern numerical generator relays typically meter both of these values. These signals correspond to normal operating conditions. You can apply these values to equations (8) and (9) to solve for the total capacitance to ground (C0).

Stator Ground-Fault at Machine Neutral Place a single line to ground-fault at location F1 and measure the 20 Hz IN. This measurement corresponds to a short circuit applied at the neutral of the machine. Record this value as IN F1. Set the 64S overcurrent relay pickup such that it does not pickup during normal operation. The pickup should operate for a short circuit at either location F1 or F2. Set the pickup sensitive enough to detect a stator ground-fault with up to at least 5,000 ohms primary of ground-fault resistance if possible.

CONCLUSIONS This protection provides 100% coverage of the stator windings for ground-faults including when the machine is off-line. The total capacitance-to-ground of the generator stator windings, bus work and delta-connected transformer windings of the unit transformer is a very important factor and must be known to ensure the protection settings are correctly determined. There are cases when it is hard to distinguish between normal operating conditions and an actual ground-fault unless special steps are taken in the design of this protection. A good rule of thumb to decide if the real component of 20 Hz current is necessary is when C0 is greater than 1.5 micro-Farads and the grounding resistor is less than 0.3 ohms secondary. Use the real component of the 20 Hz current measured by the relay for these cases. The protection must reject fundamental frequency (50 or 60 Hz) voltage and current signals that are present at the relay measuring inputs during ground-faults on the stator windings. Use an under-frequency element that operates on the system voltage to block the 64S relay if nuisance tripping occurs during either startup or shutdown of the generator.

REFERENCES C. Russell Mason, The Art and Science of Protective Relaying (Wiley: 1956): 209 – 210. 1

Steve Turner is a Senior Application Engineer at Beckwith Electric Company, Inc. He has more than 30 years of experience, including working as an application engineer with GEC Alstom for five years, primarily focusing on transmission line protection across the United States. He was an application engineer in the international market for SEL, Inc., again focusing on transmission line protection applications including single pole tripping and series compensation around the world. Steve wrote the protection-related sections of the instruction manual for SEL line protection relays, as well as many application guides on various topics such as transformer differential protection, out-of-step blocking during power swings, and properly setting ground distance protection to account for mutual coupling. Steve also worked for Duke Energy (formerly Progress Energy) in North Carolina, where he developed a patent for double-ended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Texas A&M Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and serves in the IEEE PSRC.

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Protective Relay Vol 1

MEANINGFUL TESTING OF PROTECTION SCHEMES Powertest 2013 J. P. Gosalia, Doble Engineering Company

INTRODUCTION Many utilities are downsizing their organizations in order to become more competitive. However, downsizing only works if new technologies are implemented so that the organization becomes more efficient with fewer people. In relay testing there are many procedures that were created in 1950 with then the current technology. In 1950, slide rules were used to perform complex calculations, Electro-mechanical techniques were used for relay designs and passive components were used for test equipment. In 1990, technology has changed dramatically. The advancement in digital signal processing and microprocessor technology allows the relay design engineer to design state of the art relay protection scheme. Modern relay systems are multi-function digital devices that are designed to provide complete protection for a power system component like line, transformer, generator etc. Some of the newer designs have over 2000 setting possibilities and require extensive configuration and setting procedures. The traditional method of testing individual Steady-State calibrations is no longer viable because of the excessive time required to reconfigure each individual element. With the modern test equipment we can, and should, do things differently in order to improve productivity. By testing the protection scheme under power system condition using modern test instruments the performance of the protection scheme can be ensured. Dynamic relay testing means testing under simulated power system conditions. A report from IEEE Power System Relaying Committee entitled Relay Performance Testing discusses how dynamic-state testing and transient simulations provide a far better understanding of how the relay system performs. By making a profile of the operation of the scheme, malfunctions can be found faster because it is easier to identify the changes in areas that don’t operate the way they are expected. The objective of this paper is to present the different test methods their advantages and limitations. The paper also describes the use and advantages of performing satellite synchronized end-to-end test.

TRADITIONAL RELAY TESTING Historically, users performed relay testing using passive components such as variacs, load boxes and phase shifters. These

tests only verified the relay setting and gave no indication of how the relay would operate under power system conditions. With the passive test instruments, this was the best that could be done. Traditional test methods are not only time consuming but also do not provide confidence that the relay will properly operate under power system conditions. The interaction of the relay’s in-built protection features and how they are affected by power system conditions need to be evaluated to truly understand the relay’s performance.

TYPES OF RELAY TESTING As relay designs became more advanced with the solid-state and microprocessor-based technology, advanced test methods should be used to test the relays, protection schemes and systems. The types of relay testing are: ●● Integrity testing ●● Application testing

Integrity Testing This test establishes whether the relay was manufactured, delivered, installed, and maintained according to the relay’s published specifications. Integrity testing is normally performed as acceptance testing and for periodic testing to check the relay. Integrity Testing is also called Steady State testing or routine testing.

Application Testing This test is performed after the Integrity Test. Application testing provides more comprehensive tests to ensure that the performance of the relay is satisfactory for its intended application. This is especially important when published specifications do not provide adequate detail to be sure of proper application. The test is performed by either DFR playback of specific fault disturbances or play back of the waveforms created by mathematical simulation to assess relay performance. Scheme testing using dynamic or transient testing falls in to this category.

Steady-State Testing (Integrity Testing) In Steady-State Testing, phasor quantities are held stable for duration much longer than the operating time of the relay, and then are varied in increments much smaller than the resolution of the relay.

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Protective Relay Vol 1

Certain assumptions are made in Steady-State Testing of distance relays as shown in Figure 2.

Fig. 2

Fig. 1 The reasons to perform Steady-State Testing are: ●● To confirm relay settings. ●● To determine faulty components of the relay. In the case of digital relays, Steady-State Testing can reveal the defects in functioning of coils, capacitors, and resistors. For Electro-mechanical relays, it can reveal weakened springs, dirty contacts or loose setting screws that may have vibrated loose and caused the settings to drift. Steady-State Testing can be very time consuming. Automation of SteadyState Testing provides many advantages. Some of the advantages are listed below. ●● Reduced Testing time ●● Provides consistent test methods so that results obtained can be used to evaluate the relay condition. ●● Increased productivity of testing personnel, which results in increased job satisfaction and variety. ●● Reduced protection maintenance cost and increased reliability ●● Testing automation allows trending of historic test data, which can be used for scheduling test intervals. The procedures for these tests are based on the assumption that users only had basic test components available, such as variacs, load boxes and phase shifters. In Steady-State Testing phasors are slowly varied to determine relay settings (Figure 1). If the relays passed the test, all that was known that the relay is set correctly. All the components of a scheme are being tested this way to ensure their setting. With the Steady-State Testing, how the scheme will operates in service and under power system condition is not known?

These tests do not simulate power system conditions and the important circuits like polarizing and memory circuits are not being tested. For these reasons, Steady-State Testing results should only be used for reference, as these tests do not test relays under power system conditions. In the past for more definitive tests under power system conditions, users could model their power system on a simulator at the manufacturer’s site, but this was very expensive and time consuming. Therefore, only protection schemes that were to be applied on critical applications were tested this way, using either a PTL (Programmable Transmission Line), TNA (Transient Network Analyzer), or ATL (Artificial Transmission Line).

Application Testing: Dynamic-state Testing To ensure the performance of the scheme for the intended application, the scheme should be checked under power system condition. Before the application of a particular scheme, requirements of the protection scheme for the intended application need to be identified. Relay protection scheme design is characterized by two major considerations: ●● Security: the measure of the relay not to misoperate for an external fault conditions ●● Dependability: the measure of the relay to operate for an internal fault conditions These two considerations define relay reliability. The system component to be protected must be reviewed with regard to the power system as a whole, to establish the priority needed. As shown in Figure 3, the protection cannot be designed to provide both high security and high dependability, so the protection needs to be tested in a way that ensures the most important considerations are satisfied for a particular application.

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Protective Relay Vol 1 Test data for dynamic simulation can be calculated using short-circuit programs, fault simulation software or recordings of Digital Fault Recorders (DFR). Using this technique the response of the protection scheme can be analyzed for different fault types to ensure the proper operation of the scheme. Figure 6 shows a waveform recording of a dynamic state test.

Fig. 3 EHV protection applications demand that the protection scheme provide security to ensure system stability. Conversely, distribution protection applications demand system dependability to ensure continuity of power. Once decisions have been made on the appropriate protection for a given application, the user needs to confirm the proper operation of the protection before it is placed in service. This Testing needs to be performed at, or before, the commissioning stage. The advancements and affordability of microprocessor and digital signal processing technology now makes Testing of protection schemes by the user under power system conditions practical. Digital test equipment can be used to perform dynamic-state testing of protection scheme. Complete scheme and not the individual relay modules need to be tested using dynamic state Testing to evaluate the performance of the scheme. Modern, portable Power System Simulators are now readily available and reasonably priced, allows user to simulate power system events easily.

Fig. 5 It can be used to perform following tests on a line protection scheme. ●● Reach accuracy for all fault types in all zones of protection

Dynamic-state Testing allows fundamental frequency components to be synchronously switched to represent the power system events. The synchronous switching between the pre-fault, fault and post-fault conditions allows user to simulate a power system event easily and quickly.

●● Operate time

PC-based software controls the simulators and switches the phasors synchronously between the states to simulate power system events (Figure 4).

●● Programmable logic

●● Switch-on-to-fault protection ●● Blown fuse detection ●● Power swing blocking It is also important to note that dynamic-state testing allows the testing of various zones of distance protection scheme without the need to disable other zones, switch-on-to-fault protection, VT supervision etc. as duration of each state during simulation can be controlled. Using Dynamic State Simulation Testing, user can easily plot the dynamic characteristic of the relay. (Figure 6).

Fig. 4

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Protective Relay Vol 1

To get more power at different test values, test instrument with multiple current range should be used. If the instrument of 450 VA rating has say 3 current range of 7.5, 15 and 30 A. It will deliver ●● 300 VA at 10 A (at 15 A range) ●● 300 VA at 5 A (at 7.5 A range) ●● 60 VA at 1 A (at 7.5 A range) Test instrument with multiple current range is capable of providing more power compared to an instrument with one current range of the same power rating.

Fig. 6

Considerations for Dynamic-state Testing: The first questions to ask are:

Another important factor in determining power requirements is the test lead considerations. To reduce the power loss in the test leads, impedance of the test leads should be minimized. To minimize the impedance of the test leads: ●● Use a larger gauge test lead

●● How many test instruments are needed?

●● Keep leads as short as possible

●● Will the whole scheme be tested, or only a part of it?

●● Do not coil excess test leads

●● How many states are needed for simulation?

●● Do not use the instrument ground as the return path

●● How many connections are required?

●● Twisted pairs can be used to cancel mutual inductance

●● How many test leads will be needed? Once this is determined, the only equipment needed to begin testing is dynamic-state simulation software and high power active sources. Following example indicates the power requirement for testing simple line protection scheme at 1A, 5A and 10A fault current. Consider a typical microprocessor based line protection scheme with breaker fail and directional over current back up protection. Total impedance of the circuit for A to Ground fault loop including lead resistance for interconnection is approx. 2.37 Ohms. Following table indicates the power (VA) requirement for the current source for different values of test current.

Test Current 1A 5A 10 A

Power 2.37 VA 59.25 VA 237 VA

Power requirement of the current source increases by square of the test current. Power rating for current source is defined as the power delivered by the current source at the maximum current value of the current range. If the instrument has one current range of say 15 A and power rating of the current source is 100 VA, it will deliver 100 VA at 15 A. It will deliver

Transient Simulation Testing (Application Testing) Transient simulation Testing simultaneously applies both fundamental and non-fundamental frequency components of voltage and current that represents power system conditions. The test signals can be the ●● Actual signals received by protection scheme during power system disturbance captured by Digital Fault Recorders. ●● Calculated signals using Electro Magnetic Transient Program (EMTP or ATP). Modern digital relays are capable of recording signals used by relays during power system disturbances but it may not capture high frequency components of voltage and current due to lower sampling rates compared to digital fault recorders. Typical DFRs can record signals at 200 to 400 µSec steps and EMTP can generate signal at 50 to 100 µSec steps. The sampling rate used for EMTP or ATP simulation is important to truly simulate power system conditions with different fault inception angle. DC coupled power amplifiers are used to play transients into the relay. Transient Testing helps user ●● In evaluating relay and protection scheme performance under actual power system conditions

●● 66 VA at 10 A

●● In the analysis of questionable relay operations

●● 33 VA at 5 A

●● In testing relays and protection scheme with special characteristics.

●● 6.6 VA at 1 A

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Protective Relay Vol 1

Modern Digital Fault Recorders and numerical protections can provide fault records in COMTRADE format and can easily be played back by the modern test instruments. A typical record is as shown below in figure 7.

Fig. 8 To ensure the accuracy of the test, Global Positioning Satellite synchronization (GPS) needs to be utilized as shown in Figure 8. Power system simulator with built in GPS satellite receiver can synchronize its output accurately using time signal from the GPS satellite. Fig. 7 Sample by sample control of the voltage and current sources of the test instrument is required to faithfully reproduce the waveforms. One important point need to be considered here is to study how test instrument plays back the events. Some DFRs, records the events at different sampling rate in one recording. Hence test instrument should be able to replay different rates of the recording. If play back of the signal is to be done at rate different than originally recorded utmost care need to taken in the sampling rate conversion.

End-to-end Testing Today, many utilities perform end-to-end Testing regularly as a means to test the entire protection scheme at both line ends under power system condition. End-to-end Testing is the ultimate testing tool because this test closely simulates the actual conditions the protection will experience in service. End-to-end scheme Testing can be used to ●● Evaluate the performance of the complete protection scheme and it’s associated equipment. ●● Ensure the proper operation of the communication equipment for pilot relaying schemes. ●● Prove the proper coordination and operation between two line ends of a line protection scheme in current reversal and evolving fault conditions. End-to-end Testing can be used for commissioning tests and as a diagnostic tool. The test does require high power to check the complete scheme that may include primary and backup relaying, high fault current events, and schemes mixed with digital and Electro-mechanical relays.

The GPS system was developed and deployed by the U.S. Department of Defense in the early 1980’s as the most accurate radio timing and navigation system ever devised. Each of the 24 satellites presently deployed carries an ensemble of onboard atomic clocks, which are traceable to the United States Navel Observatory (USNO) to an accuracy better than 100 nanoseconds. The GPS based time receivers (now commercially available from a number of manufacturers) are able to transfer time referenced to Universal Coordinated Time (UTC) to better than 150 nanoseconds. Such receivers are being used at electric utilities for time tagging on SCADA, fault recorder and sequence of events recorder systems. The GPS system provides a range of output signal options, the most useful to electric utilities being the 1 pulse per second (1PPS) synchronizing pulse and the IRIG-B Standard Time Code signal. The test instrument, when equipped with the GPS time sync option, can use the 1PPS signal from the GPS receiver to phase lock the synchronizing signal. The IRIG-B signal is used by the test is linked to a local laptop PC via RS232 Cable. This time is then used by the Dynamic State Simulation or transient play back Software to synchronize the test instruments at any substation. A test instrument can be set to initiate, automatically, an end-to-end test at exactly the same time. The only thing the test engineer at each terminal need to verify is that the “GO AT’ (Start) time on each station’s PC display for the State Simulator Program or transient program shows the same time. This is the Test instrument initiation time, which in an End-to-end test must be the same at each terminal. By injecting the appropriate voltage and current phasors at each end of the line, performance of the protection scheme along with the associated equipment like communication scheme can be easily checked.

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Protective Relay Vol 1 When test instrument is equipped with GPS satellite receiver, it can use 1PPS signal from the GPS receiver to phase lock the synchronizing signal. This is very useful when testing protection schemes located on panels in different locations within the same substation. The lead burdens that would be experienced to wire the schemes together would exceed the power requirements of the test sets. Synchronization using GPS avoids this as test instruments can be placed near the relay panel for testing protection scheme without excessive lead burden. As and example breaker fail relay and line protection scheme may be located in two different panel. To check both schemes at the same time, set of test instrument can be placed near each panel and can be tested simultaneously using same start time.

CONCLUSION Steady-State Testing can only test each individual component of a system. The entire system cannot be tested as a whole to observe its behavior under power system conditions. The inability to test the complete system leaves many gaps in the test procedure. Misoperations in service are generally due to the performance of the untested parts of the system. Steady-State Testing only confirms that relay is alive and setting has not drifted. It is useful in ensuring that electromechanical components are working properly. Steady-State Testing should be automated using PC for efficient and consistent Testing. Test data should be stored and can be used to track the drifting in the test results and test scheduling. Dynamic Testing synchronously changes the fundamental frequency voltage and current phasors and closely simulates power system events. Computerized control of the instrument and PC power system model allows user to evaluate protection performance for the different power system events. Dynamic Testing of the complete protection scheme ensures the proper functioning of the scheme during power system disturbances. Complete protection scheme should checked rather than testing individual relays or modules, as complete scheme testing confirms the proper interaction between various modules of the scheme. In testing complete scheme, it is very important that test instrument is capable of supplying required power. Multiple ranges on the current source are capable of providing more power compared to only one current range. Transient Testing simulates fundamental, harmonic and all other frequency component including DC component in the voltage and current phasors. It is very useful in analyzing the questionable response of the protection scheme. Modern test instrument with DC coupled amplifier with sample by sample control allows play back of the transient event using PC based transient program. Care need to be taken in data conversion if the play back rate is not the same as recording rate. The use of satellite synchronized dynamic Testing provides the closest simulation to true power system conditions that is available with existing technology. This provides all the benefit of observing how the protection system operates and relates to all its components. Endto-end Testing dramatically increases confidence in the reliability and

proper operation of the protection under actual operating conditions. Satellite synchronized dynamic Testing now makes routine end-to-end Testing feasible and desirable. The quality of the test results, combined with the reduction in test time, allows a previously special test to become routine, thus improving the quality and reliability of the protection.

REFERENCES 1. IEEE Special Publication # 96TP115-0 Relay Performance Testing Power System Relaying Committee, Report of Working Group I 13. 2. Dynamic Relay Testing, A.T. Giuliante, Pennsylvania Electric Association Relay Committee, February 2, 1990. 3. Dynamic Relay Testing Seminar, A.T. Giuliante, ATG Exodus. 4. Protection Scheme Testing Using a Power System Model, J.A. Jodice, Doble Engineering Company and A.T. Giuliante, ATG Exodus, International Conference of Doble Clients March 25-29, 1996. 5. A New Philosophy for Protection Diagnostics, J.A. Jodice, Doble Engineering Company and A.T. Giuliante, ATG Exodus, Pennsylvania Electric Association Relay Committee, September 18, 1996. 6. Re-engineering Relay Engineering, A.T. Giuliante, ATG Exodus, Texas A&M University 50th Annual Conference for Protective Relay Engineers, April 7-9, 1997 7. End-to-End Testing for Routine Maintenance, Cliff Tienken, Central Hudson Gas & Electric Corporation, Jay Gosalia, Doble Engineering Company and A.T. Giuliante, ATG Exodus, 1997 Annual Western Protective Relay Conference, October 21-23, 1997. 8. Relay Response to Abnormal Conditions, A.T. Giuliante, ATG Exodus, IEEE Winter Power Meeting, February 5, 1998. 9. Mysterious Disturbances Resolved Using Load Flow Power System Model, Cliff Tienken Central Hudson Gas & Electric Corporation and A.T. Giuliante, ATG Exodus, Doble ProTesT User Group Meeting, February 25, 1998. Jay Gosalia is the Vice President of Global Market Solutions with Doble Engineering Company. He is responsible for the promotion of doble business worldwide. Jay has 40 years of experience in application, sales and marketing in the power industry. Jay has worked with ABB and GEC ALSTOM before joining Doble in 1996 as Protection test Instrument Product Manager. As a Product Manager, he was responsible for the development of the state of the art protection test instrument and associated software. He launched the 3 phase Power System Simulator F6150 in year 2000 and was the instant success in the market. At Doble Jay was also responsible for the product development of Circuit breaker test instrument and launched the sophisticated and comprehensive circuit breaker test instrument TDR9000 in 2001

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Protective Relay Vol 1

HOW TO IMPLEMENT SYMMETRICAL COMPONENTS INTO RELAY TESTING PowerTest 2014 Jason Buneo, Megger

ABSTRACT Many of today’s relay testing methods employ techniques available 50 years ago and have not evolved. These test methods don’t fully utilize the capabilities of either the protective relays or the available test equipment. In fact, current standard testing practices for microprocessor-based relays do not even adequately represent real system conditions. Moreover, these methods do not properly utilize the one theory that could help—namely, that of symmetrical components. This paper looks at four distinct ways of using symmetrical components to more accurately simulate real world conditions, including: ●● a current unbalance scenario in a motor protection relay, ●● the removal of zero sequence current in a transformer differential relay, ●● operating a phase time overcurrent and a neutral time overcurrent on the same trip output without isolation, ●● directional elements that utilize negative sequence impedance. For each of these scenarios listed above, antiquated methods are generally used, or the scenarios are not even tested because of the perceived difficulty of the procedure. In many cases of field-testing relay schemes, the methods employed do not take into consideration symmetrical components in the determination of fault values. Therefore, a more accurate method for evaluation and testing of protection relays is necessary. In this paper, the method is examined in detail, along with the solutions for the four scenarios, encouraging testers to utilize symmetrical components to more accurately represent the power systems that the relay is protecting. By embracing methods that utilize symmetrical components, the perceived difficulty in testing protective relays will be greatly reduced.

INTRODUCTION The transition from electromechanical protective relays to microprocessor based protective relays has allowed users to better protect power systems than what was possible in previous generations of equipment. Microprocessor based relays have a lower burden, greater flexibility for protective functions and logic, and in many cases can be accessed through remote communications. The increased flexibility of microprocessor based relays has also allowed customers to reduce their wiring costs and simplify their elementary diagrams.

However, with these great enhancements also comes some drawbacks. Many of these drawbacks are related to commissioning and periodic testing of these microprocessor based relays. Since there now many protective elements in a microprocessor based relay, isolating a specific function to verify its correct operation can become a bit of a challenge. In many protective schemes, it is common to have a single output contact on a protective relay trip based on the operation of many different protective elements. For example, in a protective relay, there might be differential, current unbalance, phase time overcurrent, and ground time overcurrent programmed to the same output contact. Many customers may now require that the relay be tested with all elements active, but that the tests are performed so that each element can be properly tested without operating the other active elements. To say the least, this can be tricky. This increasing complexity also doesn’t help that the average tester won’t look at a particular relay that often. Once or twice a year for certain relays of a certain type. It could be even longer for other relays that have continuous monitoring. If you tested a relay once, a few years ago, chances are that you are not going to remember all of the details necessary to quickly test it again. Especially, if there were some settings changes. Then all bets are off. You might as well be testing it again for the first time. All of these factors together, plus some others (like deadlines and pressure) make testing protective relays a pain. This paper won’t be addressing some of the factors like deadlines and pressure, but it will discuss how to make the fault values you apply to the relay more realistic and make the relay think it is looking at a real power system. This is good from a practical standpoint, because many modern protective algorithms in relays can tell the difference between a real fault and a contrived one from old equipment and procedures. The best way to start make fault values applied to a relay appear more realistic is to apply the method of symmetrical components.

SYMMETRICAL COMPONENTS Calculating normal and abnormal system conditions starts with an understanding of symmetrical components. Symmetrical components first came about in a paper written by Dr. C. L. Fortescue entitled, “Method of Symmetrical Coordinates Applied to the Solution of Polyphase Networks.”1 Dr. Fortescue stated that unbalanced three phase voltages or currents could be transformed

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Protective Relay Vol 1 into three sets of balanced three phase components. To do this mathematically, the method of symmetrical components utilize a variable called the “a” operator. This variable is a vector with a magnitude of 1 and an angle of 120°. In a three phase system, the “a” operator is applied to the reference voltage or current. By applying the “a” operator to the reference voltage and current phases they are each rotated counter clockwise by 120°. To get a 240° displacement, the “a” operator is squared. This is shown in Figure 1 below where the “B” and “C” phases of voltage are expressed in terms of “A” phase voltage. This same procedure would apply to current as well.

Fig. 3: Relationship between symmetrical components and phase components

Fig. 1: Application of the “a” Operator Now that each of the phases are expressed in terms of a common reference, they can be broken down further into their actual sequence components. All three phases will each contain three components called positive, negative, and zero sequence. These are shown in Figure 2.

In power systems each of these symmetrical components would be measured by the protective relay in some form or another depending on what the current system conditions are. In a normally operating, balanced system, the protective relay will measure primarily positive sequence values. The negative and zero sequence values will be minimal because there are no unbalances or ground currents. During a three phase bolted fault, only positive sequence current will be measured because all three phases are still balanced symmetrically due to fault magnitude and phase angle. During a phase to phase fault, the relay will be measuring both positive and negative sequence currents. This is because that when a phase to phase fault occurs, the negative sequence component opposes the positive sequence component. When a line to ground or double line to ground fault occurs, positive, negative, and zero sequence values will be measured.

APPLICATION EXAMPLE 1: Motor/Generator Current Unbalance Protection

Fig. 2: Positive, Negative, and Zero Sequence Components Mathematically, the sequence components can be broken down into the following equations: VA = VA1 + VA2 + VA0 VB = VB1 + VB2 + VB0 = a2∙VA1 + a∙VA2 + VA0 VC = VC1 + VC2 + VC0 = a∙VA1 + a2∙VA2 + VA0 Now that we have these equations, what do they mean? To put these equations in perspective, let’s show how the relationship between phase voltages and currents with their sequence components. Figure 3 shows how each of the phase quantities are a vectorial summation of each of their respective sequence components.

Now that symmetrical components have been discussed in theory, it is time to put that new knowledge into practice. The first application symmetrical components will be used to test a motor or generator for current unbalance protection. This protection is designed to protect a motor or generator from uneven loading between the phases. In particular, the negative sequence current is monitored to keep it below a predefined magnitude as proscribed by the settings engineer. To make the math easy, let’s say this motor’s full load amp rating in secondary current is 5 A, and that the percent unbalance pickup is 20%. In secondary amperes, the pickup current should be 1 A. The traditional way of testing this protection has been to inject a single phase current into one of the phases of the relay and increase the magnitude until the unbalance element operated. Using this method the pickup would be actually be 3 A instead of 1 A. This is because the relay is splitting the positive negative and zero sequence components evenly, and it will take three times as much current to get a proper trip.

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Protective Relay Vol 1

To get a proper 1 A trip, the symmetrical component quantities will need to be computed. Since this is an unbalance element, only positive and negative sequence components are required. The positive sequence current will be the full load secondary Amps which is 5 A. The negative sequence current is the 20% unbalance, which is 1 A. There is no mention of zero sequence current, so that will be set to 0 A. These values of symmetrical components can now be used to figure out what the phase currents should be. The phase A current can be solved as follows. The solution for leading and lagging angles will be given.

APPLICATION EXAMPLE 2: TRANSFORMER ZERO SEQUENCE CURRENT REMOVAL The next example of applying symmetrical components to protective relay testing that we will look at is verifying the removal of zero sequence current in transformer differential relays. Zero sequence current tripping is a common nuisance problem experienced by differential relays. When a sufficiently high magnitude line to ground fault occurs outside of the zone of protection of a differential relay the zero sequence current flowing through the relay may become large enough to cause a trip even though the transformer is not experiencing the fault directly. Fortunately, there have been various methods developed that can counter act this problem. Figure 4 shows a typical diagram for a two winding transformer differential protection scheme.

Continuing on, the B and C phase currents can also be solved in the following equations.

Fig. 4: Two winding transformer differential protection

The final calculated values are shown in Table 1.

Magnitude

Ia

Ib

Ic

4A

5.568 A

5.568 A

111.05°

248.95°

Angle (Lagging) 0°

Table 1: Calculated values for 20% unbalance As can be seen the magnitudes and phase angles have drifted from the nominal balanced conditions. This is exactly a 20% unbalance with a 5 A nominal current. It is quite different from the 3 A single phase injection that was calculated earlier. This method is much closer to an actual system condition than the previous single phase injection method.

2

In traditional electromechanical differential schemes, the zero sequence current could be eliminated by virtue of the current transformer (CT) connections to the relay. This was done by wiring the CT’s in the opposite configuration of the winding that they are connected to. So, for the delta high side winding, the CT’s are wired in a wye configuration. In the wye winding, the CT’s are wired in a delta configuration. This configuration will cancel out the zero sequence current in both windings. This process is referred to as external zero sequence compensation. Modern microprocessor relays no longer have to rely on specific CT configurations to eliminate the zero sequence current. They can do it internally through software. Almost all new protection and many retrofit commissioning is done with microprocessor relays. To use the internal compensation, the CTs will be wired in a wye configuration for both windings. As we saw earlier, this will give rise to zero sequence current flow in the transformer, but the relay will be able to recognize it with its internal algorithms and essentially ignore this current. Let’s take a look at exactly how this is done with a practical example. For our example, let the transformer have the following settings: Transformer MVA = 22.4

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Protective Relay Vol 1 High Side Voltage = 69 kV Low Side Voltage = 12.47 kV CT Ratio on the High Side = 30:1 CT Ratio on the Low Side = 240:1 With these settings we can figure out the high and low side secondary current with the following equations.

Now that we have the secondary currents we can look at the relationship of the two windings of the transformer. For our example we will have the following relationship shown in Figure 5.

First, calculate the values of the relay that would give you trip values based on the positive sequence current. When that value is calculated, apply the current that is slightly less than that so that the relay does not operate on a differential trip. The idea is to get the relay on the verge of tripping on a differential operation. When the relay is at this precipice, apply zero sequence current to the relay. The relay should not trip. Taking the same transformer we have been working with, let us apply some differential settings to the relay. Since many manufacturers have various methods of calculating differential operation, let’s take one of the most common methods where the operate current is the sum of the two winding currents and the restraint current is the average of the two winding currents.

Here are the differential relay settings of interest.



Slope = 25% Winding 1 Secondary Current = 6.25 A Winding 2 Secondary Current = 4.32 A

Using these settings we can solve for when the relay should be just on the threshold of operating. Note that when testing differential relays, the CT polarities will be facing opposite of each other when in service to establish a zone of protection around the transformer.

Fig. 5: Phase angle relationship between winding 1 and winding 2 2 Winding 2 is shifted 30° from Winding 1. The relay will take this phase relationship and apply its zero sequence compensation by mathematically computing its phase components against a zero sequence matrix and applying a magnitude shift factor of to the calculations. These calculations are shown in the following equations.

The value of slope applied by injecting 4.5 A of positive sequence current into winding 1and 3.97 A of positive sequence current into winding 2 is just at the precipice of operation. Since these are positive sequence values, a total of six currents will be applied to the relay. Three in winding 1 and three in winding 2. Table 2 shows the magnitude and phase angle of all of the current inputs.

As can be seen, each of the I0 terms are eliminated in each of the equations. Depending on what the phase relationship is between windings the compensation matrix will be different. If an incorrect matrix is selected, then the zero sequence currents will not be properly eliminated. Verifying the relay is removing the zero sequence components is an important, but often overlooked test when commissioning transformer differential relays. To determine if the differential relay is actually removing the zero sequence current, it is best to perform the following steps.

Table 2: Phase Quantities of Only Positive Sequence Current Values

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Protective Relay Vol 1

By applying 1 A of zero sequence current to winding 2, we can calculate the phase quantities of the combined positive and zero sequence current. Like with the motor unbalance example, the calculations will have only two sequence component terms to worry about instead of three. Only the positive sequence and zero sequence values need to be used. These values are shown in Table 3.

Going back to our original impedance example, let’s use 5 Ohms be the pickup point for the negative sequence impedance, and stipulate that if the positive sequence drops below 85% of the nominal voltage, the relay will not operate. How do we test the relay to get it pick up at 5 Ohms of negative sequence impedance? We ramp the negative sequence values while keeping the positive sequence values constant. To accomplish this we need to calculate the phase quantities based on the following symmetrical component values shown in Table 4. I1 1A

I2 6A

I0 0A

V1 69V

V2 30V

V0 0V

Table 3: Positive and Zero Sequence Values

Table 3: Phase Quantities of Positive and Zero Sequence Values The values given in Table 3should not trip the differential protection with the given settings.

APPLICATION EXAMPLE 3: Testing Directional Elements that use Negative Sequence Impedance There are many methods of determining direction for protective relays. One method for microprocessor relays is to use the various types of sequence components to determine the direction of a fault. For this example we will look at a method that uses negative sequence impedance. Most technicians who test impedance relays are accustomed to testing the positive sequence value. For this example, let’s assume that the impedance relay in question was set to 5 Ohms at a line angle of 85°. Normally, to test this setting, a technician would probably test the relay using a constant voltage method. By setting the appropriate phase angles and setting the magnitude of the voltage to 30 V, the technician would then increase the current applied to the relay until a magnitude of 6 Amps was reached. At this value the relay would trip because the value of the impedance would have reached 5 Ohms as described by Ohm’s law: V = IR The previously described method of testing impedance relays involves the positive sequence value of the impedance seen by the relay. So how does one test negative sequence impedance? The answer to that is to employ a method similar to testing the positive sequence impedance, but apply Ohm’s Law by using the negative sequence values. In many relays that employ a negative sequence impedance, the relay is also looking for positive sequence values as well. This positive sequence value is usually tied to the loss of potential function in many microprocessor relays. If the positive sequence value drops below the pickup value for the loss of potential function, the relay may not operate properly when trying to test the negative sequence impedance.

The positive sequence values represent normal operating conditions where the relay will not engage its loss of potential protection. The negative sequence values follow Ohm’s law and yield 5 Ohms to trip the directional element. The line angle was set as 85°, which would be the same as the positive sequence current angle. The negative sequence current angle would be 180 degrees from the positive sequence value. Following the calculations from example 1, we arrive at the following phase values shown in Table 4. Va Magnitude 39V 0° Angle

Vb 87.93V 102.8°

Vc 87.93V 257.2°

Ia 5A 265°

Ib 6.56A 152.6°

Ic 6.56A 17.4°

Table 4: Calculated Phase Quantities These values will operate the relay without engaging the loss of potential function.

APPLICATION EXAMPLE 4: Phase and Residual Time Overcurrent Protection on Same Contact With the previous three examples, extensive calculations were needed to calculate the positive, negative and zero sequence current values. Of course by now it is expected that the reader is an expert on symmetrical components and can now do these calculation in her or her head. In fact we will do so with the following example. Many times a person tasked with testing protective relays will be given the constraint to individually test the elements using only the trip contact that will be used during actual faults. In addition, the other elements must remain active during the testing. In a lot of cases this is not a problem because it is relatively straight forward to isolate protective elements from one another based on the design of the test. For instance, and under frequency element is easy to isolate from an over voltage element by keeping the voltage magnitude below the over voltage threshold and ramping the frequency. Other element it is not so easy. Phase time overcurrent and residual time overcurrent elements can often interfere with one another if care is not taken. Both of these elements use the same current inputs to take their measurements. This is shown in Figure 6.

Protective Relay Vol 1

Fig. 6: Current inputs for phase and residual time overcurrent 2 The phase time over current element measures the positive sequence current and the residual time over current element measures the zero sequence current. In many cases, the residual time overcurrent element is set to a pickup value lower than the phase time overcurrent element. Many testing procedures have each of these elements tested the same way, by injecting a current into a single phase of the relay and ramping the magnitude until a trip occurs. The problem with this is that if the phase element is being tested, the residual will trip first preventing the user from measuring the true phase pickup value. This can be easily solved by looking at what each of the elements is actually measuring. In the case of the phase time overcurrent, positive sequence is being measured. To ensure that the residual current does not pickup, the zero sequence current must be set to zero. This is done by applying a balanced three phase current to all three current inputs, and then ramping to the appropriate magnitude that will yield a trip. To test the residual element without affecting the phase element, the opposite can be applied. Apply only zero sequence current and make the positive sequence component zero. This is achieved by applying three equivalent currents with a phase angle displacement of zero degrees. Then ramp the current to the appropriate pickup magnitude. The residual element will trip and the phase element will not.

CONCLUSIONS A solid understanding of symmetrical components is vital to understanding and testing the various protection algorithms of modern microprocessor relays. This paper has shown only three of the many scenarios where proper application of symmetrical component theory can aid in testing protection elements. More importantly, proper application yields more realistic fault values which in turn gives a more accurate picture of protective relay operations.

REFERENCES 1. C.L. Fortescue, Method of Symmetrical Co-ordinates Applied to the Solution of Polyphase Networks, Annual Convention of the American Institute of Electrical Engineers, Atlantic City, NJ, 1918 2. J.Lewis Blackburn, Protective Relaying Principles and Applications Third Edition, CRC Press, 2006

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Jason Buneo received his B.S and M.S in Electrical Engineering from the University of Buffalo. In 2005, he joined GE Energy Services as a Field Service Engineer. He specialized in arc-flash coordination studies, protective relay testing and calibration, and low-/ medium-voltage switchgear repair. In 2008, he joined Megger as an Applications Engineer where he assisted Megger’s customer base in their relay testing needs. He became the Applications Development Manager in 2012 and now specializes in developing automated testing applications for protective relays. Jason continues to work closely with utility and industrial customers to develop new testing solutions. Jason has published several technical papers in industry journals and conferences and is active in the IEEE Power Systems Relaying Committee.

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Protective Relay Vol 1

SIMPLIFIED MOTOR RELAY TESTING PowerTest 2014 Chris Werstiuk, Manta Test Systems, Inc.

INTRODUCTION Electric motors perform most of the real work in our modern society and can be found in nearly every facility outside of the utility substation. Smaller motors in low voltage applications are expendable and typically have some kind of overload element that isn’t very sensitive, because it attempts to protect the motor from overloads and power system faults while ignoring the wide range of “normal” currents that flow into a typical motor. Protecting motors becomes more important as they increase in power and are connected to higher voltages because these motors can be vital to the manufacturing process, or are very expensive to repair or replace. We’ll start by reviewing the motor’s basic operating conditions to show why a simple overload element cannot adequately protect a motor.

Manufacturers usually provide two damage curves for each motor which specify the thermal limits for the rotor and stator. The Cold Thermal Limit Curve applies if the relay has not been running to capacity and was not hot before an overload occurred. The Hot Thermal Limit Curve applies if the motor has been running at or near capacity before the overload occurred. A protection engineer could apply a simple Motor Protection Curve below the Thermal Limit Curve as shown in Fig. 1, to protect the motor from damage caused by overheating. Time Coordination Curve 1000.0

Motor Damage Curves

Electric motors are a pretty efficient way to transmit power from one location to another, but they are not perfect machines. A typical motor runs at about 85% efficiency, which means that 15% of that power stays in the motor and can be measured as heat. A running motor is always turning, and that friction also creates heat. No motor or electrical system is perfect, and any unbalance will also create heat. The ambient temperature also affects the motor temperature. You can see by now that motors can also be used as heaters, and that excessive heat negatively affects the insulation quality of the coils wrapped around the stator. In fact, if the motor exceeds its rated temperature by 10°C, it can halve the motor’s expected lifespan. A perfect motor relay should be able to monitor the motor’s temperature and trip if the temperature exceeds the setpoint.

Time to trip in Sseconds

Motors are designed to convert the electricity supplied by an electrical power system into mechanical power. The motor rotates a shaft that can turn fans, create air or fluid pressure, or move material from one location to another. That shaft is connected to a rotor which can have a small, residual magnetic field found in induction motors, or they can be connected to an external electrical field generator as found in synchronous motors. Regardless of the motor type, the rotor rotates inside a stator that is comprised by at least one stationary coil of wire wrapped around a magnetic material that is fixed in place. When the power system is connected to the stator, a magnetic field is created. The magnetic field of the stator interacts with the rotor’s magnetic field, and the rotor turns.

100.0

10.0

Hot Thermal Damage Curve Motor Protection Curve Cold Thermal Limit Curve

1.0

0.1

1

10

100

Multiples of Full Load Amps

Fig. 1: Motor Thermal Limits and Protection

Motor Starting Curves This paper wouldn’t exist if motor protection was a simple overload curve, so there must be more to it. The rotor turns because the stator and rotor’s magnetic fields lock together (with a little slip in induction motors), and the magnetic field created in the stator pushes the rotor around which, in turn, rotates the shaft. Motors often drive heavy loads which require the magnetic lock between the rotor and stator to be greater than the energy required to move that load. The rotor starts with a small, residual magnetism that does not have enough inherent energy to move the smallest of loads; so the energy required to move a load must come from somewhere else.

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Protective Relay Vol 1 Squirrel-cage and other motor rotor styles are designed to build a magnetic field using energy from the electrical system. When the motor is initially energized, there is a large inrush current that the motor uses to build the electrical field necessary to turn the load. Remember that Newton’s laws of motion state that more energy is required to move an object at rest than is required to keep an object moving, so a larger electrical field will be required to get the load moving. This starting current can be up to six times larger than the normal operating current, and the relay may trip under the motor’s worst case starting condition.

are installation and/or settings errors that cannot be found without reviewing the entire application. Most relay problems are discovered when you look at the entire application but unfortunately, most relay testers focus exclusively on the relay itself and getting values on their test sheets without looking at the equipment around the relay.

The inrush current is directly proportional to the system voltage, so manufacturers usually supply a minimum of two starting curves at different voltages. If we had a large motor and a weak system, the motor’s large starting current could depress the system voltage to 80% when starting, and our simple overload relay would not trip. Counting on a heavy load depressing the voltage isn’t healthy for the rest of the electrical system and isn’t good engineering practice, so engineers who wish to limit the starting current can use reduced-voltage motor starters that use autotransformers to apply a fraction of the normal operating voltage to the motor without affecting the rest of the system, wait for the motor to reach the maximum speed it can at that voltage, and then switch to nominal voltage. The design engineer could also specify a variable frequency drive (VFD) to control the voltage and frequency during starting to keep the starting current as low as 1.5x the starting current.

Motors are typically connected to the electrical system via motor starters or circuit breakers. The motor relay outputs must be configured for the correct scheme as they have completely different operating philosophies.

Threading the needle between the manufacturer Thermal Limit curves and the Starting curves will probably take something more complicated than a simple overload relay. Multifunction motor protection relays were created to protect the motor and associated equipment as per the manufacturer’s specified limits, and many more operating conditions.

GETTING READY TO TEST What most people consider to be relay testing is actually quite easy. Anyone who can operate a computer and understands pre-high school math (basic algebra and Pythagoras’ triangle theories) could create and run a relay test plan. Many test-set manufacturers and software vendors use this secret to create tests that ask the relay (a computer) what it is programmed to do, apply those settings to a series of pre-canned test plans (a simple spreadsheet or database), and then send those test plans to a test-set (another computer) to run. The user is often only on-site to connect the interfaces between computers and press Start. Because the test plan is regurgitating the relay settings back into the relay as voltage and current, almost none of the problems with modern relays will ever be discovered with this philosophy of testing. Most relay problems in the digital age are either simple-to-detect problems like power supply or analog-to-digital converter failures that do not require any special equipment to discover; or they

This section will review what to do before you start testing to make sure that the relay settings are appropriate for the application.

Digital Outputs

●● Circuit Breakers The circuit breaker scheme uses the same principles as a normal protective relay in the trip circuit. The circuit breaker is closed via a close-coil that energizes the mechanical close mechanism. The circuit breaker remains closed and its trip mechanism is set with a hair trigger. When the trip coil is energized, the trip mechanism is released and the breaker opens. The motor relay trip contact should be a normally-open contact connected in series with a trip-coil as shown in Fig. 2. If the relay detects a fault and sends a trip signal, the trip contact will close and operate the trip-coil to open the circuit breaker. Motor relays often have a “fail-safe” feature that will close the contacts and initiate a circuit breaker trip if the relay detects a problem or powers down. Be sure that there is a breaker status contact in series with the trip-coil, as shown by “52a” in fig.2 that will break the trip circuit when the circuit breaker is open to prevent the trip-coil from burning up during a fail-safe trip. Motor relays often have another contact that prevents the circuit breaker from closing if the relay thinks that the motor will be unduly stressed or damaged without waiting for a manual reset from an operator, or a preset amount of time between starts. A normally-open contact is placed in series with the close coil as shown in Fig. 2 to prevent the circuit breaker from closing unless the relay thinks that it is safe. The fail-safe version of this contact would be to stay open if there was a problem with the relay to prevent the circuit breaker from closing. Some design engineers place this contact in parallel with the trip contact with the same fail-safe conditions as the trip contact, but this scenario is not desirable because the circuit breaker will close and trip free. Every motor start creates stress and, like humans, the motor will last longer with the least amount of stress and the block-close application is preferable.

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Protective Relay Vol 1

Fig. 2: DC Circuit Breaker Schematic ●● Motor Starters A motor starter has the opposite characteristic when compared to a circuit breaker. The motor is energized by a high-voltage contactor that is held closed as long as the close-coil is energized. If the close-coil de-energizes, the contactor automatically opens via its mechanism. There is no trip-coil in a motor starter scheme. Most medium-voltage motors are energized with a motor starter. In this application, the trip contact is a normally-closed contact in series with the close-coil. The motor can only be started if the relay trip contact is closed along with any other permissive contact. If all of the permissives are normal, the motor is started when a “Close” contact energizes the close-coil, and a seal-in contact keeps the contactor energized. If the relay detects a problem and needs to de-energize, or stop the motor; the trip contact opens, the close-coil de-energizes, and the contactor opens because it is no longer being held closed by the close-coil. The trip contact should remain open (fail-safe = open) if the relay detects a malfunction or is de-energized. The relay block-start contact is also a normally-closed contact in series with the close-coil and should remain open when it fails-safe.

Fig. 3: AC Motor Starter Schematic It is important to ensure that the correct scheme is being used and that the fail-safe settings are correct. Fail-safe explanations in the relay instruction bulletins are often confusing and you should not trust your understanding of how you think it should work. Measure the contact state in normal (relay powered up), tripped (after a time test), and relay failed (relay powered down) conditions and compare the results to the application.

Digital Inputs Digital inputs are not typically used during normal motor operation, but I found an interesting passage in one of the relay manufacturer’s bulletins that suggest that at least one of them should be. Here are the most commonly used and/or necessary inputs: ●● Remote Reset/Emergency Reset/Reset/External Reset Not to be confused with Emergency Restart, this input could be connected to a button on the control panel or to a SCADA system that performs the same function as pressing reset on the relay’s front panel. This is often a useful input for relay testers when relays are set to latch after every trip, which means you otherwise have to get out of your chair and press Reset on the relay after every test. You could connect a switch or test-set output to this relay input to manually, or automatically, reset the relay after each test. ●● Emergency Restart/EMSTR/Restart This input makes motor relay testing bearable because it typically resets all of the motor relay’s saved data. Many of your tests will lock the relay in trip mode for minutes or hours until the relay thinks it is safe for the motor to be started again. This input bypasses that protection and allows you to keep testing. NEVER tell an operator about this input, and it should never be connected to a permanent button, anywhere.

Protective Relay Vol 1 ●● Starter Status/52b/Motor Offline Most relays measure the motor current to determine if the relay is starting, running, or de-energized. This input is used for actual breaker position and one manufacturer recommends using it as per the following passage, “This input is necessary for all motors.” I have never observed it in-use, so nobody else appears to be reading the manuals either.

25 Always make sure that unshielded cables are installed as per the following figure, or else the CT may not detect ground faults correctly.

Instrument Transformers Most relay settings are defined in secondary values and the CT/ PT ratios are only used for metering applications. In those cases, incorrect CT or PT ratios will not affect relay operation assuming the design engineer used the correct ratios when they created their protection settings. Most motor relay settings are based on primary ratings to make it easier for the design engineer to apply their settings using the motor nameplate data. This means that the CT and PT ratios must be perfect, or else the relay will not protect the motor correctly. ●● Phase CT Ratios You should compare the Current Transformer (CT) ratio from the single-line drawings, three-line drawings, and relay setting to ensure that they all match. You have a problem if they don’t match. Here are a couple of possibilities not including simple human error. ○○ The Single-Line and Three-Line Drawings Do Not Match

Fig. 4: Ground Fault CT Installation with Unshielded Cable Always make sure that shielded cables are installed as per the following figure, or else the CT may not detect ground faults correctly.

○○ Some manufacturers and utilities will show the maximum possible ratio on the single-line drawing and the actual ratio on the three-line drawing. Make sure you know what is expected and that the drawings meet that expectation. ○○ The Drawings and Settings Do Not Match ○○ Some relay manufacturers specify the CT ratio based on the nominal secondary current (xxx:5) like drawings typically show, but other manufacturers will show the CT ratio as the actual ratio. (xxx:1) Make sure you understand what is expected and that they match. ●● Ground CT Ratios Motor relays typically have 3 types of ground CTs. ○○ Standard CTs The star-point of a Wye connected motor is connected to ground through a standard bar or donut CT. Treat this CT configuration as you normally would. ○○ Zero Sequence CTs This is the preferred method for ground fault detection where the 3 conductors feeding the motor are threaded through a donut CT that will measure the zero-sequence current flowing into the motor. Zero-sequence current is a complicated way of saying one-third ground current. There are some pitfalls with this CT configuration to be aware of depending on the type of cables used to supply the motor.

Fig. 5: Ground Fault CT Installation with Shielded Cable Zero-sequence CTs can have a standard CT ratio (usually 50:5) and you would treat that configuration as a normal CT after making sure it is connected to the correct terminals. Zero-sequence CT’s can also have a seemingly strange CT ratio like 50:025. Be sure you are absolutely sure what CT is being

26 used, and that they are connected to the correct terminals on the relay. Never try to simulate the secondary current with this configuration. You must test these applications via primary injection by applying current through the CT.

Protective Relay Vol 1 ratings are. You should go to the motor and take a picture of the nameplate to compare it to the relay settings, or write down this key information as shown on the following figure:

PT Ratios Potential Transformers (PTs) can be used to protect the motor from abnormal system conditions such as under/over voltage, frequency, and VAR flow. There are three types of PT connections: ●● Single Phase PTs This method has a single PT that can be connected between a phase and ground (P-N), or between two phases (P-P). It is important to know which connection is used because there is usually a √3 difference between the two methods. P-N connections usually have a nominal voltage around 69V, and P-P connections usually have a nominal voltage around 115V. If the PT connection is set or connected incorrectly, the protective functions will work perfectly when you test them as per the settings, and then never operate when the in-service voltages are used. ●● Wye Connected PTs This method connects three PT secondaries and ground (P-N) to the relay to create a 4-wire voltage system. These connections usually have a nominal voltage around 69V, but some rare systems have a nominal voltage around 115V. If the PT connection is set or connected incorrectly, the protective functions will work perfectly when you test them as per the settings, and then never operate when the in-service voltages are used. ●● Delta Connected PTs This method uses two PTs to create 3-phase voltages and is the most commonly applied voltage connection because it provides accurate 3-phase voltage as long as the secondary burdens are balanced for one-third the cost of a Wye connected system. These connections usually have a nominal voltage around 120V, but some rare systems have a nominal voltage around 208V. If the PT connection is set or connected incorrectly, the protective functions will work perfectly when you test them as per the settings, and then never operate when the in-service voltages are used. Almost every relay requires a jumper between the B-phase voltage terminal and the voltage neutral terminal. Be sure that this jumper is in place before you start testing or the voltage elements may never work.

Fig. 6: Motor Nameplate ●● Nominal Voltage Motors may be connected to a 4.16kV electrical system, but the actual voltage at the motor terminals is likely lower due to the voltage drop across the motor conductors. Therefore, the nameplate voltage is often 5% lower than the system voltage. Make sure the nominal voltage on the nameplate matches the settings. The nominal voltage is often listed with two voltages for Delta or Wye stator connections such as 2300/4000 Volts. ●● Nominal Current The nominal current is the most important setting. There are usually two current settings such as 173/100 in Figure 8. Use the current setting appropriate to the voltage connections. For example, if our motor was connected with the 4160V connection (xxxx/4000), the matching current would be 100A. (xxx/100) That current value should match the relay’s Full Load Amps setting. ●● H.P. (Horse Power) The horse power information can be used if the nameplate does not list the nominal current. It is important to remember that Horse Power is a measure of work or watts, and you must also know the efficiency or power factor of the motor to get an accurate current value. If the nameplate does not list either value, the 30° phase angle or 0.867 power factor is a good rule of thumb to use. The following calculations can be used to calculate current from Horse Power:

Motor Nameplate The design engineer has probably never seen the motor they designed the relay settings to protect, and is often using on very old drawing revisions. The relay tester is the last line of defense to make sure the relay is set to protect the motor, and reading the nameplate is the only way to know for sure what the motor’s

Fig. 7: Convert HP to Amps

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Protective Relay Vol 1 ●● Service Factor It is possible to buy a motor that is more robust than a standard motor in order to increase the motor’s service life. A normal motor has a service factor of 1.00 and any overload for any amount of time will decrease the motor’s lifespan. A motor with a service factor of 1.1 can be overloaded up to 110% of its rating without damage. Service factor is an important setting to confirm and ensure that the motor is adequately protected and the nameplate service factor should match the settings.

CONNECTING YOUR TEST-SET The best way to connect your test-set to the relay is the same for any relay application; follow your three-line drawings. You won’t find any mistakes following the relay schematic, and your goal should be to find the wiring mistakes during relay testing and not during start-up when the stakes are much higher.

Fig. 8: Ground Fault CT Test Connections

Current Transformer Connections (Normal CTs) Follow the A-Phase flow of current from the circuit breaker to the motor until you reach the A-Phase CT. If the current flows into the polarity mark, follow the wire connected to the CT secondary polarity mark until you reach the test switch or relay. If the current flows into the non-polarity mark, follow the wire connected to the CT secondary non-polarity mark until you reach the test switch or relay. Open and isolate the test switch and connect the 1st current channel to the point closest to the relay, and label that channel A-Phase Current. If you not have test switches, remove the wire from the relay and document its location on the test sheet. Connect the neutral of the A-Phase Current test-set channel (do not remove the wire, if possible) to the other side of the relay or test switch. Repeat for B and C-Phases.

Current Transformer Connections (50:0.025 CTs) Connect a wire to a current channel output designated as ground. Make sure that the motor cell is completely de-energized and wear the appropriate personal protective equipment (PPE) and string that wire through the ground fault CT. If the expected test current is higher than your test-set can produce, loop the wire as many times as necessary to achieve the required current. (Relay measured current = test-set current x number of loops)

Fig. 9: Ground Fault CT Test Connections for More Test Current

Voltage Transformer Connections Follow the A-Phase bus from the circuit breaker to the PT(s) until you reach the A-Phase PT connection. Follow the connection through the PT secondary until you reach the test switch or relay. Open and isolate the test switch and connect the 1st voltage channel to the point closest to the relay, and label that channel A-Phase Voltage. If you not have test switches, remove the wire from the relay and document its location on the test sheet. Repeat for B and C-Phases. ●● Wye Connected PTs Connect the neutral(s) from all test-set voltage channels to the neutral terminal(s) of the relay. ●● Delta Connected PTs Connect the neutral(s) of the test-set voltage channels together. Do NOT connect the relay-neutral to the test-set. Be sure that there is a jumper between B-Phase and neutral on the relay. ●● Single-Phase Connected PTs If the PT is connected between a phase and neutral, connect the test-set voltage neutral to the relay neutral. If the PT is connected phase to phase, connect the two voltage channel neutrals together. Do NOT connect the relay-neutral to the test-set.

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The following figure shows the AC Connections typical for a motor relay:

Most motor control schemes are AC instead of DC, and you usually have to isolate the contacts from the AC wiring to prevent interference with your test-set input monitoring circuits. This can be very dangerous if you do not return the wiring back to the correct terminals. Make sure you plan your wiring changes to remove the least number of wires, and document every change so you can return the wiring to normal. A clever relay tester might think, “I don’t need to move any wires, I’ll just use the other side of the Form C contact.” This is a possible solution, but ONLY if you check the in-service relay contact during your testing to ensure it is operating correctly. One of the most common problems with digital relays occurs if the output relay contact is fused closed or never closes. I prefer to all of my connections at one time so that all in-use contacts are available without re-arranging my test leads between tests.

RELAY INPUTS We discussed the relay inputs earlier in this paper and it is much more convenient to have the most commonly used inputs available at your test station: ●● Remote Reset/Emergency Reset/Reset/External Reset – If you notice that the relay elements are set to latch, you must press the reset button between each test. This can be done via the front panel, software, or an external contact connected to this input. Choose what is more convenient for you.

Fig. 10: Test-Set to Relay AC Connections

RELAY OUTPUTS TO TEST-SET INPUTS If the control circuit is DC or has test switches (unlikely), you can make any of the following connections to connect your test-set inputs to the relay’s output contacts that are in-use.

●● Emergency Restart/EMSTR/Restart – You will need to use this input at least once unless you want to wait hours between some tests. This input will reset many of the protection functions to allow you to keep testing, or get accurate timing results. ●● Starter Status/52b/Motor Offline – This input is seldom used. If it is being used, you should connect it to a test-set output programmed to simulate a closed breaker whenever generating voltages and/or currents, and an open breaker when not generating.

RTD’S Resistance Temperature Detectors (RTDs) are strategically placed in and around the motor to monitor the motor’s temperature. RTD’s can be constructed with different materials, but most modern RTD’s are 100Ω Platinum which means that the resistance across the RTD is 100Ω when the material is 0°F. There are three wires connected to an RTD with the RTD material between two leads and an extra lead that allows the relay to eliminate the lead resistance from the resistance measurement to eliminate error caused by long runs.

Fig. 11: DC Test-Set Input to Relay Output Connections

A typical motor has an RTD mounted at each end of the stator, an RTD mounted near the two end bearings, and maybe one for the ambient temperature. You can purchase an RTD simulator to test the RTD protection, but most RTD protection uses more than one

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Protective Relay Vol 1 signal to prevent nuisance trips caused by an RTD failure. This is called voting in the SR469 relay and all of the RTDs that “vote” together must be above the temperature setpoint for the relay to operate, so you must purchase at least two to test most relays. It is more economical to purchase some precision potentiometers with a display like the Bourns Precision Potentiometer shown below.

If you are bench testing a relay or are testing a relay before the motor is installed, you will likely have a hard time testing any Alarm functions because the RTD Open or Shorted Alarm has probably energized the Alarm relay. There are three solutions to correct this problem: ●● Connect Potentiometers or Resistors in Every RTD circuit Review the connection diagram (Fig. 13) and connect all of your test potentiometers or resistors in every slot that a RTD is used.

Be sure that the potentiometer has a range from 100-200Ω if you will only be testing 100Ω Platinum RTDs, or 0-400Ω for all possible combinations of RTDs as shown in the following chart of RTD resistance characteristics. RTD TEMPERATURE vs. RESISTENCE

Fig. 13: Potentiometer and Resistor Test Connections ●● Disable the RTD Alarms This is the worst option, but if you do not have the resistors (and you should always carry at least 10), then it is the only way you can test the alarm functions. Make sure that the RTD tests are the last tests you perform if you choose this option.

GENERAL MOTOR ELEMENT TESTING PRINCIPLES You can start performing what most people consider to be relay testing once you are confident that the basic relay connections, settings, and functionality is correct as described in the previous sections. You could reverse engineer the element descriptions, logic diagrams, and settings to create a test that will never fail, and never find problems; or you can simulate the fault the element is designed to operate for, and make sure that the settings are appropriate for the application to give yourself the possibility to find problems. Unfortunately, most setting problems prevent the relay from operating when it should, and this will be the only opportunity to find them until the relay mis-operates in the future and causes significantly more damage or headaches than a properly configured relay would have.

Full Load Amps Test Calculations Fig. 12: RTD Temperature vs Resistance Chart If you are testing a motor relay that is in service, chances are that the RTDs are in service and functioning. This is a perfect time to review the RTD temperatures from the Actual Values or Metering screen. All sets of RTDs (Stator 1, Stator 2, Stator 3, Bearing 1, and Bearing 2) should have the same temperature and should be relatively close to each other.

Most motor elements are not set at a defined current like other relays and use a multiple of the Full Load Amps (FLA), which is usually defined in primary amps. We need to find out what the FLA is in secondary current because that is the current we will be referring to repeatedly in our test plan. Look through your relay settings and retrieve the following information that you should have already verified with the motor nameplate and drawings:

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●● CT Primary = 250A ●● CT Ratio = 250:5 or 50:1 ●● Full Load Amps (FLA) = 220A ●● Mechanical Jam Pickup = 2 x FLA Use the following calculation to determine the FLA in secondary amps. After you have the FLA in secondary amps, write it down in a prominent spot and/or save it in your calculator’s memory. We’re going to be using it a lot.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00°

Fig. 15: RTD Connections for Bench Testing

Evaluating results Part of relay testing is determining whether you have obtained the correct results or not. Review the specification section of the relay bulletin to determine the actual specifications for the relay. Here are some relevant specifications from a GE Multilin SR469 instruction manual. PHASE CURRENT INPUTS Accuracy at <2 x CT: ± 0.5% of 2 x CT Accuracy at >2 x CT: ± 1.0% of 2 x CT OVERLOAD/STALL PROTECTION/ THERMAL MODEL

Fig. 14: FLA Calculation

Starting Test State Most motor relay elements are designed to protect the motor from three-phase problems and you should know how to configure your test test-set to create three-phase simulations. You can lock the channels together 120° apart with identical magnitudes between phases, or select some kind of 3P mode. The biggest hurdle with motor testing is a simple one to overcome. The relay expects the motor to have two main conditions, starting and running, and many elements are blocked in the starting condition. Therefore, nearly every test should have at least two states and many elements will require three fault states. Learn how to manage the number of states on your test-set and how to automatically transition between states with a timer. Almost all of your tests will require a starting state before we can test the element so we will create a generic Prefault state that will run before most of the element tests. You could realistically simulate a motor start by applying a three-phase current set up to 6x the full load amps with a slightly depressed three-phase voltage, but that will affect some of your timing test results and create unnecessary stress on you test-set, connections, and relay. We can create a Prefault test condition where the current is greater than the Undercurrent setting and less than the motor FLA with nominal Voltage to run for four seconds before almost every test.

Pickup Accuracy: as per Phase Current Inputs Timing Accuracy: ±100ms or ± 2 % of total time OUTPUT RELAYS Operate Time: 10ms

Your test-set isn’t perfect either; here are the specifications for an older vintage test-set. AC Amplitude Accuracy Typically 0.2% of reading Multi-Mode Digital Timer Accuracy: ± 0.0005% of reading, ± one least significant digit, ± 50 microseconds Resolution: 10 microSeconds. (1 least significant digit)

●● Pickup Tests If we were performing a pickup test, the maximum allowable range for test results on a SR469 relay using the specified test-set would be:

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Protective Relay Vol 1 If the expected result was 5A, the maximum allowable range in amps would be:

We can determine which of the Relay Errors to calculate as follows: Accuracy in Time = 2% * Total Time 100ms = 2% * Total Time Total Time =

100ms 2%

Total Time =

100ms 0.02

Total Time = 5s

If the expected result was 5A, the maximum allowable range in percent would be:

The expected time for our example is 84.83s which is greater than 5s, so we’ll use 2% of total time. The following figure shows what the new formula looks like:

If the expected result was 84.83s, the maximum allowable range in percent would be:

If our test result was 5.05A and we knew the Maximum Pickup error in amps, we could already tell that the test passed because the result is less than 5.06A. If we wanted to know what the test result was in percent, we could use the following formula: If the expected result was 84.83s, the maximum allowable range in seconds would be:

Fig. 16: Calculating Percent Error ●● Timing Tests If we were performing a timing test, the maximum allowable range for test results on a SR469 relay using the specified test-set would be:

That formula was very long and we need to make some choices to simplify it.

If our test result was 86.23s and we knew the Maximum Pickup Error in seconds, we could already tell that the test passed because the result is less than 86.53s. If we wanted to know what the test result was in percent, we could use the following formula:

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If the expected value was less than 5s, we would use the 100ms per of the equation to obtain a maximum tolerance as per the following calculation:

ACCEPTANCE TESTING Acceptance testing proves that there are no physical defects inside the relay. If you are not using the in-service relay settings or are changing settings during your testing, you are really just performing a complicated acceptance test that only proves that the relay manufacturer supplied a relay in working order; nothing more. There are a couple of steps that must be performed during a successful acceptance test as described in the following sections.

Fig.17: Different Test-Set and Relay Phase Angle References Current ●● Current Calculate a three-phase current greater than the Undercurrent setting and less than the calculated FLA. 1.0A is usually a good number to start with. Calculate the expected relay meter reading. For example, if you apply 1.0A to a relay set with a 250:5 CT Ratio, the relay should report 50A.

Digital Outputs The goal with this test is to ensure that all outputs open and close correctly. Motor relays require an extra step to ensure that the failsafe functionality is also set correctly. With the relay powered down, use your meter or test-set inputs to record each contact state. Does it match the correct scheme as described in "Digital Outputs” earlier in this paper? ●● Power the relay up and record each contact state. Did they change or not change as they were supposed to? ●● Make each contact close and make sure that both sides of the contact change state.

●●Three-Phase Voltages Calculate the 3-Phase balanced voltage to apply using the following formulas.

●● Record the results on your test sheet.

Digital Inputs Use the relay’s front panel or software to determine the in-service state of all inputs. Open or close the end-device for any input connected to an external device. Did the relay indication change state for each input? ●● Use a jumper to energize each device that is not connected to an external device. Did the relay indication change state for each input? ●● Record your results on a test sheet.

Analog to Digital Converters ●● Phase Angles Understanding how your relay and test-set display phase angles is a very important step whenever you inject voltages and/or current into a relay. Many test-sets can alter their phase angle readings to match the user’s preference, but relays are typically fixed to a specific standard. The following figure displays some possible phase angle references and the relays they are typically used in. We will be using the ±180° standard whenever angles are referenced to hopefully reduce confusion. Always look at the phasor diagrams before you start and whenever you are in doubt.

Apply the three-phase current and/or voltages as shown below and review the relay metering. Do the metered values display the correct magnitude and phase angle? There should be the maximum positive watts and next to zero VARs. Prefault Magnitude Angle A-Phase Current 0.00° B-Phase Current 1.0A -120.00° C-Phase Current 120.00° A-Phase Voltage 0.00° B-Phase Voltage 69.28V -120.00° C-Phase Voltage 120.00° Time in State 4.00 seconds

Relay Metering (IA Reference) IA = 50A@0° IB = 50A@-120° IC = 50A@120° VAB=4200V@30° VBC=4200V@-90° VCA=4200V@150° 3P WATTS = 363.72kW 3P VARS = 0.06kVAR 3P VA = 363.72kVA

Relay Metering (VA Reference) IA = 50A@-30° IB = 50A@-150° IC = 50A@90° VAB=4200V@0° VBC=4200V@-120° VCA=4200V@120° 3P WATTS = 363.72kW 3P VARS = 0.06kVAR 3P VA = 363.72kVA

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Protective Relay Vol 1 None of the tests in this Acceptance Testing section have to be performed as separate tests because they can be included in other tests. For example, a timing test will prove that the contact operates correctly.

STARTS PER HOUR/TIME BETWEEN STARTS/ JOGGING BLOCK/RESTART BLOCK TESTS The elements in this section are designed to protect the motor from damage caused by starting the motor while it is still hot or spinning, and each element will monitor when the motor starts and stops. The metering test from the previous section should count as one start assuming that you started testing at least one hour after the motor was de-energized. Review the relay settings for any block start functions such as the ones described in the header. Our example relay has the following settings. Jogging Block Jogging Block = On/Yes Maximum Starts/Hour Permissible = 2 Time Between Starts = 20 min

Restart Block Restart Block = On/Yes Restart Block Time = 60 s

Restart Block If the Restart Block setting is enabled, as it is in our example relay, the trip contact and/or the block start contact should be energized until the Restart Block Time expires to prevent an operator from restarting the motor until it is safe to do so. These contacts should be connected to your test set and you could set up a timer to monitor the exact time, but a rough estimate is usually good enough for all but the most strict relay testers. Almost all GE Multilin relays will display this information on the front panel which makes it easy to troubleshoot. Some SEL relays require the design engineer to program these messages which can be confusing when trying to figure out why a motor cannot start.

Time Between Starts is Enabled and Restart Block is Disabled If there is a Time between Starts setting enabled, as it is in our example, and the Restart block is not enabled; the trip contact and/ or the block start contact should be energized until the Time between Starts time expires to allow the motor to cool before a start is attempted. Most relay testers will locate the message with the expected delay rather than wait for the timer to expire because you could spend hours just testing this section depending on the settings.

Starts per Hour If there is a Starts per Hour setting enabled, as there is in our example, you should only be able to start the motor that number of times in an hour to prevent the motor from being damaged by the thermal stress caused during a motor start. Wait for the Time between Starts timer to expire and the relay should return to a normal condition. Re-energize your previous meter test (that constitutes a motor start) and stop the meter test after the relay indicates that the motor is running. Notice that the relay will go through its regular start and run indication and the block start contact returns the normal state when you inject the test values. This means we can ignore these messages as we perform the rest of our testing. If the Starts per Hour setting is two, as it is in our example, the trip contact and/or the block start contact should be energized and there should be a message indicating that you have exceeded the maximum number of starts in an hour. If your setting is greater than two, repeat the meter tests until you get the appropriate response from the relay. If the trip contact is energized during any of these tests, you should document it on the drawings and/or around the relay with a message like “This relay’s trip contacts operate every time the relay is de-energized, for any reason, and no targets will be present for this normal condition. Relay trips will always be indicated by targets on the relay explaining the cause of a trip.” Many motor relay “trouble” calls have been caused by an event recorder recording a relay trip during a normal shutdown.

THERMAL OVERLOAD TRIP TESTS The thermal overload trip element is the primary reason for motor protection, and is the most complicated element in the relay because it has many different input signals. A cursory glance at the instruction manual will usually show you a curve, a formula, and/ or a table; and you may believe that this is a simple overcurrent relay. The Thermal Overload element can be tested like an inverse overcurrent element, but only if the conditions are right.

Time Between Starts and Restart Block is Enabled

The Thermal Overload element does not trip simply because the measured current exceeds a setpoint for a certain amount of time like an inverse overcurrent element does. The Thermal Overload element trips when the relay believes that the thermal capacity of the motor has been exceeded, and current is just one input into the thermal capacity calculations. The relay creates a thermal model of the motor based on the settings you provide, and you can imagine the thermal model as a bucket with a hole in the bottom.

If there is a Time between Starts setting enabled, as it is in our example, and the Restart block is enabled; the trip contact and/or the block start contact should be energized until the Time between Starts time expires. The message should change from Restart Block to Time between Starts when the Restart Block timer expires, assuming that the Restart Block timer is shorter. Most relay testers will locate the message with the expected delay rather than wait for the timer to expire because you could spend hours just testing this section depending on the settings.

The thermal capacity bucket fills at different rates depending on the measured temperature from RTDs, or unbalanced currents drawn by the motor, or the amount of motor load based on the motor current. The thermal capacity empties based on cooling factors determined by the relay’s thermal capacity algorithm. If you do not control all of these factors, the thermal overload element will trip faster than expected. For example, if you try to test a motor relay immediately after it has been shut down, the motor thermal capacity bucket will already be partially full, and your calculated

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time delay will not match the measured time. The thermal capacity bucket fills as soon as any current is injected into the relay, so a simple meter test can affect the measured overload timing test. A pickup test requires a higher current that fills the bucket more quickly, and will almost certainly cause the timing test to fail. Follow this procedure to successfully perform a Thermal Overload Timing test:

Determine the Maximum Test Current A normal overcurrent test is performed at some multiple of the pickup, and the relay would operate within a few seconds. Motor overload timing tests can take tens of minutes, so it is important to perform the test correctly the first time. We first need the FLA for the relay that we calculated in the previous section. The motor in our example has a secondary FLA of 4.4A. Now you must look through all relay settings that are based on the motor phase currents or load. The two most common trip elements to look for are usually called some version of Mechanical Jam and Short Circuit. The relay in our example has the following settings: Mechanical Jam Mechanical Jam Trip = Unlatched Mechanical Jam Trip Relays = Trip Mechanical Jam Pickup = 2.00 xFLA Mechanical Jam Delay = 1 s

Short Circuit Short Circuit Trip = Unlatched Short Circuit Trip Relays = Trip Short Circuit Trip Pickup = 10.0 CT Intentional Short Circuit Trip Delay = 0 ms

The Short Circuit trip is set at 10.0 CT. Notice that 10.0 isn’t a multiple of FLA and it is not specified in Amps. Many GE Multilin relays define pickup as a multiple as the nominal CT secondary current, which means that this setting would typically be multiplied by 5.0A in North America or 1.0A in many places outside North America. Be sure that you know what multiple to use when making the following calculation to determine the minimum amount of current that will cause the Short Circuit Trip element to operate.

delays and comparing, so we’ll keep the current less than 8.8A for our test. ●● Choose the Test Current The actual current you apply will depend on how you will calculate the expected time delay. The Thermal Overload settings for our example relay follow: THERMAL MODEL Curve Style = Standard Overload Pickup Level = 1.15 FLA Unbalance k Factor = 8 Cool Time Constant Running = 15 min Cool Time Constant Stopped = 30 min Hot/Cold Safe Stall Ratio = 0.80 RTD Biasing = Off/No Thermal Capacity Alarm = Unlatched Thermal Capacity Alarm Relays = Alarm Thermal Capacity Alarm Level = 90 % used Thermal Capacity Alarm Events = Off/No Overload Trip Relays = Trip & Aux.1 Standard Overload Curve Number = 2

The settings we will use for this test are: THERMAL MODEL Curve Style = Standard Overload Pickup Level = 1.15 FLA Overload Trip Relays = Trip Standard Overload Curve Number = 2

The Overload Trip Relay setting tells us that we must monitor the Trip contact when performing this test, and the Overload Pickup Level tells us that our test current must be greater than 1.15xFLA to register as an overload. The motor nameplate must have a 1.15 Service Factor or greater to be adequately protected by this relay. If the motor has a service factor less than 1.15, the motor may be damaged by overloads that the relay will not detect. These example relay settings use a Standard Overload Curve whose characteristic can be described in the following ways:

Our Thermal Overload Timing Test current must be less than 50.0A. We can perform the same calculation for the Mechanical Jam Trip except that the Mechanical Jam setting is a multiple of FLA instead of the nominal CT secondary or Amps.

Looking for the lower of the two calculated currents, we can see that the Thermal Overload Trip test amps must be less than 8.8A/2xFLA, or the expected time must be less than 1.0s. It is always easier to deal with the current instead of calculating time

●● Thermal Overload Curve This method displays the curve and allows you to pick the time using the standard inverse or time-overcurrent method. It is not terribly accurate, but it will put you in the ballpark. We know we can’t inject more than 2xFLA, so we can draw a vertical line just before 2xFLA that stops when it touches the specified curve. (Curve #2 in our example.) Then draw a horizontal from the intersection to determine the expected time. Based on this method, the expected time should be around 61 seconds if we inject a threephase current slightly below 2xFLA.

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Protective Relay Vol 1 ●● Thermal Overload Formula

The formula method allows you to choose any current you wish, which can decrease your testing time. You should always stay at least 10% below the maximum current (2xFLA) to ensure that any test-set and/or relay accuracy errors will not cause the other element, such as Mechanical Jam, to operate before your Thermal Overcurrent test is complete. The following calculation will determine the expected operate time for a timing test at 1.9xFLA (2.0xFLA – 0.1xFLA) for the standard curves of our example GE Multilin SR469 relay:

60 50 40 30 20

The excel formula for this calculation would be: =(Curve*2.2116623)/((0.025303373*(Pickup-1)^2)+ (0.050547581*(Pickup-1))). If you wanted to automate the calculation, the excel formula for “Pickup” would be: =Mechanical_Jam_Pickup*0.9.

Prepare Your Test Plan Now that you have all of the necessary information to test the relay, it is time to create your test plan using the following criteria. ●● Thermal Overload Trip Table This method is the easiest and most accurate method of determining the expected time delay of a Thermal Overcurrent trip. Choose the row just above the maximum current (1.75xFLA in our example) and follow that row until you find the column that matches the curve settings (Curve 2 in our example). The expected trip time for a timing test performed while generating 1.75xFLA will be 84.83 seconds.

Table 4-2: SR469 Standard Overload Curves

●● Prefault Use the Prefault state we created previously to start the test: Prefault Magnitude A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

1.0A

69.28V 4.00 seconds

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

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●● Fault Decide on a test multiple using one of the methods described previously. We will use the table method for our example which uses a 1.75xFLA test current.

Create a fault state using the calculated current. The voltage does not change because we cannot predict how the system will react to a 3-phase overload without performing a fault study.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

mal Capacity Used currently stored in the relay, it should be zero percent. You are now ready to test. Keep watching the Thermal Capacity Used and start the test plan from the previous section. Notice that the Thermal Capacity Used is already increasing in the Prefault state, which will slightly skew test results. When the test automatically transitions to the Fault 1 state, there should be a message available displaying the amount of time before a trip occurs. Make sure that the displayed time roughly matches your calculations from the previous section. If not, review the settings and calculations again. After the relay operates, compare your test results to the specification as described in section “4) c)” of this paper.

Fault 1 Magnitude 7.7A

69.28V

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

Make sure that all outputs set to operate when a Thermal Trip occurs are connected to the test-set inputs. Also make sure that any other outputs not set to trip for this element will not stop the test by disabling the test-set input function or removing one wire from the test-set input.

Now you have a problem. Because the Thermal Capacity has been exceeded, a properly programmed relay will not allow you to reset the relay via the normal Reset functions while it waits for the Thermal Capacity Used bucket to drop below a safe value. If the relay does not have a Thermal Capacity Used alarm, activate the Emergency Restart input again to reset the Thermal Capacity Used bucket. Otherwise, read the next section to test the Thermal Capacity Used alarm.

●● Timers

THERMAL CAPACITY USED ALARM

Create a timer to start when the Fault 1 state is energized and stop when the relay Output is detected. Repeat for all relay Outputs set to operate. Make sure the timer will stop when a normally-closed contact opens or a normally-open contact closes.

The Thermal Capacity Used Alarm monitors the Thermal Capacity Used bucket and energizes a contact if the Thermal Capacity Used is greater than its setpoint. The setpoint for our example is:

Until Trip

●● Relay Outputs and Test-Set Inputs

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State Timers Timer 1

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

Fault 1 Magnitude Angle 0.00° 7.7A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° Until Trip Start Stop Fault 1 Input 1 Op

You could just use one timer and repeat the test for each relay output set to operate.

Perform the Test You must reset the relay’s thermal capacity before you can perform this test with maximum accuracy. Use the relay’s front panel or software to view the Thermal Capacity Used information stored in the relay. Activate the Emergency Restart input on GE Multilin relays or the EMSTR word bit on SEL relays. Re-check the Ther-

Thermal Model Overload Pickup Level = 1.15 FLA Thermal Capacity Alarm = Unlatched Thermal Capacity Alarm = Relays Alarm Thermal Capacity Alarm Level = 90 % used

Testing the Thermal Capacity Used alarm will require you to temporarily overload the motor and then return to a test current less than any other alarm. The other element typically set to sound an alarm is the Overload Alarm, so our normal current should not exceed that setting. Calculate the test current that will be 95% of the Overload Alarm pickup current as shown below:

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Protective Relay Vol 1 Our test plan must start with a Prefault state with the current we calculated above, that will be followed by the three-phase current calculated from our previous Thermal Overload Trip in Fault 1. Configure your test-set to monitor the Alarm contact(s) and ignore all other contacts.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Prefault Magnitude Angle 0.00° 4.807A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

Modern motor relays are digital relays that cannot be adjusted. Therefore, there really is no need to find the exact pickup level, it is more important that the relay operates when required and, more importantly, doesn’t under normal conditions. This element’s settings are defined below.

Fault 1

Phase Current Inputs

Magnitude

Angle 0.00° 7.700A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° Manual with return to Prefault

Your Thermal Overload test has just finished and the Thermal Capacity Used bucket should be at or near 100%. Activate the Emergency Restart input to reset the Thermal Capacity Used bucket or set up future tests until the Thermal Capacity Used is below the alarm setpoint. Follow this plan to test the Thermal Capacity Used element: ●● Monitor the Thermal Capacity Used indication and apply the Prefault and then Fault 1 current as per the test plan. The Thermal Capacity Used indication should start rising. The Alarm contact(s) will likely also operate because you are injecting a Thermal Overload. ●● When the Thermal Capacity Used is 5% less than the Thermal Capacity Used Alarm setting, switch the Fault 1 current back to the Prefault state. Press Reset to reset the Alarm contact(s). The Alarm contact should reset because your current is below the overload alarm, and you are below the Thermal Capacity Used setpoint.

Accuracy at <2 x CT: ± 0.5% of 2 x CT Accuracy at >2 x CT: ± 1.0% of 2 x CT Overload/Stall Protection/Thermal Model Pickup Accuracy: as per Phase Current Inputs

We can round up to 1% to be sure that all errors are accounted for in our test plan that starts with our previously defined Prefault. Prefault Magnitude A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

1.0A

69.28V

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

4.00 seconds

Then calculate the Overload Alarm pickup less the maximum error as follows:

●● Switch back to Fault 1 until the Thermal Capacity Used is 1% less than the Thermal Capacity Used Alarm setting, switch the Fault 1 current back to the Prefault state. Press Reset to reset the Alarm contact(s). The Alarm should reset. ●● Switch back to Fault 1 until the Thermal Capacity used rises by 1%. Return to Prefault. Attempt to reset the Alarm. If the Alarm does not reset, record your pickup. If the Alarm does reset, repeat until the Alarm does not reset.

OVERLOAD ALARM The Overload Alarm should send an alarm to the operator if the measured current exceeds the Overload Pickup Level. The following settings are important when testing the Overload Alarm: Thermal Model Overload Pickup Level = 1.15 FLA Overload Alarm = Unlatched Overload Alarm Relays = Alarm Overload Alarm Events = Off/No Overload Alarm Delay = 0.1 s

We want to be sure that the relay does not operate when the measured current is less than the Overload Alarm pickup, so we will stay in Fault 1 for significantly longer than the Overload Alarm Delay (0.1s in our example relay). We will stay in Fault 1 for 0.5s to give the Overload Alarm a chance to operate. If it does not operate, the test-set will automatically transition to Fault 2.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

Fault 1 Magnitude

Angle 0.00° 5.00A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 0.50 Seconds

38

Protective Relay Vol 1

Now we want to calculate the Fault 2 current which should be at least 10% higher than the pickup setting to ensure the relay will operate.

Fault 2 will be identical to Fault 1 except for the fault magnitude so that we only test the one change. Set your timer(s) to start when the test-set starts generating Fault 2 and to stop when the Alarm contact(s) operate.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Prefault Fault 1 Magnitude Angle Magnitude Angle 0.00° 0.00° -120.00° -120.00° 1.0A 5.00A

69.28V

120.00° 0.00° -120.00° 120.00°

4.00 seconds

Timers Timer 2

120.00° 0.00° 69.28V -120.00° 120.00° 0.50 Seconds or Alarm Operate

Fault 2 Magnitude Angle 0.00° -120.00° 5.566A 120.00° 0.00° -120.00° 69.28V 120.00° 0.50 Seconds or Alarm Operate Start Stop Fault 2 Input 2 Op

Check the Thermal Capacity Used indication to make sure it is significantly less than the Thermal Capacity Used Alarm, or else that alarm may operate during this test instead. Start the test by initiating the Prefault state. The test-set should transition to the next state automatically. Evaluate your test results after the test in completed. If the timer(s) did not start, something is wrong with the pickup or your test plan. If the timer started but did not stop, something is wrong with your relay output/test-set input connections or the time delay settings. If Timer 2 stopped within the Overload Alarm Delay and specified tolerance, the element’s pickup, timing, and logic functions must all be operating correctly. The expected time delay is 0.1s, which is a very small number. Very small pickup or time settings cannot be evaluated using percent because any difference between the measured and expected will create a large percent difference. We already discussed how to evaluate time delay results in section 4) c) of this paper where we calculated that the maximum allowable error for time delays less than 5s is 110.06ms. Therefore, your timers should be less than 0.21006 seconds. (The 100 ms Overload Alarm Delay setting plus the maximum allowable error.)

MECHANICAL JAM The Thermal Overload Trip and Overload Alarm are designed to monitor the motor current and protect the motor from thermal damage caused by prolonged overloads. The Mechanical Jam set-

ting monitors the motor current for sudden spikes that might occur if there was a mechanical failure in the motor bearings or external equipment. When the motor cannot turn, the current can spike to motor starting levels as the electric field tries to overcome the mechanical block. The most common motor relays do not have any pickup indication for Mechanical Jam and, therefore, the dynamic test procedure described in the Overload Alarm section of this paper is a perfect application of dynamic testing to test an element’s pickup, timing, and output logic. Our example relay has the following Mechanical Jam settings: Mechanical Jam Mechanical Jam Trip = Unlatched Mechanical Jam Trip Relays = Trip & Aux.1 Mechanical Jam Pickup = 2.00 xFLA Mechanical Jam Delay = 2 s

The SR469 specifications for the Mechanical Jam element follow. PHASE CURRENT INPUTS Accuracy at <2 x CT: ± 0.5% of 2 x CT Accuracy at >2 x CT: ± 1.0% of 2 x CT Mechanical Jam Pickup Accuracy: as per Phase Current Inputs Timing Accuracy: ±0.5 s or ± 0.5 % of total time

We can start creating the test plan by calculating the Mechanical Jam Pickup in Amps and the maximum tolerances.

Now that we know that the current will stay below 2xCT, we can calculate the pickup error.

Now we start with the normal Prefault current: A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Magnitude 1.0A

69.28V

Prefault

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00° 4.00 seconds

39

Protective Relay Vol 1 The Fault 1 current should be less than the Mechanical Jam Pickup minus the Maximum Pickup Error. We can use our calculations for Mechanical Jam pickup and tolerance to choose a test current that is less than the Mechanical Jam Pickup minus the Maximum Pickup Error. We’ll pick 8.7A for our Fault 1 current.

The expected time delay is 2.0s and we should check to see which of the two tolerances to use with the following calculations.

We want to be sure that the relay does not operate when the measured current is less than the Mechanical Jam pickup, so we will stay in Fault 1 for significantly longer than the Mechanical Jam Delay that is set for 2.0s in our example relay. We will stay in Fault 1 for 2.5s to give the Mechanical Jam a chance to operate. If it does not operate, the test-set will automatically transition to Fault 2. Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Fault 1 Magnitude Angle 0.00° 8.7A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 2.50 Seconds

The Fault 2 current should be at least 10% higher than the pickup setting to ensure the relay will operate as we calculated earlier in this section. Fault 2 will be identical to Fault 1 except for the fault magnitude, so that we are only testing the one change. Set your timer(s) to start when the test-set starts generating Fault 2 and to stop when the Trip contact(s) operate. Prefault

Magnitude

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State Timers Timer 1 Timer 3

1.0A

69.28V

Angle

0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

4.00 seconds

Fault 1

Magnitude

Angle

0.00° 8.70A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 2.50 Seconds or Trip or Aux.1 Operate

Fault 2

Magnitude

Angle

0.00° 9.68A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 2.50 Seconds or Trip or Aux.1 Operate Start Stop Fault 2 Input 1 Op Fault 2 Input 3 Op

You should ensure that the Thermal Capacity Used indication is less than 50% before you start the test, or else you may get a Thermal Overload Trip instead. Start the test by initiating the Prefault state. The test-set should transition to the next states automatically. Evaluate your test results after the test in completed. If the timer(s) did not start, something is wrong with the pickup or your test plan. If the timer started but did not stop, something is wrong with your relay output/test-set input connections or the time delay settings. If Timer 2 stopped within the Overload Alarm Delay and specified tolerance, the element’s pickup, timing, and logic functions must all be operating correctly.

Based on the calculations, the expected time delay should be between 1.5 to 2.5s.

ACCELERATION TRIP The Acceleration Trip element monitors the motor start state and will trip if the motor current does not drop below the FLA within the Acceleration Timer from Start setting. The motor is already thermally protected from overloads caused by motor starting via the Thermal Overload Trip, and this element is primarily defined by the connected load. The motor should start within a certain amount of time based on the connected load, so it would be a good idea to stop the motor before the thermal limit is reached if it fails to start within that time to reduce unnecessary stress to the motor and connected equipment. Our example will use the following settings: ACCELERATION TIMER Acceleration Timer Trip = Unlatched Acceleration Timer Trip Relays = Trip & Aux.1 Acceleration Timer from Start = 30.0 s

The Acceleration Trip test is one of the few times we do not use Prefault in the test procedure because this element is only active when the relay thinks that it is starting. The test current must be higher than the FLA, so we can use the Overload Trip Fault 1 test parameters for this test as shown below. Magnitude

A-Phase Current B-Phase Current

7.7A

C-Phase Current A-Phase Voltage B-Phase Voltage

0.00°

Angle

-120.00° 120.00° 0.00°

69.28V

C-Phase Voltage Time in State

Fault 1

-120.00° 120.00°

Until Trip

40

Protective Relay Vol 1

We want our timer(s) to start when the Fault 1 state is energized and to stop when the appropriate output(s) operate. A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State Timer 1 Timer 3

Magnitude

Fault 1

7.7A

69.28V Until Trip Start Fault 2 Fault 2

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

Stop Input 1 Op Input 3 Op

We should also look at the specifications to help determine what a good test result should be as per the following specifications and calculations:

The first thing to notice is that all of the relays have two calculations, one when the Phase or Average currents are above the FLA, and one when they are less than the FLA. Keeping track of that adds additional steps to our test calculations, so we are going to keep all of our test currents greater than the FLA current to eliminate that extra step. The next thing to notice is that different relays use different terms. Let’s look at some of those terms. ●● How to Calculate I2 I2 is the Negative Sequence Current (which is a complicated way of saying unbalanced current) that uses the following calculation where I2 is the Negative Sequence current and “a” rotates the vector counter-clockwise by 120° and “a2” rotates the vector by 240° counter-clockwise.

Acceleration Timer Timing Accuracy: 100ms or ± 0.5 % of total time

This calculation uses vector math and can be quite complicated. Here are a couple of I2 calculations with balanced and unbalanced conditions.

Make sure the Thermal Capacity Used value is less than 50% before you start this test, otherwise the Overload Trip may operate instead. Also make sure that only the inputs you are looking for (Trip and Aux.1 in our example) will stop the test to prevent an alarm or other element from operating. Start the test by initiating the Fault 1 state. The expected time delay is 29.85 to 30.15s as per the previous calculations.

CURRENT UNBALANCE Unbalanced currents are one of the major contributors to motor heating and can be caused by a large number of factors. The motor relay constantly monitors the motor current and calculates the motor current unbalance using its internal criteria. Unfortunately, different relays calculate Unbalance differently, even if those relays were produced from the same manufacturer.

Most relay testers aren’t math geniuses who can do vector math in their head and complex calculators are a rare breed, so we are going to keep our angles fixed at 120° apart so that we don’t need to make any complex computations. The following calculations demonstrate how the simplified calculations will get the same result.

Current Unbalance Calculations Here are the different formulas for the most popular motor relays.

Remember that this only works if the angles between phase currents are 120° apart in the correct phase rotation. Watch your angles! ●● How to Calculate I1 I1 is the Positive Sequence Current (which is a complicated way of saying balanced current) that uses the following calculation where I1 is the Positive Sequence current, “a” rotates the actual vector counter-clockwise by 120°, and “a2” rotates the vector by 240° counter-clockwise.

41

Protective Relay Vol 1

This calculation uses vector math and can be quite complicated. Here’s a couple of I1 calculations with balanced and unbalanced conditions.

Review the Relay Settings and Specifications Here are the settings and specifications for our example relay. CURRENT UNBALANCE Current Unbalance Trip = Unlatched Current Unbalance Trip Relays = Trip & Aux.1 Current Unbalance Trip Pickup = 20 % Current Unbalance Trip Delay = 10 s

The SR469 specifications for the Current Unbalance element follow. Most relay testers aren’t math geniuses who can do vector math in their head and complex calculators are a rare breed, so we are going to keep our angles fixed at 120° apart so that we don’t need to make any complex computations. The following calculations demonstrate how the simplified calculations will get the same result.

CURRENT UNBALANCE Pickup Accuracy: ±2% Timing Accuracy: ±0.5 s or ± 0.5 % of total time

The pickup accuracy is self-explanatory, but we should determine the Timing Accuracy in seconds. Based on the following calculation, the relay should operate within 9.49 and 10.51s.

Remember that this only works if the angles between phase currents are 120° apart in the correct phase rotation. Watch your angles! ●● How to Calculate IAverage IAverage is typically the average of the three phase current magnitudes as per the following formula. You typically do not have to worry about angles, but if you keep the Phase angles 120° apart with the correct phase rotation, it doesn’t matter. Did you notice that I1 and IAverage are the same if you keep the angles 120° apart with the correct phase rotation?

IAverage

I +I +I = A B C 3

●● How to Calculate IMaxPhase IMaxPhase is typically the current magnitude furthest away from the three-phase average current magnitudes. This could require several calculations, but we will always keep two current magnitudes identical and vary the third, so IMax will always be the odd current magnitude. ●● How to Calculate IMax IMax is the difference between IMaxPhase and IAverage magnitudes.

Create the Test Plan As usual, we start with a Prefault State as shown below using the calculations below for the Prefault current.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Magnitude 4.5A

69.28V

Prefault

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00° 4.00 seconds

We want to start with all currents greater than the FLA (4.A), so we will set IB and IC at 4.5A in Fault 1. Now we need to create a universal formula that we can use for any setpoint as follows.

42

Now we can calculate a magnitude for IA that will produce a Current Unbalance less than 18% (20% setting minus 2% error). We will use 17% to ensure that the relay does not operate.

The formulas are the same for the GE Multilin SR469, 269Plus, and GE M60 relays but all of the other relays (IMax relays) use a different formula. Let’s see if this formula will work when testing the IMax Relays.

Protective Relay Vol 1

Based on our calculations a 17% Current Unbalance injected into a GE Multilin SR469, 269Plus, and GE M60 relays (I2 relays) would be measured as a 34% Current Unbalance in the rest of the relays. This means that some relays can be twice as sensitive to Current Unbalances as the others. This is an important distinction and we can only hope the design engineer took this into account when they created the settings and we would have to modify our calculations accordingly for the new formula. We want to be sure that the relay does not operate when the measured Unbalance Current is less than the Unbalance Current pickup, so we will stay in Fault 1 for significantly longer than the Unbalance Current Delay that is set for 10.0s in our example relay. We will stay in Fault 1 for 11.0s to give the Unbalance Current a chance to operate. If it does not operate, the test-set will automatically transition to Fault 2.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Prefault Magnitude Angle 0.00° 4.5A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

Magnitude 7.265A 4.500A 69.28V

Fault 1

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00° 11.00 Seconds

The Fault 2 Unbalance Current should be at least 2% higher than the pickup setting to ensure the relay will operate as we calculated earlier in this section. So we can calculate the Fault 2 current using the same formula with a 23% Unbalance.

43

Protective Relay Vol 1 Relay Model GE Multilin SR469 GE M60 GE Multilin 369 GE Multilin 269Plus GE Multilin 239 SEL-701 SEL-749M SEL-710

Fault 2 will be identical to Fault 1 except for the fault magnitude to only test the one change. Set your timer(s) to start when the test-set starts generating Fault 2 and to stop when the Trip contact(s) operate. Prefault Fault 1 Magnitude Angle Magnitude Angle A-Phase Current 0.00° 7.265A 0.00° B-Phase Current 4.5A -120.00° -120.00° 4.500A C-Phase Current 120.00° 120.00° A-Phase Voltage 0.00° 0.00° B-Phase Voltage 69.28V -120.00° 69.28V -120.00° C-Phase Voltage 120.00° 120.00° 11.00 Seconds or Trip Time in State 4.00 seconds or Aux.1 Operate Timers Timer 1 Timer 3

Fault 2 Magnitude Angle 8.532A 0.00° -120.00° 4.500A 120.00° 0.00° 69.28V -120.00° 120.00° 11.00 Seconds or Trip or Aux.1 Operate Start Stop Fault 2 Input 1 Op Fault 2 Input 3 Op

Perform the Test You should ensure that the Thermal Capacity Used indication is less than 50%, or else you may get a Thermal Overload Trip instead. Start the test by initiating the Prefault state. The test-set should transition to the next states automatically. Evaluate your test results after the test in completed. If the timer(s) did not start, something is wrong with the pickup or your test plan. If the timer started but did not stop, something is wrong with your relay output/test-set input connections or the time delay settings. If Timer 2 stopped within the Overload Alarm Delay and specified tolerance, the element’s pickup, timing, and logic functions must all be operating correctly. The expected time delay is 10.0s and we should check to see which of the two tolerances to use with the following calculations. Based on the calculations we made at the beginning of this section, the expected time delay should be between 9.49 and 10.51s. Repeat the test using the alarm contacts, if required.

Input Signals Unbalance > 40%, or One Phase=0 and IAvg>25% FLA Unbalance > 30%, or Motor Load > 30% and one phase = 0.0A Unbalance > 30%

Time Delay 2.0 seconds, ±0.5 seconds 2.0 seconds, ±0.06 seconds 2.0 seconds ±0.51seconds 4.0 seconds, ±1.5 seconds

N/A

N/A

This protection should operate when the motor is starting or running, so the test plan can be as simple as the Acceleration Time test described in an earlier section, or you could slightly modify the Current Unbalance from the previous section to apply 0.00A in one phase as per the following test plan. The Single Phase Trip protection will use the same trip outputs as defined in the Current Unbalance Trip element.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State Timers Timer 1 Timer 3

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

Magnitude 0.00A 4.500A 69.28V

Fault 1

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

Trip or Aux.1 Operate Start Stop Fault 1 Input 1 Op Fault 1 Input 3 Op

SHORT CIRCUIT TRIP The Short Circuit Trip is one of the simplest motor relay elements because it is a simple overcurrent element that does not require any special test plans. Here are the settings and specifications for the Short Circuit Trip in our example: SHORT CIRCUIT TRIP Short Circuit Trip = Unlatched Overreach Filter = Off/No Short Circuit Trip Relays = Trip & Aux.1 Short Circuit Trip Pickup = 10.0 CT Intentional Short Circuit Trip Delay = 0 ms Short Circuit Trip Backup = Off/No

You must make sure that the Short Circuit Trip setting is greater than the maximum motor starting current. Here is the calculation for our example motor.

SINGLE PHASE TRIP Some motor relays have additional protection to protect the motor from single phase conditions that could occur due to a blown fuse, malfunctioning circuit breaker/starter, or other system problem. The following table outlines the Single Phase configurations in the most popular motor relays.

Notice that the Short Circuit Trip Pickup is not in Amps or a multiple of FLA. The setting is a multiple of the CT Secondary nominal current, which is typical for a GE Multilin relay. The CT Secondary nominal current is listed on the relay nameplate

44

Protective Relay Vol 1

(typically 5.0A in North America and 1.0 Amps in the rest of the world), and our example relay has a 5A secondary. Therefore, the pickup in secondary amps is:

We want to be sure that the relay does not operate when the measured current is less than the Short Circuit Pickup, so we will stay in Fault 1 for significantly longer than the Short Circuit Delay setting plus the Maximum Timing Error (0.0ms + 0.06s = 0.06s). We will stay in Fault 1 for 0.1s to give the Short Circuit a chance to operate. If it does not operate, the test-set will automatically transition to Fault 2.

The Short Circuit Pickup is greater than the maximum expected starting current, so we are ready to test this element.

Review the Specifications The SR469 specifications for the Short Circuit element follow. PHASE CURRENT INPUTS Accuracy at <2 x CT: ± 0.5% of 2 x CT Accuracy at >2 x CT: ± 1.0% of 2 x CT PHASE SHORT CIRCUIT Pickup Accuracy: as per Phase Current Inputs Timing Accuracy: +50ms

We know that our pickup setting is 50A, which is greater than 2xCT (10A), so we can calculate the maximum tolerance using the “Accuracy at >2 x CT” specification.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

Fault 1 Magnitude Angle 48.5A -60.00° 1.0A -120.00° 1.0A 120.00° 30.00V 0.00° 69.28V -120.00° 69.28V 120.00° 0.10 Seconds

Notice that the faulted voltage magnitude has decreased, that faulted current angle is lagging the voltage, and the other two phases are unaffected by the fault. These changes help simulate the conditions that would exist if a phase-ground short circuit did occur on the system. These changes are not required for most relays, but simulating realistic fault conditions whenever possible is a good habit to get into so that when you come across the super-intelligent relays that are looking for realistic quantities, you will already be prepared. The Fault 2 current should be at least 10% higher than the pickup setting to ensure the relay will operate. (50*1.1=55A) Fault 2 will be identical to Fault 1 except for the fault magnitude to ensure we are only testing the one change. Set your timer(s) to start when the test-set starts generating Fault 2 and to stop when the Trip contact(s) operate.

Now we can calculate the time delay tolerance:

Prefault Magnitude

Create the Test Plan We can start with the normal Prefault current or skip it, your choice. Prefault Magnitude A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage

1.0A

69.28V

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

The Fault 1 current should be less than the Pickup minus the Maximum Pickup Error (50A – 1.1A = 48.9A). We’ll choose 48.5A for our Fault 1 current. We’ve been applying three-phase faults up until now, but a short circuit could occur on any phase. Therefore, we want to apply the fault current one phase at a time and test all three phases to ensure all three phases are working correctly.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

1.0A

69.28V

Angle 0.00° -120.00° 120.00° 0.00° -120.00° 120.00°

4.00 seconds

Timers Timer 1 Timer 3

Fault 1 Magnitude

Angle

48.5A -60.00° 1.0A -120.00° 1.0A 120.00° 30.00V 0.00° 69.28V -120.00° 69.28V 120.00° 0.10 Seconds or Trip or Aux.1 Operate

Fault 2 Magnitude

Angle

55.0A -60.00° 1.0A -120.00° 1.0A 120.00° 30.00V 0.00° 69.28V -120.00° 69.28V 120.00° 0.10 Seconds or Trip or Aux.1 Operate Start Stop Fault 2 Input 1 Op Fault 2 Input 3 Op

Perform the Test Start the test by initiating the Prefault state. The test-set should transition to the next states automatically. Evaluate your test results after the test is completed. If the timer(s) did not start, something is wrong with the pickup or your test plan. If the timer started but did not stop, something is wrong with your relay output/test-set input connections or the time delay settings. If Timer 2 stopped within the Overload Alarm Delay and specified toler-

45

Protective Relay Vol 1 ance, the element’s pickup, timing, and logic functions must all be operating correctly. Rotate the Fault to B-Phase and perform the test again.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Time in State

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00° 4.00 seconds

Timers Timer 1 Timer 3

Fault 1 Fault 2 Magnitude Angle Magnitude Angle 1.0A 0.00° 1.0A 0.00° 48.5A 180.00° 55.0A 180.00° 1.0A 120.00° 1.0A 120.00° 69.28V 0.00° 69.28V 0.00° 30.00V -120.00° 30.00V -120.00° 69.28V 120.00° 69.28V 120.00° 0.10 Seconds or Trip or 0.10 Seconds or Trip or Aux.1 Operate Aux.1 Operate Start Stop Fault 2 Input 1 Op Fault 2 Input 3 Op

Rotate the Fault to C-Phase and perform the test again.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage

Prefault Magnitude Angle 0.00° 1.0A -120.00° 120.00° 0.00° 69.28V -120.00° 120.00°

Time in State

4.00 seconds

Fault 1 Magnitude Angle 1.0A 0.00° 1.0A -120.00° 48.5A 60.00° 69.28V 0.00° 69.28V -120.00° 30.00V 120.00° 0.10 Seconds or Trip or Aux.1 Operate

Timers Timer 1 Timer 3

Fault 2 Magnitude Angle 1.0A 0.00° 1.0A -120.00° 55.0A 60.00° 69.28V 0.00° 69.28V -120.00° 30.00V 120.00° 0.10 Seconds or Trip or Aux.1 Operate Start Stop Fault 2 Input 1 Op Fault 2 Input 3 Op

GROUND FAULT TRIP The Ground Fault Trip is one of the simplest elements in a motor relay after you get the right connections, because it is a simple overcurrent element that does not require any special test plans. Here are the settings for the Ground Fault Trip in our example:

The Ground Fault element could use a regular CT with a 1.0 or 5.0 secondary, but some motors use a special 50:0.025 CT. You should never try to simulate the secondary of these CTs and you should only apply the test parameters in primary amps as described later in this section. The expected pickup in primary amps can be calculated with the following formula.

The Short Circuit Pickup is greater than the maximum expected starting current, so we are ready to test this element.

Choose your Connection Motor relays allow for a couple of different CT configurations, so you can make one of the connections outlined in the two sections on Current Transformer Connections.

Review the Specifications The SR469 specifications for the Ground Fault element follow. GROUND CURRENT INPUTS Accuracy: ± 0.5% of 1xCT for 5A Accuracy: ± 0.5% of 5xCT for 1A Accuracy: ± 0.125 A for 50:0.025 GROUND INSTANTANEOUS Pickup Accuracy: as per Ground Current Input Timing Accuracy: +50ms

The pickup tolerance for a regular CT is:

GROUND FAULT Ground Fault Alarm = Off Ground Fault Alarm Events = Off/No Ground Fault Trip = Unlatched Ground Fault Trip Relays = Trip Ground Fault Trip Pickup = 0.10 CT Intentional GF Trip Delay = 1000 ms Ground Fault Trip Backup = Off/No Ground Fault Overreach Filter = Off/No

Notice that the Ground Fault Trip Pickup is not in Amps or a multiple of FLA. The setting is a multiple of the CT Secondary nominal current, which is typical for a GE Multilin relay. The CT Secondary nominal current is listed on the relay nameplate (typically 5.0A in North America and 1.0 Amps in the rest of the world), and our example relay has a 5A secondary. Therefore, the pickup in secondary amps is:

The pickup tolerance for a 50:0.025 CT is:

Now we can calculate the time delay tolerance:

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Protective Relay Vol 1

Create the Test Plan We’ll use the 50:0.025 connections for our example test plan. The Fault 1 current should be less than the Pickup minus the Maximum Pickup Error (5.0A – 0.136A = 4.864A). We’ll choose 4.75A for our Fault 1 Ground current. We want to be sure that the relay does not operate when the measured current is less than the Short Circuit Pickup, so we will stay in Fault 1 for significantly longer than the Short Circuit Delay setting plus the Maximum Timing Error (1000.0ms + 0.06s = 1.06s). We will stay in Fault 1 for 1.2s to give the Short Circuit a chance to operate. If it does not operate, the test-set will automatically transition to Fault 2.

Ground Current Time in State

4.75A 1.2 Seconds

Angle 0.00°

Voltage only

500-700ms

Voltage only None

3-4 seconds None

Current and/or Voltage

0.5 seconds

We know that the relay is responding to the correct phase rotation at this point, so all we need to do to test this element is to apply three-phase voltage in the reverse direction, or three-phase current if no voltages are connected and the relay supports phase-reversal protection via current inputs. Fault 1

Fault 2 will be identical to Fault 1 except for the fault magnitude to ensure we are only testing the one change. Set your timer(s) to start when the test-set starts generating Fault 2 and to stop when the Trip contact(s) operate. Fault 2 Magnitude 5.50A 1.2 Seconds Start Fault 2 Fault 2

Time Delay

Magnitude

The Fault 2 current should be at least 10% higher than the pickup setting to ensure the relay will operate. (5.0*1.1=5.5A)

Fault 1 Magnitude Angle Ground Current 4.75A 0.00° Time in State 1.2 Seconds Timers Timer 1 Timer 3

Input Signals

Here is the three-phase voltage phase reversal plan.

Fault 1 Magnitude

Relay Model GE Multilin 369 GE Multilin SR469 GE Multilin 269 GE Multilin 239 SEL-701 SEL-710 SEL-749

Angle 0.00° Stop Input 1 Op Input 3 Op

Perform the Test Start the test by initiating the Fault 1 state. The test-set should transition to the next states automatically. Evaluate your test results after the test is completed. If the timer(s) did not start, something is wrong with the pickup or your test plan. If the timer started but did not stop, something is wrong with your relay output/test-set input connections or the time delay settings. If Timer 2 stopped within the Overload Alarm Delay and specified tolerance, the element’s pickup, timing, and logic functions must all be operating correctly.

PHASE REVERSAL The Phase reversal element typically has two options, On/Off and what outputs to operate. This element monitors the power system and if the 3-phase voltage and/or current is applied to the motor with the opposite phase rotation, the relay will trip in a preset amount of time. The following table outlines the phase reversal configurations in the most popular motor relays.

A-Phase Current B-Phase Current C-Phase Current A-Phase Voltage B-Phase Voltage C-Phase Voltage Timers Timer 1 Timer 3

Angle 0.00° -120.00° 120.00° 0.00° 120.00° -120.00° Stop Input 1 Op Input 3 Op

0.0A

69.28V Start Fault 1 Fault 1

Here is the three-phase current phase reversal plan. Fault 1 Magnitude A-Phase Current B-Phase Current C-Phase Current Timers Timer 1 Timer 3

1.0A Start Fault 1 Fault 1

Angle 0.00° 120.00° -120.00° Stop Input 1 Op Input 3 Op

VOLTAGE, FREQUENCY, AND POWER ELEMENTS These elements are no different than any other relay and are not covered in this paper.

RTD TEMPERATURE TESTING RTD’s are Resistive Temperature Devices that are strategically placed in and around the motor to monitor the motor’s temperature. RTD’s can be constructed with different materials, but most modern RTD’s use 100Ω Platinum which means that the resistance across the RTD is 100Ω when the material is 0°C. There are three wires connected to an RTD with the RTD material between two, and an extra lead that allows the relay to eliminate the lead resistance from the resistance measurement to reduce any error caused by long runs. A typical motor has an RTD mounted at each end of the stator, an RTD mounted near the front and back end bearings, and maybe one for the ambient temperature. You can purchase an RTD simulator to test the RTD protection, but most RTD protection uses more than one signal to prevent nuisance trips caused by an RTD

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Protective Relay Vol 1 failure. This is called voting in the SR469 relay and all of the RTDs that “vote” together must be above the temperature setpoint for the relay to operate, so you must purchase at least two simulators to test most relays that use this scheme. RTD Temperature testing starts by reviewing the settings and specifications. Our example relay has the following settings. RTD #1 RTD #1 Application = Stator RTD #1 Name RTD #1 Alarm = Unlatched RTD #1 Alarm Relays = Alarm RTD #1 Alarm Temperature = 130 °C RTD #1 Trip = Unlatched RTD #1 Trip Voting = RTD #2 RTD #1 Trip Relays = Trip RTD #1 Trip Temperature = 155 °C

RTD #2 RTD #2 Application = Stator RTD #2 Name RTD #2 Alarm = Unlatched RTD #2 Alarm Relays = Alarm RTD #2 Alarm Temperature = 130 °C RTD #2 Trip = Unlatched RTD #2 Trip Voting = RTD #1 RTD #2 Trip Relays = Trip RTD #2 Trip Temperature = 155 °C

RTD INPUTS Accuracy: ± 2 °C RTD Time Delay: 3 s

Review all of the RTD trip settings and make a summary of the Alarm Relays, Alarm temperature, Trip Voting, Trip Relays, and Trip Temperature settings for all RTDs. Monitor the Trip and Alarm relays and set all of the RTD simulators 5° below their alarm settings, or set all potentiometers at the resistance to be the row below the temperature setpoint. Our example relay has 100Ω Platinum RTDs with a 130°C setpoint, so we will apply 146.06Ω (120°C) to all Stator RTDs. All alarm and trip contacts should remain de-energized and the relay RTD metering screen should show roughly 120°C for all Stator RTDs. Raise the RTD temperature (135°C) or potentiometer resistance (153.58Ω) above the alarm setting on one RTD. The Alarm contact should close within 3.0 seconds as per the specifications. Return the RTD temperature/resistance to the start level and repeat for all RTDs. Raise the RTD temperature (150°C)/potentiometer resistance (157.32Ω) just below the Trip Temperature Trip setting on the first group of RTDs that vote with each other. Raise the temperature of one of the RTDs above the setpoint (160°C/161.04Ω). Nothing should happen because only one RTD is above the setpoint. After four seconds (to give the relay a chance to operate), raise the other RTD above the setpoint. The Trip Relay contacts should operate within three seconds. Repeat for all groups of RTDs.

CONCLUSION Motor relay testing is fairly simple once you understand the basic characteristics of a motor, and apply some dynamic testing principles to build test plans. However, all of the element testing described in this paper assumes that you are using the relay’s set-

tings to create and implement your test plans. This is usually the only information that a relay tester has for testing, but using the relay’s settings to create a test plan can be a huge waste of time. You will never find a problem without a great deal of relay testing experience of good and bad settings. Reviewing the drawings and settings for consistency will find some obvious problems with the installation, and performing the analog and digital input/output tests will find obvious problems with the relay. Performing element tests as we’ve described in this paper will prove that the relay will perform as it set, but there are no checks and balances to see if the relay was set correctly, other than the relay tester’s experience with similar relays and settings. Ideally, you should look to the coordination study to see if the relay settings and test results match the coordination study for the Thermal Overload Trip. The rest of the element information should come from the relay engineer who created the settings or operates the motor. They should give you test parameters showing how they intended the relay to protect the motor. These test parameters should be in an external document outside of the settings so that you can test that missing piece of the puzzle. Second best would be the working papers they used when entering the relay settings. Without this information, you will never know if the relay is operating as it was supposed to.

REFERENCES Donaldson, Kevin, 269/269+ Theory of Operation and Functional Testing, GE Multilin. Young Wester, Motor Protection Principles, GE Multilin. GE Multilin, 239 Motor Protection Relay Instruction Manual. GE Multilin, 269Plus Motor Management Relay Instruction Manual. GE Multilin, 369 Motor Management Relay Instruction Manual. GE Multilin, 469 Motor Management Relay Instruction Manual. Schweitzer Engineering Laboratories, Inc.; SEL-701-1 Monitor Instruction Manual. Schweitzer Engineering Laboratories, Inc.; SEL-710 Motor Protection Relay Instruction Manual. Schweitzer Engineering Laboratories; Inc., SEL-749M Motor Protection Relay Instruction Manual. GE Digital Energy, M60 Motor Protection System UR Series Instruction Manual. Chris Werstiuk is an Electrical Technologist, Journeyman Electrician, Professional Engineer and author of the upcoming book, “digital Relay testing: A Practical Guide from the Field.” He is also the founder of “RelayTesting.net”, an online resource for testing technicians who need custom test leads, test sheets templates, step-by-step testing guides, or an online forum to exchange ideas and information.

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Protective Relay Vol 1

TEST THE SYSTEM, NOT THE ELEMENTS. PowerTest 2015 Will Knapek, OMICRON electronics Corp.

will work the designed system. This test should be a thorough test, done in a lab, to determine if the operating characteristics of the relay will perform to the design specifications. If the relay performs as intended then it is accepted for use in the protection system. A Commission test, sometimes mistakenly called an Acceptance test, is performed in the field with the intended system settings applied. Elements can be tested again at this time to ensure the settings have been applied. It is at this stage that a complete test of the system as it is intended to operate must be conducted. It is a disservice to only test elements and neglect the system test. A system test is designed to prove that the protection system will operate as intended by applying a fault and ensuring that the relay responds as the protection engineer intended. After a predetermined time a Scheduled test should be performed. This test should not change any settings, but by using a subset of the Commissioning Test, verify the relay is still performing as designed. However if any settings are changed a complete Commissioning Test must be conducted. This paper will explore the shift in traditional relay testing to a more complete system test.  We need to test the logic of the relay, not the capability of the microprocessor to perform math. As the technology for protecting the power systems has evolved, the process of testing the protection must also evolve.  The protection systems that are in service are moving away from electromechanical devices to intelligent electronic devices, (IED) the methods of testing need to be updated.  No longer is it applicable to test the capability of the modern relay to perform the mathematics of calculating the proper timing of an overcurrent element or the proper impedance characteristic in a distance element.  This paper will explore the testing practice of system testing and learn how to apply them. With the change of the Protection and Control schemes from an Electro-Mechanical base to Microprocessor based relays, a change in the thinking of how to test a protection system must also take place. No longer can we focus only on testing the element, but we must now test the protection scheme as a system. Let’s look at where we are and where we need to go in terms of testing PAC systems. To start, there are several stages of testing relays and the systems they will be part of. The Acceptance test is the first step in this process. An Acceptance test is preformed to determine if the relay

Another type of test would be a Troubleshooting Test conducted after an operation. If it is found to be preforming correctly, then it can be placed back into service. If not or changes are required then a complete Commissioning test must be conducted on the system. In the electromechanical relay world, each element has a separate relay. Some elements require a separate relay for each phase. This causes the need for large spaces just to accommodate the relays used in the protection system. All electromechanical relays must be tested for the element, as each relay is the element. The EM relay is made up of mechanical parts such as springs, bearings, magnets and sometimes capacitors. These parts are designed to emulate a mathematical formula that models the intended reaction to the fault. The instruction books that were written for the EM relays for the most part do not show the use of a modern three-phase test set. The calibration instructions must be adapted to the current relay test sets being used. A great deal of the skills learned on the correct way to adjust these relays is being lost as the workforce ages and retires.

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Protective Relay Vol 1

The first generations of IED’s the logic was relatively simple compared to today’s IED’s. This has to do with the increased capabilities that are now available in the new designs of relays. Logic statements went from a limited to a set of elements assigned to one output, to writing a complete PLC type program controlling several out puts and even other relays. Today’s relays have much more processing capability built in allowing much more complex protection schemes. This is the main reason that system testing is a must. Why waste time confirming the manufactures algorithm for an overcurrent curve or a differential slope is correct? Test what is the most likely to have an error, the logic. And this logic is where you will find the most errors. Either from improper wiring of I/O to the relay, transposed symbols in the logic statement, and incorrect version of the setting file, to changes made in the field. And the list of possible mistakes goes on.

EM Relays require scheduled maintenance and this maintenance differs by the type and vintage of the relay. The importance of the system along with the economic impact it produces will dictate to a large extent the time intervals between maintenance testing events. Also a point to consider is the impact that a particular maintenance procedure will have on the commissioned status of the protection system. Any changes to the relay prompts a re-commissioning of the system. Another point to consider is the timing of the maintenance period is the environment that the relay is subjected to. EM relays should be tested to the manufactures recommendations following the outlined procedures in the instruction books.

So what does need to be tested on an IED? Legacy single function testing methods on a modern IED are irrelevant with one exception – Acceptance Testing. No need to repeatedly check the capability of the relays processor to perform math. For the IED, any check recommended by the manufacturer that pertains to the operational health of the device. Make use of the IED self-check Logs and Reports. A wealth of knowledge can be gained by evaluating the event logs, checking for misoperations and other events out of the ordinary. Meter check and Settings Compare, tests of output relay contacts operation, and verification inputs to IED and wiring inspection are other tests that must be performed. The current NERC standard PRC-005-2 states the only required test on microprocessor relays is: ●● Verify operation of the relay inputs and outputs that are essential to proper functioning of the Protection System. ●● Verify acceptable measurement of power system input values.

In contrast the IED relay, element setting does not play as large a focus in the testing of the relay. Several element are now contained in one enclosure, thus reducing the amount of space needed for the protection system.

Remember that in a maintenance test it is best to use any test that is a subset of the Commissioning Test that does not require changing settings. Change of settings will require a complete re-commission of the protection relay.

For any IED, a proper Acceptance Test protocol should be employed to verify each and every function and specification claimed by the manufacturer before it is used. After this no further functional test is required unless the hardware design or firmware has changed. This testing is done in the lab and only after the relay meets the needs of your protection system should the relay be purchased. Proper Testing of an IED requires duplicating the system application sources and I/O to put the IED in the correct operational conditions.

So how do you test the system? This can be done in many ways. I have already discussed testing all inputs and outputs to determine their proper functionality. There are several types of system tests. To name a few: Logic type tests, UV Load Shed, System Restoration, Two or more PMU’s, and SCADA/RTU tests.

With an IED, logic should be the main focus of the field testing. Verification of the correct element setting is necessary, but an injection of voltages and currents after installation to prove the relay picks up and calculated the timing points can be a waste of time. This type of test should be proven in the Acceptance Test stage.

System Testing is the ONLY test method that requires no setting changes of the IED in order to correctly verify its operational compliance. Proper Trouble Shooting of PAC miss operations should also use System Testing as the baseline for evaluations and proper scheme operations. As the digital relays continue to evolve and become more complex, our methods for testing them must also evolve. Legacy test methods cannot properly address these complex relays or simulate

50 the power system adequately in order to prove their operational performance and compliance. Advanced testing tools and methods are available and should be used. Using a Network Simulation Model to provide an even better fault simulation would be the next step beyond the Constant Z method. For many IEDs this will be the only way to produce correct system events that they will respond to as expected. Modern relays look for invalid fault signals to increase security of the system. They will not respond to static fault signals as EM and first generation relays did. The best way to test the modern IED is to use a method of fault signal generation that will apply faults with pre fault, Asymmetrical components, and a post fault signals. To test as a system, all needed inputs must be simulated or be active and to properly assess the performance all outputs must be monitored. This can be accomplished with software that will drive the test set with Network Simulation signals or the ability to replay actual faults from COMTRADE files. A common practice is to also use COMTRADE files that are generated by system modeling software used to derive the setting scheme. To perform a system test you will need as a minimum, the ability to perform Network Simulation Testing with a test set that can simulate three phase power system voltages and currents. The test set must be able to output true system faults and replicate asymmetrical signals seen during a fault. The capability to monitor several outputs of the protective relay, both binary and GOOSE is also required. If there is more than one relay involved in the protection scheme then a test set will be required at each relay and they must have the ability to be synchronized with a GPS clock signal.

Protective Relay Vol 1 the line relative to direction the relay is monitoring. This requires detailed planning to develop the test plan for each location so that the correct signals are applied. There is a new software package available that will control multiple test sets with only one program, thus making this a simple task. Some critical factors to make your system testing successful is the first training is a requirement, not an option. Testing personnel must be trained in the proper techniques to perform a system test. They must understand what the test is meant to accomplish. This training also applies to the engineering department of understand what the test is evaluating, not just producing a document to file away. Perform Acceptance tests on all discrete components in a lab or controlled environment. This eliminates the need for further functional testing unless it is E/M. Use the same system test cases regularly on new or existing relays of the same application for both commissioning and routine testing. Verify the health and availability of the digital protection relay/ system in service without violating its commissioned status or performing excessive testing. When possible, use matched test equipment and the best accuracy clocks available, and match the test equipment capabilities to the protection application requirements. Coordinate the test case sequences for each end and ensure the power system will be properly modeled. Use a Network Simulation tool for best system test cases. Automate as much of the data exchange into the test software and/or test cases.

CONCLUSIONS As the digital relays continue to become more complex, our methods for testing them must also change. Legacy test methods cannot properly address these complex relays or simulate the power system adequately in order to prove their operational performance and compliance.

What is most common today is End to End Testing. This entails two test set synchronized to start the injection of the fault signals to the relay by a GPS or IRIG pulse. The two test sets must have programs that would inject the fault with the correct values to simulate the fault at a predefined location relative to the instrument transformers providing the signals to the relay. So if a distance relay system was to be tested then at one relay the fault signal injected could be a 20% of the line length, the other test set would need to inject the fault signal at values simulating a fault at 80% of

Advanced testing techniques are available and should be used. Using legacy test methods and technology is a dis-service to the industry, the utility, the workforce, and more important the customer. Training, Education, and the Right Tools are key for an efficient Power System. New standards and technology coupled with proper system test methods like End-to-End testing allow a significant reduction in man-hours and intrusive functional testing. (Better results with less risk.) To properly maintain a modern protection system one must begin at the planning and engineering phase in order to provide the proper design, support, build and configuration of the protection system (design friendly to System Testing).

Protective Relay Vol 1 REFERENCES A. Apostolov and B. Vandiver III, “Maintenance Testing of Multifunctional Distance Protection IEDs”, IEEE T&D Conference, New Orleans, LA, April 2010. A. Apostolov and B. Vandiver III, “Testing of Advanced Distance Protection Relays," TX A&M Relay Conference, College Station, TX, April 2009. A. Apostolov and B. Vandiver III: “Automated Testing of Communications Based Schemes in Transmission Line Protection Relays,” Power Industry Computer Applications-PICA, Sydney, Australia, May 2001. Chris Werstiuk, The Relay Testing Handbook, Principles and Practice, Arvada, CO: Valence Electrical Training Services, 2012. J. Lewis Blackburn, "Protective Relaying: Principles and Application," New York: Marcel Dekker, Inc., October 17, 1997. Walter A. Elmore, Protective Relaying: Theory and Applications, 2nd ed., New York: Marcel Dekker, Inc., September 9, 2003. William Knapek received a BS degree in Industrial Technology from East Carolina University in 1994. He retired from the US Army as a Chief Warrant Officer after 20 years of service in 1995. During his time with the Army Corps of Engineers, he held positions as a power plant instrumentation specialist, a writer/instructor for the Army Engineer School, and a Facility Engineer for a Special Operations compound. He has been active in the electrical testing industry since retiring in 1995. He worked for NETA companies in the Nashville, TN area until joining OMICRON electronics as an application engineer in April of 2008. He is currently the Sales Manager for the Southeast Area of North America for OMICRON electronics Corp, USA. He is certified as a Senior NICET Technician and a former NETA Level IV technician. Will is a member of IEEE and vice chair of WG I23 of the PSRC.

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OPEN-CIRCUITED CT MISOPERATION AND INVESTIGATION PowerTest 2015 David Costello, Schweitzer Engineering Laboratories, Inc.

ABSTRACT A wire crimping error caused a current transformer (CT) to become open-circuited under load, a relay to operate, and an industrial plant outage. The wiring error was corrected, and the relay, internally damaged by severe overvoltage, was put back into service. Root cause analysis predicted and exposed the damage and led to corrective actions. This paper revisits the IEEE dielectric strength standard, safe design and work procedures regarding CTs, and what happens when a CT is open-circuited under load. The case study emphasizes the critical importance of commissioning tests and root cause analysis to power system reliability.

Fig. 2 shows the manufacturer excitation curve for an ANSI C400 (IEC 100 VA 5P 20) 2000:5 single-ratio CT. The ANSI/IEEE rating defines the voltage developed across a standard burden by a steady-state, symmetrical secondary current equal to 20 times nominal, with less than 10 percent ratio error. The ANSI knee-point voltage is the voltage corresponding to the point in the excitation characteristic where the tangent is at 45 degrees to the abscissa, when the curve is plotted on log-log axes with square decades. This is the point of maximum permeability on the excitation characteristic. While the excitation characteristic has a well-defined knee 1 point, it has no discernible point of saturation .

REVIEW OF CT CONCEPTS Fig. 1 shows the equivalent circuit of a current transformer (CT), referred to the CT secondary side. The CT primary winding current is IP, the CT ratio is n, and the current source IP/n represents the ratio current. The CT secondary winding resistance is represented by RS. The nonlinear inductive reactance ZE represents the CT magnetization branch. The excitation current IE flowing through the magnetization branch ZE sets up the flux in the CT. The excitation voltage ES is due to the flux linkage produced by the magnetizing branch inductance. Impedance ZB represents the total load, or burden, connected to the CT secondary terminals. The CT secondary terminal voltage VS appears across the CT burden. The secondary current IS flows through the CT burden.

Fig. 2: Excitation Curve for an ANSI C400 2000:5 CT Fig. 3 shows the graphical relationships between the excitation characteristic (a) and the magnetic flux density (b), excitation current (c), and excitation voltage (d) as functions of time.

Fig: 1: CT Equivalent Circuit A typical magnetization curve, or B-H curve, conveys the nonlinear relationship between the magnetic flux density (B) and the magnetic field intensity (H). The CT secondary excitation curve is an alternate representation of the B-H curve and has a similar shape because the flux density B is proportional to the voltage ES and the magnetic field intensity H is proportional to excitation current IE. The voltage ES is also proportional to the rate of change of magnetic flux φ.

Fig. 3: Excitation Characteristic (a), Flux Versus Time (b), Excitation Current Versus Time (c), and Excitation Voltage Versus Time (d) When the magnetic flux density B or excitation voltage ES is low, the excitation current IE is low and the CT behaves almost linearly, with no saturation in the magnetic core. As the burden

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Protective Relay Vol 1 current or impedance increases, the excitation voltage ES, the magnetic flux density B, and the excitation current IE also increase. At a given flux density, the magnetizing inductance saturates and the excitation current increases disproportionally with voltage. The secondary current IS at this point is no longer an accurate replica of the primary current. The CT excitation current IE creates a difference between the secondary current IS and the ratio current IP/n. This difference, IE, is the CT error. As indicated in Fig. 3, when the CT is saturated, the rate of change of flux is almost zero (b), and therefore, the excitation voltage is near zero. However, in the linear region, the flux can exhibit a very high rate of change and therefore a very high induced voltage. This produces the voltage peaks shown in Fig. 3d.

These peaks represent dangerous overvoltages, which can damage CTs, protective relays, and the insulation of the secondary wiring, as well as expose personnel to dangerous primary-level voltages (thousands of volts) on the terminal blocks and test switches of switchboard panels and switchgear. This demonstrates why CTs should never be left with the secondary open and the primary connected. Reference 2 from 1936 describes a scheme where thyrites were installed across CT secondary terminals to prevent dangerously high voltages. Distribution reclosers occasionally have a 100-ohm resistor connected across the CT secondary terminals, in parallel with the protective relay burden, so that the CTs are not open-circuited when the control cable and relay burden are manually disconnected.

It is important to note that in the extreme saturation condition, such as that caused by an open-circuited CT or an infinite load impedance, the peaks that appear in the excitation voltage can be extremely large, even for relatively low ratio currents. From the excitation curve in Fig. 2, we can estimate the nonlinear inductive reactance ZE of the CT excitation or magnetization branch at various points (see Table 1). ES

IE

ZE

Point 1

205 V

0.02 A

10.25 kohms

Point 2

500 V

0.1 A

5 kohms

Point 3

530 V

4.0 A

132 ohms

TABLE 1: Excitation Branch Impedance Estimates At low excitation voltages and small load currents, the magnetizing branch impedance is very large (10.25 kohms). If the CT is open-circuited, all of the ratio current IP/n will flow through this extremely high impedance, develop an extremely high excitation voltage ES, and drive the CT deep into saturation. As the CT saturates, the magnetizing branch impedance approaches a short circuit (132 ohms) and the CT magnetizing current IE increases nonlinearly with voltage. A C400 2000:5 CT with 1,000 A primary current (2.5 A secondary) and an extremely high burden to replicate an open-circuited CT condition was simulated using Mathcad®. The nonlinearity of the magnetizing branch impedance versus time is displayed in Fig. 4. The flat spots (near short circuit) in the magnetizing branch inductive reactance occur during alternating half cycles of the CT saturation, when flux is relatively flat in Fig. 3a and b. During these times, flux is not changing, so the excitation voltage is near zero and the magnetizing current IE is large. The very large and thin spikes in the magnetizing branch inductive reactance occur during the transition times when flux is increasing or decreasing rapidly in Fig. 3a and b. During these periods, the reactance increases to very large values, which creates similarly shaped brief, but extremely high, voltage spikes.

Fig. 4: Magnetizing Inductive Reactance Versus Time Shorting terminal blocks and CT test switches allow technicians to short CTs while open-circuiting relay inputs for testing and troubleshooting. New test switch designs are completely finger-safe, with no exposed metal or blades. One utility in Oklahoma specifically mentions in their design standard several preferred wiring methods, including placing the crimp dimple of a ring lug on the back side of the lug barrel and placing the lug back side out so that the crimp can be visually inspected. These design and operating practices reveal the great care taken to avoid open-circuiting a CT.

IMPORTANCE OF STANDARDS AND TYPE TESTING IEEE and IEC environmental standards and type tests were developed to ensure that protective relays for critical infrastructure meet minimum design criteria. Examples include the IEEE C37.901989 and IEC 60255-5:1977 dielectric strength tests. When a fault occurs, ground potential rise may cause high voltages to develop at the end of CT cabling. Dielectric strength standards and tests are intended to ensure that a protective relay subjected to high fault-induced voltages and transients in wiring will not be damaged and will operate dependably, securely, and safely. The IEEE dielectric

54 strength test mandates that a relay between insulation and ground and between any two circuits shall withstand twice the rated voltage plus 1,000 Vrms, with a minimum of 1,500 Vrms. These severe testing requirements take into account the harsh environments typical of utility and industrial applications and the critical importance of reliable power systems 3. Note that open-circuited CTs also can produce extremely high voltages on CT cabling and all equipment connected to it, but dielectric withstand standards were not designed to protect against these circumstances. Said another way, no matter how well a relay is designed, if we put primary system voltage levels on the circuit board, we can expect the relay to fail at some point.

Protective Relay Vol 1 B (bottom of Fig. 6) claims a 2,000 Vdc withstand capability on contact inputs. Both claims exceed the IEEE standard. A dielectric test is quite simple to perform with the correct equipment. Fig. 7 is a screen capture from a video taken during dielectric strength, or HiPot, type testing of Relays A and B. However, few utilities and industrial consumers actually test relays today to prove the claims of manufacturers. It is recommended that they do, either directly or through a third-party validated test laboratory. Fig. 8 shows the dielectric breakdown of Relay B at 1,500 V.

Consider that the North American Northeast blackout of 2003 was aggravated by improper operator action because of a lack of up-to-date information from the supervisory control and data acquisition (SCADA) system. A remote terminal unit (RTU) had been installed with two redundant power supplies that both failed because of ground potential rise. Self-test monitoring did not alert the operator that the RTU had failed. Fail-safe design practices, such as reporting full-scale or zero values for all data fields during loss of communications or for watchdog timer failures, were not in place. Two power supplies, installed for redundancy, did not improve the availability of the system. The equipment was not substation-hardened, designed, and type-tested to meet IEEE C37.90. Further, no independent testing had been done to detect the product weakness 4. Many consumers and regional reliability entities mandate protective relays be designed and tested to meet these standards. In this way, standards and type tests provide a repeatable and objective way to validate equipment and compare the designs of different manufacturers 5. Fig. 5 shows circuit boards from the overcurrent relays of two different manufacturers. Relay A has 2 optoisolated inputs and 5 output contacts. Relay B has 15 inputs and 10 output contacts. Relay A sacrifices 13 inputs and 5 outputs in order to have increased component spacing and larger creepage distances.

Fig. 6: Manufacturer A and B Dielectric Specifications

Fig. 7: Dielectric Strength Type Testing

Fig. 5: Manufacturer A (Left) and B (Right) Circuit Boards Both of the relays in Fig. 5 include specifications in their instruction manuals. Both claim to exceed the 1,500 V minimum dielectric strength requirement. As shown in the top of Fig. 6, Relay A claims a 3,000 Vdc withstand capability on contact inputs. Relay

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The three phase currents are measured individually. The phases are then connected residually, and a separate neutral current input, called IN, on the relay measures the sum of the phase currents. The relay is capable of providing light-based arc-flash protection, although fiber-optic sensors have not yet been installed. A simplified protection connection diagram is shown in Fig. 10.

Fig. 8: Dielectric Breakdown of Relay B at 1,500 V Relay A withstands a continuous voltage of 4,000 V in this test. This speaks to the dielectric withstand capability of its design and its ability to operate reliably in the presence of ground potential rise and other fault-induced transients. However, any relay will eventually fail given a high enough voltage because relays are not designed to withstand primary- level voltages such as those developed by open-circuited CTs.

Important settings for the application are shown in Fig. 11. Only four elements are enabled to trip—the individual phase time-overcurrent elements and the separate neutral time-overcurrent element. Phase elements (51A, 51B, and 51C) have a 2,000 A primary pickup, while the neutral 51N has an 800 A primary pickup. The 51N element operates from measured 3I0—the physical sum of IA, IB, and IC. The relay also calculates the mathematical sum of the phase currents, called IG. The IG element is not enabled to trip in this application. Both IG and IN are available as analog channels in event reports.

CASE STUDY APPLICATION DETAILS The application under study in this paper is a microprocessor-based overcurrent relay installed in switchgear in an industrial plant (see Fig. 9). CTs from the main and bus tie breakers are paralleled and wired to the relay. One breaker is normally closed while the other breaker is normally open.

Fig. 10: Simplified Protection Connection Diagram

Fig. 11: Important Settings for This Application

Fig. 9: Switchgear Breaker, Relay, and Controls

A main-tie-main automatic transfer scheme is in place to transfer plant load to an alternate source within seconds of primary source loss. Local diesel generators provide emergency backup only. Plant loads are especially vulnerable to voltage sags and comply with CBEMA and SEMI F47 curves. Total plant load was greater than 18 MW and increasing at the time of the event.

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OPEN-CIRCUITED CT CAUSES OUTAGE The industrial plant experienced an outage caused by a trip of the overcurrent relay. The initial outage lasted at least 15 minutes due to the breakers being locked out and personnel trying to determine root cause, restart in an orderly manner, and not close back into a fault.

As the load was increased, the 51N element eventually picked up continuously and started timing to trip. Fig. 14 shows the element timing to trip.

There was no fault, but the root cause was not determined immediately. So the breaker was closed, only to trip again. This led to a near complete plant outage, some equipment failure, and some processes requiring weeks to restart. Industrial plant personnel requested assistance from the relay manufacturer to help determine root cause of the original trip. Event records were downloaded and analyzed. Fig. 12 shows one of the first records. The phase-to-phase voltages are balanced, the three phase currents are balanced, the calculated IG current is zero, but the measured IN current is about 800 A primary. The 51N element is shown picking up and dropping out.

Fig. 14: 51N1P Element Timing to Trip When 51N1P finally asserted continuously, IN was equal to 817 A primary, just above pickup. At this current level and with an IEEE very inverse curve and a time dial setting of 5, the 51N element would take over 7.5 minutes to trip (see Fig. 15). Load current continued to increase, however, and IN increased in magnitude to over 900 A primary at the time of the trip. This sped up the trip time.

Fig. 12: 51N1P Picking Up and Dropping Out Fig. 13 shows the phasors at Cycle 5.75. Note that IN is equal to the sum of IA and IB currents (or –IC).

Fig. 13: Phasors at Cycle 5.75 in Fig. 12 Event

Fig. 15: IEEE Very Inverse Curve

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Protective Relay Vol 1 At the time of the trip in Fig. 16, note that the phase-to- phase voltages are balanced, the three phase currents are balanced, the calculated IG current is zero, and the measured IN current is near 1,000 A primary. The balanced phase voltages and currents indicate that there was no fault at the time of the trip.

made good enough contact to carry current. All of the ring lug barrels had a wire label on them. The IC nonpolarity terminal appeared to be heat shrink-wrapped around the barrel of the lug, whereas all other labels were loosely wound around their lugs. It is suspected that heat generated by load current through this loose connection heat shrink-wrapped the label tightly around the barrel. After about one year of service in this condition, and two weeks prior to the misoperation, a metallic EIA-232 serial cable was connected between the relay and an automation controller to enable SCADA control and communication. It is suspected that this data cable was touching the C-phase current wire and put enough pressure on it to cause the wire to push free of the ring lug barrel and the shrink-wrapped label (see Fig. 18).

Fig. 16: 51N1T Trip There are two questions to be answered concerning the trip event. First, why was the relay measuring IN neutral current while the three phase currents were balanced? Because the 51N element caused the trip, this question understandably became the first priority and focus of the initial investigation. Second, how can IG be zero while IN is large? This question only was asked and noticed later in the investigation.

Once the wire slipped and fell free of the barrel, an open circuit in the C-phase circuit (downstream of the IC nonpolarity terminal and before the neutral bus) was created. This explains why IN equaled the sum of IA and IB currents (or –IC). About 2.5 A secondary current was flowing through each phase at the time. Fig. 18 is a photograph of the open-circuited CT wire after the misoperation.

Event records confirm that the breaker was closed before the theory of an IN wiring problem was developed and resolved (Fig. 17). IN measuring significant current when no fault existed on the system led investigators later to suspect a wiring problem. As is the case too many times, operators were urgently trying to restore power to critical loads, and in their haste, the breaker was closed before root cause was known. After the breaker was closed, significant IN current was still present while phase currents were balanced. This led to a subsequent relay trip. Fig. 18: Photograph of the Open-Circuited CT Circuit The wire labels installed over the barrel of the ring lugs likely made visual detection of the original problem (no crimp) difficult. Subsequent relay testing, commissioning tests, and normal metering did not expose the problem because the stripped wire made decent enough electrical contact. Nonetheless, these tests should be performed because they do catch the majority of wiring problems.

Fig. 17: Breaker Is Closed Without Root Cause Known After several days of investigation, the source of the IN current was discovered. A ring lug on the nonpolarity or neutral terminal of IC on the relay had not been crimped during the initial switchgear installation. For almost one year, the stripped wire end had

The Oklahoma utility mentioned previously uses only uninsulated ring lugs and dictates that the barrel be installed to the outside and that wire and terminal labels be on the wire (versus covering the barrel) to make visual inspections easier and more effective. Fig. 19 shows the actual ring lug next to an example crimped lug. Beyond these wiring standards and visual inspections, physically tugging on each wire to ensure the crimp is secure is recommended as part of future commissioning checklists.

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Protective Relay Vol 1 Recall from the review of CT concepts that an open-circuited CT can develop dangerously high voltages. At the time of the relay trip, the C-phase CT was carrying nearly 1,000 A primary, or 2.5 A secondary, current. When the C-phase neutral connection became open-circuited, the only load or path for the CT secondary current to flow through was the very high magnetizing branch impedance (Table I, Point 1). This would have developed a very high voltage spike, driving the CT deep into saturation and decreasing the magnetizing impedance. During the next half cycle, this process would start all over again.

Fig. 19: Photograph of the Actual Ring Lug (Left) and Example Crimped Lug (Right) Once the open circuit was discovered, the ring lug was crimped correctly, the wire was reinstalled, and the breaker was closed. Fig. 20 shows an event report that was triggered 11 days after the initial trip. The voltages and three-phase currents are balanced, and IG and IN are both near zero. Now that everything appeared normal, some assumed that the work was over and that the problem had been solved. The breaker and relay remained in service for over two weeks.

Fig. 20: Event Triggered After Crimp Fixed

OPEN-CIRCUITED CT CAUSES RELAY DAMAGE The second question from the event analysis remained unnoticed and unanswered at the time that the crimp was fixed and the breaker was closed again. Only during later investigation did engineers focus on how IG could be zero while IN was so large during the events that showed the relay trip (Fig. 12, Fig. 13, Fig. 14, Fig. 16, and Fig. 17). After all, IG is equal to the mathematical sum of the three phase currents, while IN is equal to the physical summation. More to the point, how could the relay measure C-phase current when a physical open or break in its circuit was visible (Fig. 18)? Further, once the open circuit was fixed and restored to service, how was the relay measuring normal and expected values for IG and IN (as in Fig. 20)?

A theory was developed that would explain why the relay measured C-phase current while simultaneously having an open C-phase circuit external to the relay (see Fig. 21). The dangerously high voltages must have exceeded the dielectric strength of the relay, damaged the relay, and created a short circuit. In order for the relay to measure C-phase current, the short circuit to ground must have developed internal to the relay, downstream of the C-phase current-sensing element but upstream of the open circuit at the relay terminal block.

Fig. 21: Theory of Why IG and IN Did Not Match To prove this theory in the laboratory, the relay manufacturer conducted a dielectric strength test on a circuit board from a like make and model relay. A video recording was made of this test. The relay specifications state that its analog inputs will withstand up to 2,500 Vac. This exceeds the IEEE standard minimum by 1,000 V. Voltage was applied between the polarity of IC (terminal Z05) and the relay ground. At approximately 3.4 kV, the relay failed the dielectric test. The test was repeated, and in the second test, we can observe a visible flash (see Fig. 22). No permanent damage was observed on the relay under test, primarily because the dielectric test equipment automatically shuts down the high voltage for safety when measured leakage current exceeds a threshold of about 300 mA.

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With a theory and a dielectric test on a like make and model relay in hand, the industrial plant was advised that they had a damaged relay in service that needed to be removed from service and repaired immediately. After switching loads to an alternate source, the breaker and relay were removed from service for thorough inspection. Fig. 25 shows a photograph of the relay involved in this event with its rear panel removed. Compare Fig. 24 and Fig. 25. The CT terminals are visible, as are the internal instrument transformers themselves. The internal magnetics are mounted to the top of a circuit board identical to that in the video shown in Fig. 22.

Fig. 22: Video From Dielectric Strength Test The relay current terminals are shown in more detail in the next few figures. Fig. 23 is a profile view of the relay hardware. The bottom terminal block is for the current connections. The diagram or sticker on the side of the relay simply explains the connections and terminal numbering. Terminal Z05 is C-phase polarity. Terminal Z06 is C-phase nonpolarity. Recall in this application that Z06 is the terminal that was open-circuited.

Fig. 24: Rear-Panel Layout of Relay Hardware

Fig. 23: Profile of Relay Hardware Fig. 24 is a view of the relay rear-panel layout. The CT connections are made to the Z terminal block on the bottom. Terminal Z05 is the fourth screw from the right, and terminal Z06 is the third screw from the right.

Fig. 25: Relay Rear Panel Removed to Expose Inside

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When the CT board was removed from the relay, the first obvious sign of damage was the heat and arcing evidence on the bottom inside of the relay chassis, directly under the CT board (see Fig. 26).

deed develop dangerously high voltage spikes, and these caused a dielectric breakdown, damage, and a short circuit to ground inside the relay. Once established, this short circuit to ground provided the path for current to flow through the C-phase-measuring element within the relay to ground, while external to the relay, the neutral element only saw the sum of IA and IB currents.

Fig. 26: With CT Board Removed, Heat and Arc Damage Evident Once the CT board was out of the relay, the circuit board damage and arc-induced short circuit were clearly visible (see Fig. 27). The circuit board on the left in Fig. 27 is the damaged board. On the right is the sample board used in the laboratory test and video.

Fig. 27: Damaged Relay Board (Left) and Board From Dielectric Strength Test Video (Right) Fig. 28 is a close-up view of the damaged board. The relay transformers are mounted on the opposite side of the board. The red highlighted area, where the worst damage is, shows three throughhole pins that connect the nonpolarity Z06 terminal side of IC. The arc-induced weld from the third pin connects to a slightly lighter shade of green vertical area, which is a copper ground or reference plane in the printed circuit board. The open-circuited CT did in-

Fig. 28: Closer View of Damaged Board and Arc-Induced Weld Between Z06 and Ground The impedance from Z06 to ground was measured at 16.8 ohms. This represents the impedance of the arc-induced weld on the circuit board (see Fig. 29).

Fig. 29: Impedance Between Z06 and Ground On all of the other current channels, this should and did measure as an open circuit (infinite ohms). This explains why the relay, when returned to service as shown in Fig. 20, appeared normal. The external CT path wiring had a much lower impedance than the arc-induced weld to ground, so most of the current flowed through IC and on to the neutral bus.

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Protective Relay Vol 1 CONCLUSION Standards provide best known methods and minimum acceptable requirements. It is recommended that users verify the claims and specifications of manufacturers. Robust designs ensure that critical protection systems will operate reliably even when exposed to fault-induced transients. Standards, however, are not enough to make any design bulletproof. Even relays designed and tested to greatly exceed IEEE and IEC dielectric standards will fail at some point if subjected to primary-level voltages. Open-circuited CTs can create dangerously high voltage spikes. Great care must be taken in design, commissioning tests, and operation to ensure that CTs carrying load current are not open-circuited. In this case study, a CT wire was not properly crimped and was in operation for about a year with no noticeable effects. The addition of a communications cable added just enough pressure to the CT wire to cause it to fall free of the ring lug barrel and open-circuit the CT. A neutral overcurrent element tripped an industrial plant offline. The open-circuited CT and the resulting high voltage damaged the protective relay. This was not noticed due to haste during the emergency or simply missed because of lack of experience. Because of this, a damaged relay was put back in service, unknowingly putting the plant at risk again. Fortunately, the problem was discovered eventually and corrected before any further problems were experienced. The damaged relay was discovered through event report analysis and observing a strange anomaly—calculated 3I0 and measured neutral currents not matching. There is a key lesson to be learned—root cause analysis is not complete until every question has been answered thoroughly. There are literally thousands of wires and terminations in substation control buildings and switchgear lineups. This case study is a vivid reminder that just one wire terminated improperly can damage equipment, cause dangerous working conditions for personnel, and cause power outages. That is a slim margin of error and should reinforce the criticality of proper design, peer review, commissioning tests, and more. It is recommended that commissioning procedures include visual inspection of, and physically tugging on, each crimp connection.

COMMENTARY The following quote seems particularly relevant with respect to this case study. In the Summer 2007 Issue of PAC World Magazine, the late Walt Elmore, an icon in our industry, was quoted as follows: PAC WORLD: What advice would you give to the … engineers in our field? WALT ELMORE: Find out why! To accept something the way it’s always been done is not acceptable. There is too much of that— accepting things the way they are. Not delving into it. I don’t know whether it’s a matter of availability of time or

what. People just don’t seem willing to devote the effort and time to look into things anymore. That’s a fact!! I think it would be good if, when you reach a little stumbling block, that you really got into it to find out why you’re about to do something, particularly in relaying.

ACKNOWLEDGMENT The author expresses his deep appreciation to engineers Tony Lee and Raymond Sanchez for their assistance with root cause analysis and the writing of this paper.

REFERENCES S. E. Zocholl, Analyzing and Applying Current Transformers. Schweitzer Engineering Laboratories, Inc., Pullman, WA, 2004. 1

G. Camilli and L. V. Bewley, “Surge Protectors for Current Transformers,” Transactions of the American Institute of Electrical Engineers, Volume 55, Issue 3, March 1936, pp. 254–260. 2

IEEE Standard C37.90-1989, IEEE Standard for Relays and Relay Systems Associated With Electric Power Apparatus. 3

E. O. Schweitzer, III, D. Whitehead, H. J. Altuve Ferrer, D. A. Tziouvaras, D. A. Costello, and D. Sánchez Escobedo, “Line Protection: Redundancy, Reliability, and Affordability,” Proceedings of the 64th Annual Conference for Protective Relay Engineers, College Station, TX, April 2011. 4

S. Muller-Cachia, A. Akhtar, and S. Hodder, “Utility Perspective on Environmental Type Testing Requirements for Modern Digital Protective Relays,” Proceedings of the 40th Annual Western Protective Relay Conference, Spokane, WA, October 2013. 5

David Costello graduated from Texas A&M University in 1991 with a B.S. in Electrical Engineering. He worked as a system protection engineer at Central Power and Light and Central and Southwest Services in Texas and Oklahoma and served on the System Protection Task Force for ERCOT. In 1996, David joined Schweitzer Engineering Laboratories, Inc. as a field application engineer and later served as a regional service manager and senior application engineer. He presently holds the title of technical support director and works in Fair Oaks Ranch, Texas. David has authored more than 30 technical papers and 25 application guides and was honored to receive the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference. He is a senior member of IEEE, a registered professional engineer in Texas, and a member of the planning committees for the Conference for Protective Relay Engineers at Texas A&M University, the Modern Solutions Power Systems Conference, and the I-44 Relay Conference.

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UNDERSTANDING AND TESTING MOTOR OVERLOAD PROTECTION AND THERMAL MODELS PowerTest 2016 Nestor Casilla, PE, Doble Engineering Company

ABSTRACT Motors are a large investment and are a crucial part of many power systems, especially in industry applications. Modern motor protection is no longer overcurrent relays. Today, the numeric relay uses a model of the motor heating and cooling, a thermal model, for overload protection. This paper presents the concepts of overload protection, and how to safeguard the motor investment through proper testing. Discussed are the following:

These older overload-protection methods did not track motor heating, so setting the overcurrent overload protection required choosing the best compromise. Some portion of the motor operation—starting or running—was under protected (or over protected) to get the desired overall protection response 2. Figure 1 shows the motor protection response for overload in the running state at greater than full rated service, which is IFLA (current, full load amps) times SF (service factor).

●● Understand the thermal model and why it has special testing requirements ●● Understand negative-sequence and unbalance effects (voltage and current) on motor ●● Confirm the starting and running thermal models (test in the right current multiples) ●● Test motor-protection installations faster (save money and reduce frustration) ●● Ensure that the motor thermal-overload protection works as expected.

TEST MOTOR PROTECTION—PROTECT ASSETS; IMPROVE PRODUCTIVITY The reason to test motor protection is to assure that induction and synchronous motors can provide long and effective service. Motors are a large investment by cost, and with respect to the processes that the motors control. To test motor protection well requires an understanding of the principals of motor protection. These principals include the historical overload method (51 overcurrent protection), and the modern thermal-model method, 49T 1.

UNDERSTANDING OVERLOAD PROTECTION Overheating causes motors to fail. The goal of motor overload protection is preventing motor overheating while working the motor to its fullest capacity. Numeric (microprocessor) relays brought a new method to motor overload protection—the thermal overload model. Historically, before the introduction of microprocessor-based protection, there had been two overload-protection methods: sensing an overcurrent condition with electromechanical relays, and heating bi-metallic strips through which ran the motor current.

Fig.1: Thermal model (49) tracks motor overload better than overcurrent (51) element This compromise led to wasted motor efficiency (less product produced) and diminished motor life from overheated motors (non-optimized use of business capital). The thermal overload model in the microprocessor protective relay tracks motor heating—it makes a mathematical model of the heat in the motor at any operational point. The overcurrent method of overload protection is either too much or too little. A motor, for all of its intricate rotor construction and stator windings, is really one large thermal mass—a mass of iron. If the mass that supports the rotor bars (or windings) gets too hot, then there is damage. For example, rotor bars become distorted and fly apart, damaging both the rotor and the stator wiring within which it is in close proximity. 3 Motor heating is like applying a blowtorch to a large iron mass. Measure the temperature rise by holding a thermometer against the block of iron far from the spot that the blowtorch is heating. Observe the thermometer and note that the block does not heat instantly to the temperature at the tip of the blowtorch. It takes

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Protective Relay Vol 1 time for the temperature to build—first slowly and then faster over time. In fact, we observe an exponential rise in the thermometer temperature readings as time progresses. (Similarly, when we remove the blowtorch from the iron mass, the decline in temperature is exponential—it remains hot initially, and diminishes in temperature more rapidly with time.) The modern thermal overload protection in a microprocessor relay models this exponential rise and exponential fall in motor temperature. When a heavy motor load is applied, the motor heats exponentially, not linearly. Contrast the exponential thermal overload model with the historical overcurrent method. When applying load to the motor, overcurrent-based protection tracks the increased load in a linear response. For a given application of motor load, the older overcurrent overload method overtrips, as shown in Figure 2 2.

(1) Note that the response is exponential, as seen in the natural logarithmic function ln (). Consult manufacturers’ literature to perform the calculations to determine the correct thermal trip time to measure. Spreadsheets are available from manufacturers to perform the calculations. When using a spreadsheet pay close attention to the type of thermal-protection method for which the relay is set.

Model based upon sequence components and heating Another major motor thermal model uses negative- and positivesequence currents. While running, the rotor rotates in the direction of the positive-sequence current I1. For an induction motor (and for synchronous motors in the starting state) there is slip—the motor runs at less than synchronous speed. Running with slip produces a negative-sequence current I2 with a phase rotation opposite to the positive-sequence current. This additional current is opposite to the rotor rotation and induces a substantial rotor current at approximately 120 Hz (in a 60-Hz system). Fig. 2: Thermal model (49) tracks motor heat; overcurrent (51) overtrips For a collection of load points the old overcurrent method cannot track actual motor heating—either we “leave money on the table” by not using the motor to full capacity, or we drive the motor into premature failure with too much load. Figure 1 shows a comparison of load tracking from both the modern thermal model and the older overcurrent overload protection methods.

This double-frequency, negative-sequence current flows on the surface of the rotor bars through a larger rotor resistance (from the double frequency), and therefore causes an increase in rotor heating. Figure 3 illustrates the phenomenon 5.

CREATING A THERMAL-MODEL TEST Thermal-model calculations vary among the protective-relay manufacturers. Some use a heating/cooling time-constants model, and some use positive- and negative-sequence currents and motor slip.

Heating/cooling time-constant model One thermal model uses thermal data from the motor manufacturer to determine the overload protection. An example is a stator thermal model (1) that calculates the trip time Tp, based upon the locked-rotor (hot) time T0, applied current ITM, locked rotor current ILR, and service factor SF. 4

Fig. 3: Negative-sequence currents flow on rotor, create heat

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This thermal model uses an equivalent current Ieq, from I2 negative-sequence current and I1 positive-sequnce current:

is high (30°C—40°C) and when the cooling ducting is blocked. If left on while testing, RTD bias can affect testing results. Figure 4 shows a typical RTD bias curve 6.

(2) See manufacturer’s literature for details 6.

Current unbalance biasing Unbalanced phase currents occur in normal motor operation. Unbalanced currents cause additional rotor heating. Some microprocessor-based relays account for this source of rotor heating. Current unbalances come from voltage unbalance—loose connections, varying feeder lengths, poorly distributed single-phase loads within the power system, and aging infrastructure. Because a running motor is a constant-kVA device, a small voltage unbalance generates a large current unbalance. NEMA (National Electrical Manufacturers Association) recommends derating based upon voltage unbalance [NEMA MG1-2009 Motor Guide derating factor from voltage unbalance; 14.36, 20.24.2]. Some motor-protection relays use the negative-sequence current caused by source unbalance to bias the trip sooner. These relays use a ratio of negative- to positive-sequence current (I2/I1). The manufacturer’s documentation provides guidance when creating a test for a relay with unbalance-bias compensation—trip times require adjustment.

Fig. 4: RTD bias trips thermal model sooner

Motor-protection curves Most manufacturers have pre-calculated curves for thermal trip time. These curves are similar to overcurrent TCC (time-current characteristic) curves (see Figure 5).

●● Adjusting unbalance biasing per overload The biasing function applies directly for overload conditions greater than SF • FLA. The ratio of the absolute value of (I2/I1) reduces the trip time. ●● Adjusting unbalance biasing per load When running load conditions have unbalance at less than SF • FLA, the relay reduces the effect of the unbalance biasing to prevent nuisance tripping. This adjustment is because positive-sequence current is smaller at this load point while negative-sequence current remains constant. The derating formula is the following 6:





(2)

The first term is the absolute value of a phasor-division operation; Iaverage is simply magnitude averaging. Use this value to adjust the trip time measured when applying unbalanced currents at less than SF • FLA.

RTD Bias Some motor-protection relays offer the capability for ambient and embedded-stator RTDs (resistance temperature detectors) to modify the thermal model. RTD bias function decreases the tripping time when the ambient motor operating temperature

Fig. 5: Reading the trip time in pre-defined motor overload protection curves

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Protective Relay Vol 1 Select a multiple of current, marking this point on the horizontal axis (1), progress upward from this point to intersect the curve (2), and then proceed to the left to read the trip time on the vertical axis (3). Custom thermal-model protection is available for special situations such as a high-inertia-start ceiling fan and for other special motor-protection scenarios.

SPECIAL TESTING REQUIREMENTS

Emptying the thermal-capacity bucket When test current is applied to the relay the model thermal capacity increases and decreases, or resets, based on the calculated model time. Think of the motor thermal capacity as the water filling a bucket; see Figure 7. Motor load fills the bucket, representing thermal-capacity heating. Less load (and no load) empties the bucket. It takes time for the bucket to empty—emergency start turns over the bucket and empties it immediately.

Because the thermal model is exponential, with varying rates of change over time, testing methods are not the same as with simple overcurrent testing. Testing requires calculating and measuring: ●● Calculating the expected thermal-capacity-used value ●● Measuring the relay response at the time that the calculated TCU (thermal capacity used) value is achieved. Furthermore, testing must confirm correct operation of the specific thermal model, as shown in Figure 6.

Thermal capacity

Maximum start current

Current

Fig. 7: Filling/emptying the thermal-capacity bucket Transition current, I � 2.5 • FLA Full-load amps

Rotor model Stator model 2

4

6

8

10 12 14 16 18 20 22 24 26 Time, s

Fig. 6: Typical current profile for motor starting to running states Advanced motor-protection relays have a thermal model for rotor heating (during a start when the rotating magnetic field is pulling hard to get the rotor spinning at rated slip frequency), and a thermal model for stator heating/cooling during a sudden change in load after the successful start while in the running mode.

Switching motor states The motor-protection relay firmware determines the demarcation between motorstarting and motor-running states. Typically, the stator thermal model is active when current exceeds full rated service (SF • FLA) and is less than TM times FLA. Usually, the transition multiple TM is 2.0–3.0. The rotor thermal model is in effect between M times FLA and 10–12 times FLA 4.

Note that the thermal trip-time calculations apply to a cold start. To be accurate, the thermal capacity must be at 0 percent when beginning the test. If a test current is applied before the thermal capacity has reset completely, the thermal element will trip in less than the calculated time. Some thermal model reset times are very long—waiting during the model cooldown time could make a long day of testing. Fortunately, the thermal capacity can be reset manually by employing the emergency-start logic between tests. In an emergency start, both the stator and rotor thermal capacities reset to zero instantly, omitting the possibly long wait between successive tests.

PERFORMING A THERMAL-MODEL TEST Testing thermal model protection is similar to other protectiverelay testing: apply a test quantity and measure the relay reaction. In thermal-model testing, apply a test current in the appropriate range for the particular model under test (stator or rotor) and wait for the relay trip. The wait time can be long (measured in seconds and minutes), especially for the stator (running-state) thermal element. Consult the protective relay instruction manual to find the emergency (re)start or thermal reset function and use it between tests.

Recording long events Relay oscillography does not have sufficient length to record the beginning and end of a thermal-model test. Tools that help document the times are the relay sequence-of-events record, an external fault recorder/strip-chart recorder, and/or the test-set data recorder.

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Outputting circuit-breaker status

Maintaining maintenance data

Some protective relays require a closed circuit breaker before the thermal model is activated. Modern test sets (power-system simulators) output a user-programmed circuit-breaker status (52a or 52b) to a relay input via the test-set output contacts/FET (field-effect transistor) outputs. Figure 8 is an example of configuring the outputs for motor states.

Modern motor-protection relays log motor starting parameters and running events, storing these as a motor history. In addition, relays can “learn” and modify initial settings based upon operating conditions driven by voltage and current inputs.

Fig. 8: Outputting circuit-breaker status

Simulating a motor-start condition For some motor-protection relays, the current must transition from zero-to-high-to-low (medium percentage of FLA) to simulate a motor start. Additionally, you can produce motor states from a state simulation. A state-simulation test generates starting, running and stopped testing states (see Figure 9). Program relay outputs to transition the state simulation.

Testing the motor protection for an in-service motor can place bad data in the motor history. Consult the manufacturer’s literature to defeat/suspend recording learned parameters, statistical information, and event recording during testing. Some relays provide a “Test” input for this purpose or make one from available relay logic). It is good practice to download all motor reports before testing, and to reload these parameters when finished.

THERMAL-MODEL TEST EXAMPLES Two examples demonstrate the steps to take when testing the thermal-overload model. One is with balanced current (for relays that don’t employ unbalance biasing) and another example tests with unbalanced phase currents.

Balanced phase currents For this example, apply balanced, positive-sequence current to the relay at a multiple of FLA that represents a starting overload or a running overload. This example is for a starting-overload test (typically the trip time is less than 30 seconds). The rotor thermal model is in effect for this test, and the applied current should be greater than the transition multiple TM (see earlier section, "Switching motor states").

• Creating the test Before running the test perform the following steps: 1. Chose input current (for the model under test) 2. Calculate the expected result  hese steps could be performed before on-site testing by the T test designer.

• Running the test 3. Turn off RTD Bias setting (if present) 4. Download relay settings 5. Set output (if using external timekeeper) 6. R  un a metering test (to confirm that the test connections are correct) 7. Reset the thermal capacity (with emergency [re]start) 8. Start the test

• While running the test Fig. 9: Motor state simulation

Motor-protection relays give a running total of metered TCU% and a time-to-trip countdown. You can monitor these via communications and via front-panel metering. (For front-panel metering you must turn off all other tripping elements.)

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Protective Relay Vol 1 • Reading results View the results once the test has completed. Read the time and tolerance from the test-set timer. For test sets that record the analog outputs and trip-signal input, simply review the recording. Place cursors at the ends of graph and read the delta time, as in Figure 10.

Ic = 5 A � 112°

Ia = 3.9 A � 0°

Ib = 5 A � -112°

Fig. 11: Unbalanced test currents When the motor has an overload (exceeds SF • FLA) the relay uses this percentage value directly to bias trip time. When the average phase current is in the normal load area, less than SF • FLA, the relay reduces the effect of the unbalance value. Perform these additional steps when creating the test (it is best to do these in preparation, before on-site testing): 1. Select balanced test currents (load or overload). 2. Consult the manufacturer’s documentation or calculation spreadsheet to determine the balanced-currents (unbiased) trip time. Fig. 10: Long stator-model trip recording: 658.8s If equipped with a sequence-of-events recorder, the relay can track associated internal element changes. However, this does not give you accurate command-output data from the relay outputs (add time for mechanical relay movement).

Unbalanced phase currents Some motor-protection relays measure the ratio of negativesequence to positive-sequence current (I2/I1) to derate the thermal model tripping time; see earlier section, "Model based upon sequence components and heating." Figure 11 illustrates possible unbalanced test currents. In this situation A-phase is reduced; B- and C-phases rotate “in” towards A-phase.

3. Add unbalance to the initial test currents. Modern protectiontesting softwares have sequence-component calculator from which to model the specific unbalance currents.

CONCLUSIONS Preparation and understanding make seemingly difficult tasks easy. This is especially true when testing the motor thermal model. Manufacturers have different methods (and some have multiple methods)—it takes study time and effort to comprehend what is needed to run the tests. Modern thermal model methods employ an exponential heating/cooling model, or a model based upon heating from sequence currents and slip. In testing thermal models it is important to be prepared before testing on site—review the manufacturer’s documentation thoroughly. When testing, avoid long reset wait times by using the emergency (re)start function. If you have odd results, make sure that the biasing functions are off, or that you have accounted for model bias in the total trip time. Above all, realize that there is nothing magical or extraordinary about modern thermal-model motor protection. Proper testing and understanding your methods and results safeguard the motor-asset investment.

68 REFERENCES C37.2, Standard Electrical Power System Device Function Numbers, Acronyms and Contact Designations, IEEE, 2008 1

D. L. Ransom and R. Hamilton, “Extending motor life with up dated thermal model overload protection,” in Petroleum and Chemical Industry Technical Conference (PCIC), 2012 Record of Conference Papers Industry Applications Society 59th Annual IEEE, vol., no., pp.1–7, 24–26 Sept. 2012, doi: 10.1109/ PCICON.2012.6549679,URL: http://ieeexplore.ieee.org/stamp/ stamp.jsp?tp=&arnumber=6549679&isnumber=6549637 2

Recent Problems Experienced With Motor And Generator Windings, G.C. Stone, M. Sasic, D. Dunn, I. Culbert, IEEE PCIC-2009-6 3

Mozina, C.J., “Upgrading the protection of industrial-sized generators using digital technology,” in Industry Applications, IEEE Transactions, No. 4, Vol. 33 (Jul/Aug 1997): 1117-1123 4

Alexander, G., and Patel, S., “Testing the Thermal Model in the SEL-710 Motor Protection Relay,” Schweitzer Engineering Laboratories, Inc., AG2011-12 5

GE Digital Energy, “469 Motor Management Relay,” GEK-106474P, GE Multilin Inc., 2013 6

Nestor Casilla has 30 years of diverse background in power engineering, including 17 years within the power generation, transmission, and distribution system of oil companies in Venezuela and 13 years as a Consultant Engineer working as Protection Application Engineer and doing protection coordination studies. As a Principal Protection Applications Engineer with Doble Engineering Company, he provides technical support for clients in the US, Canada, and Latin America, training an average of 150 technicians and engineers per year in the application of the Doble Power System Simulation F6150, evaluating different protection schemes, and protection schemes based on IEC 61850. He has participated as a speaker at technical conferences of CIGRE, IEEE, NETA, and Doble Engineering, as well as utilities’ technical conferences in the USA, Mexico, Colombia, Chile, Peru, Brazil, Puerto Rico, India, Canada, and Venezuela.

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APPLICATION OF A MULTIFUNCTIONAL DISTANCE PROTECTIVE IED IN A 15KV DISTRIBUTION NETWORK NETA World, Fall 2013 Issue Jack Chang (ABB, Inc.), Lorne Gara (Orbis Engineering), Yordan Kyosev (EPCOR) and Peter Fong (Sequence Instruments, Inc.)

BACKGROUND EPCOR Utilities Inc. is the electric utility company in Edmonton, Alberta, Canada. One of EPCOR’s capital upgrade projects is to replace obsolete protective relays for their 15kV distribution substations. Eight of EPCOR’s 15kV distribution substations have obsolete feeder relays that are starting to fail and raise concerns for system reliability and safety. The distribution feeders for these substations consist of a combination of cables and aerial lines. The existing relays protecting these feeders are equipped with overcurrent and reclosing elements. As there are many functions and options available in modern microprocessor based relays, EPCOR decided to include distance and overcurrent protection for the new relays. Distance protection is primarily utilized for transmission lines, but can be applied to distribution networks with many benefits. The new relays will provide the protection as well as the event information to SCADA and the engineering department. The concern in this new application is the accuracy of the cable/line impedance data needed for relay setting calculation. As EPCOR has the test equipment available to measure these impedances, the decision was made to measure the cable section of the distribution network that are easily isolated for the tests.

ENGINEERING CONSIDERATIONS AND IMPLEMENTATION EPCOR’s Woodcroft substation is one of the many 15kV distribution substations connected to the Utility’s 72kV sub-transmission network. The 15kV bus, feeding 18 aerial feeders, is sourced by three 30MVA two-winding transformers. A typical feeder, supplying various residential and industrial loads, consists of a short underground cable section up to a lateral take-off structure before joined by multiple sections of over-head conductors. There are usually several overhead line sections with transformer taps typically connected to the first over-head section and other line branches connected to the remaining sections. The transformer taps are protected by a combination of current limiting and expulsion fuses while the line branches are protected by expulsion fuses only.

EXISTING OVER-CURRENT PROTECTION SCHEME DEFICIENCIES EPCOR’s distribution system adopts the “fuse-burning” philosophy whenever possible so protection coordination is mandatory to allow downstream fuses to burn first before disrupting other upstream customers unnecessarily.

Fig. 1: Simplified Single Line Diagram of Feeder W1

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Fig. 2: Existing OC Protection Time Coordination Curve Auto-reclosing on an underground cable is not a desired practice as these faults are permanent in nature and reenergizing the fault during reclosing could cause serious damages to the cable and unnecessary through faults for the transformer. EPCOR policy dictates setting up a high-set instantaneous OC element (50) whenever possible to detect high fault current on the cable and block auto-reclosing when the element operates. However, for a cable that is too short (subject to short circuit study), the 50 element cannot effectively protect the cable with sufficient sensitivity and fault coverage. Consequently, the time-delayed 51 element must clear the faults in the cable, but allow auto-reclosing to follow. This unfavorable operating condition warrants a more selective and reliable means to detect cable faults and block all auto-reclosing on the cable.

DISTANCE ELEMENT SETTING GUIDELINES

The high short circuit level combining with the delay could shorten the life span of the supplying power transformers and cause damages in the cable that are otherwise avoidable.

Zone 1 coverage is generally constant such that it is not under the influence of varying source impedance. This is an improvement over the existing OC scheme (50/51) by assuring constant protection sensitivity, high speed operation, and reliable blocking of auto-reclosing on the cable to prevent further damages.

One safety concern throughout power distribution utilities in North America has always been the sensitive and timely detection of fallen conductor on high resistive surfaces (eg. concrete, ice). Due to the high-resistive nature of current distribution in combination with a high pickup set point for the 51G element, a fallen conductor is likely left undetected by the overcurrent detection method. Modern numerical IEDs now employ special algorithms to detect broken conductor conditions and can generate alarms to control center for prompt remedial actions.

Multiple zones of quadrilateral phase and ground element are configured depending on the number of feeder sections and the physical length of each section. In general, each distance zone is set up to protect up to the end of each section with security margin, but a protection zone will not be implemented if a given line section is too short.

Zone 1:

Zone 1 of the distance element is set up to provide high speed protection to the express cable section and at the same time, block auto-reclosing. To improve relay setting and measurement accuracy, the cable impedance and ground compensation factor (Kn) were measured using primary injection technique (see section on cable testing).

Zone 2:

Zone 2 of the distance element is set up to detect faults up to the first branch fuse (FDS 697) in Figure 1. Coordination with pad mounted transformer tapped off this line section is not of major concern because of the high speed nature of the current limiting fuses for close-in faults on the tap. Downstream faults are not visible to the distance relay due to the large transformer impedance. The fault coverage of

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Protective Relay Vol 1 the zone is consequently set to the length of the cable and 90% of First Line section to avoid reaching into the first branch fuse. Zone 2 operation is delayed for 33 milliseconds for added security margin and to avoid racing Zone 1 when initiating auto-reclosing.

Zone 3:

Zone 3 distance element is set up to cover all preceding cable and line sections plus 90% of Second Line while coordinating with branch fuse FDS697. Because Zone 3 reaches into at least one fused branch, it is the Utility’s intention to ensure coordination by blocking its operation whenever the time OC (51) elements pick up. For high resistance fault types not detected by OC elements, Zone 3 may provide a more sensitive coverage. The resistive reach settings of Zone 1 to 3 have been approximated to 4 times of corresponding reactive reach settings as rules of thumb. Phase and ground resistive reach settings are set equally for convenience.

In the future the OC elements will act as backup protections to distance Zone 1 and 2 and block time-delayed distance elements (Zones 3 and 4) when picked up to ensure coordination with branch fuses when the fault current is high. When the fault current is too low for the OC element to detect, the time-delayed distance elements will operate.

BENEFITS OF APPLYING MODERN NUMERICAL MULTIFUNCTIONAL IED As alluded to in the previous subsections, the benefits attained by applying the multifunctional numerical distance IED can be summarized below:

Time saving on cable and downstream faults: Due to the relatively constant fault coverage of distance measurement, instantaneous operations can be assured for Zone 1 on the express cable section and most of Zone 2 without sacrificing speed to downstream coordination requirements. The reduction in fault clearing time improves personnel safety and prevents damages to critical equipment. The application of Zones 3 and 4 will provide the sensitive fault detection required for high resistance faults.

Auto-reclose blocking:

Fig. 3: Zone 3 Time Coordination Technique

Zone 4:

Zone 4 distance element is set to cover the entire feeder length. The reactive reach of Zone 4 is set up to detect faults down to the end of the feeder sections (Figure 1). The operation and coordination guideline to the highest rated branch fuse is similar to that of Zone 3 mentioned previously. The expected maximum feeder load is around 600 A at 15 kV, corresponding to approximately 14 ohm with 10% voltage margin. EPCOR decides to set the ground resistive reach to 30 ohm per fault loop and for setting convenience, the phase resistive reach is set initially to match the ground setting.

OVER-CURRENT FUNCTIONS EPCOR applies stage 1 and stage 2 of the four-stage OC function in the selected IED to mimic the existing timed and instantaneous OC functions (DPU curve in Figure 2). The time OC curve type is modified to “ANSI extremely inverse” to attain a faster operation as shown in Figure 2 curve 11F-D-80. At this moment both OC functions and the Zone 1 distance element are enabled to trip the circuit breakers.

Zone 1 distance element can be set up to reliably block auto-closing on the express cable section to prevent damages and costly repair. The fast operate time and reclose blocking will also reduce the through fault currents for the transformers and extend transformer life. On the contrary the existing high-set OC scheme has not been an effective method to block auto-reclosing due to its varying sensitivity and other application constraints.

Sensitive detection of broken conductor or high impedance faults: The selected multifunctional distance IED employs a proven broken conductor algorithm operating on the basis of detecting the asymmetry between the three phases. The function continuously measures the three phase current and compares the difference between the highest and the lowest phase current against a set point. This function is implemented to alarm for broken conductor conditions. The high resistive reach of Zone 4 also aids the detection of conductor fallen on high resistive surfaces that cannot be picked up by the broken conductor function or other current based detection methods. An undetected fallen conductor poses serious health and safety hazards to civilians and threats to the Utility’s reputation.

Hot-line Applications: Modern numerical IEDs offer multiple setting groups and programmable logic capability to dynamically switch setting groups following different system conditions. During energized line work, a different set point can be switched to speed up protection operation to prevent arc flash hazard and improve personnel safety. In this project, the hot-line control from local (mechanical switch)

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and remote (SCADA via RTU) locations are used to turn on/off a dedicated instantaneous OC element for high speed operation on faults and block/unblock auto-reclosing. The pickup setting of the instantaneous element is sensitized to match the pickup of the phase time OC element (120% emergency load) during hotline work.

Other Ancillary Functions Modern numerical IEDs offer many ancillary supporting functions such as apparatus control, multi-position selector switches, programmable push buttons, LED annunciation, SCADA communication and event and disturbance handling functionality, to just name a few. The following ancillary functions are used in the selected IED: ●● Switch-Onto-Fault (SOTF): ●● Local Annunciation: ●● SCADA Functionality:

CABLE IMPEDANCE TESTING Distance relays uses positive and negative sequence impedance (Z1 and Z0) of the line as a reference for the zone settings. Typically, these impedance values are calculated using various line parameters provided by the cable manufacturer. Furthermore, the calculation of Z0 requires the soil resistivity of the ground return path. A Zone 1 setting of 80% of the line impedance allows for inaccuracies of these impedance calculations. Comparison studies by various utilities 4 suggest that in most cases, the calculated Z1 is less than 20% of the measured Z1 value. However, due to the complexity in getting an accurate model for ground returns, the calculated Z0 normally has higher errors, sometimes higher than the 20% margin offered by Zone 1.

Fig. 4: Line Impedance Measurement Setup As the test equipment provides only a single-phase source, in order to calculate Z1, the three line-to-line fault loops must be tested (i.e. A-B, B-C, C-A) in order to obtain ZAB, ZBC, and ZCA. Z1 is then derived from the following formula: Z1 = ½ * (ZAB + ZBC + ZCA)/3 The factor of ½ is due to the fact that for line-to-line measurement we are actually measuring twice the line length. For Z0, the three-phases must be shorted and then measured against the ground return as shown in Figure 5. The measured impedance Z0´ is (ZA//ZB//ZC + 3ZE), and by definition: Z0 = [(ZA + ZE) + (ZB + ZE) + (ZC + ZE)]/3 = (ZA + ZB + ZC)/3 + ZE Therefore, Z0 = 3*Z0´ (three times the measured impedance)

In order to achieve the 90% setting of Zone 1 for this project, an accurate measurement of Z1 and Z0 of the cables using primary injection is required. The measurement method used is a frequency shift method in which the impedance is measured at 40 Hz and 80 Hz and then the 60 Hz result is obtained through a linear interpolation of these two values. This method ensures that any 60Hz noise be rejected by the measurement. In performing the test, one end of the cable must be shorted to ground, and the other end opened for connection to the test source. As a safety precaution, an isolation transformer is used for both the output and the measuring inputs of the test set, so that there is no direct connection between the cable under test and the test equipment. Figure 4 shows a simplified connection diagram of the test setup.

Fig. 5: Z0 Impedance Model With the measured Z1 and Z0, the relay zone settings and also the ground compensation factor (k0) could then be set very accurately for this project. Different relay manufacturers represent the k0 setting in a slightly different way. The typical formula for the k0 factor is: k0 = (Z0-Z1)/(3Z1)

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Protective Relay Vol 1 IED FUNCTIONAL TESTING The initial product evaluation, preliminary relay testing, and the commissioning of the installed protection was performed using modern relay test equipment and software. Network simulation software was utilized in order to simulate actual fault values based on system models and the measured line impedances. The IEC61850 SCADA points were tested using both the communication gateway device and the relay test equipment. The network simulator software allows the IED to be tested using calculated fault values based on system impedances as well as the measured line impedances. The transient voltages and currents are calculated from a digital network model (Figures 6 and 7). This provides the optimum approximation of the real events in the system to evaluate relay settings for complex protection applications.

Fig. 8: Sample Relay Operation Test The advanced relay test modules were used to verify the parameter settings and characteristics of distance (Figure 9) and OC (Figure 10) elements.

Fig. 6: System Modeling with Network Simulator Software Fig. 9: Sample Distance Characteristics Test Result

Fig. 7: Result of Network Simulation Testing The network simulator software was used to simulate faults at different locations along the entire feeder. For each feeder we carried out multiple tests to simulate faults along the entire feeder. As the feeders in Woodcroft are radial, the source 2 impedance was set to maximum and source 1 impedance was set to the substation calculated values acquired from the engineering short-circuit study. The results of each test (Figure 8) were analyzed to verify the IED indications, annunciation, operation, and timing. The IED operation was tested to verify accurate distance and OC characteristic, fault location algorithm, and trip/reclose functionality. The IED event records were analyzed and compared with the test equipment waveforms.

Fig. 10: Sample OC Characteristics Test Result Further functional tests to verify vendor pre-built logics such as broken conductor and switch-on-to-fault were performed. User customized configurations including blocking, various tripping logics, reclose initiation/blocking logics, Hot-Line operation, and various alarms were all tested in details. Final commissioning consists of wiring checks, cursory functional tests of all relay elements on-site, functional testing of all control and annunciation including its communication to the station HMI, and energizing check.

74 CONCLUSION At the moment of writing this paper, all 16 distance IEDs procured for this project have been commissioned and put in service. Zones 2, 3 (if applicable) and 4 are not currently enabled as tripping zones, but their behaviors under real-life system operating conditions are being closely monitored. The dedicated communication gateway for engineering analysis has not been installed at this point, but any pickup signals can still be recorded and waveform captured locally in the IED buffer so that the distance reach settings can be fine-tuned to ensure service reliability. The successful completion of this project was contributed by the joint efforts of the IED manufacturer for their product knowledge and technical support, the IED setting calculation, configuration and simulation work attributed to the EPCOR team and the Test set vendor’s solution and support in accurate cable impedance testing. The application of a modern multi-functional distance IED improves operating time and personnel safety working near various sections of the distribution feeders, reliably senses close-in cable faults and blocks auto-reclosing, dynamically controls hot line protection mode and provides sensitive protection to high resistive ground faults and alarms for circuit troubles with low current. IEC-61850 communication protocol is used for GOOSE messaging and status and analog measurement reports. Other annunciation and event/disturbance features complement the main protection functions in the IED. All protection and control functionality has been verified before procurement and validated again during commissioning with a close-loop test system to verify the sensitivity, timing, annunciation, and other ancillary functionality against the design. Ongoing efforts remaining in this project include continuous monitoring of IED protection status, improvement of current protection settings to ensure more secure operations, and selecting a substation gateway dedicated for the ultimate goal of engineering monitoring and post-event analysis.

REFERENCES L. J. Blackburn and T. J. Domin, Protective Relaying: Principles and Applications, Third ed., CRC Press, 2007. 1

W. A. Elmore, Protective Relaying: Theory and Applications, New York: Marcel Dekker, Inc., 2004. 2

Substation Automation Products, “Line Distance Protection 650, Technical Manual,” Vasteras, Swedan, 2011. 3 ABB,

U. Klapper, A. Apostolov, D. Tholomier and S. Richards, “K-Factor * Mutual Coupling on Asymmetrical Overhead Lines for Optimum Reliability of Distance Protection,” in CIRED, 2008. 4

Protective Relay Vol 1 Jack Chang is a Regional Technical Manager for ABB Inc. in the Substation Automation Products business unit serving customers in western Canada and northern regions. He provides engineering, commissioning and troubleshooting support to customers applying ABB’s high-voltage protective and automation devices. Prior to joining ABB, Jack worked as a substation P&C project engineer in two specialized consulting firms and also as an engineering consultant to a public owned utility in their transmission expansion and upgrade projects. Jack is a registered professional engineer in the province of Alberta, Canada. Lorne Gara is a Technical Manager for Orbis Engineering. He provides technical support for the engineering, field services, and automation departments of Orbis and many of its Clients. Lorne has a wide range of experience in engineering, commissioning, maintenance, fault analysis, and start-up of utility and industrial power systems across North America. He has extensive experience with protective relay setting development, commissioning, and testing protection and control systems. Yordan Kyosev is a Manager of EPCOR protection team. He is accountable for the performance of protection & control systems of the company including capital planning, project execution, asset management and operational support. Prior joining EPCOR he worked as a P&C engineer in Bulgarian National Electric company and as a power systems engineer in Schlumberger, Canada. Yordan is a registered professional engineer in the province of Alberta, Canada. Peter Fong received a BS in Electrical Engineering from the University of British Columbia in 1988. He joined OMICRON in 2000, where he presently holds the position of Application Engineer. Prior to joining OMICRON, he worked for 12 years at BC Hydro and two years at a relay manufacturer in the US. Peter Fong is a Professional Engineer (APEGBC) and a member of IEEE.

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INTERCONNECTION ISSUES NETA WORLD, FALL 2013 ISSUE NETA World, Fall 2013 Issue James G. Cialdea, P. E., Three-C Electrical Co., Inc.

There has been a significant increase in green energy projects with the biggest growth in wind, solar, and cogeneration. These projects are typically built to reduce electrical demand from the local utility resulting in some cost savings and increasing green power. Unfortunately, lack of understanding of interconnection requirements have delayed and increased costs on these projects. In many cases, the developers of these projects do not realize that there are specific requirements to run any type of generation that is connected to the utility – even deep within an existing system. These requirements can stop a project, usually at a very late stage with substantial capital tied up, until they are met. Insufficient protection design adds unplanned costs to the project. Many testing companies have received calls from their customers saying “We are trying to start-up our new energy project and the utility is telling us that they need approved settings and witness testing. Can you do that… right now?” The issue is that the testing company probably can do it right away, but the utility cannot. The utility has too many interconnection applications and not enough engineers to turn around an application quickly. The utility will perform a design review, particularly focusing on the interconnection protection and may require additional studies. In fact, the Federal Energy Regulatory Commission (FERC) has created a standard procedure and time line for the process: Small Generator Interconnect Procedure (SGIP) – less than 20 MW. There are different processes in the standard depending on the size and type of project: less than 10 kW and less than 2 MW. Some of the processes can take up to 180 business days, almost a year. SGIP defines the steps that are necessary to get an interconnection agreement (IA) from the local utility. This agreement is required for the generation to go on-line. The steps include design criteria, utility studies, and commissioning. For a successful project these steps must be understood and included in

the project plan from the start. We have found projects ready to go on-line that the local utility has denied interconnection due to the developer not meeting the requirements of SGIP. This includes design criteria such as IEEE 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems. In some cases, for projects as small as 500 kW, redundant relaying and direct communication with utility SCADA is required. This additional equipment needs to be procured, approved, installed, and commissioned. This delays the project interconnection as well as adds unplanned costs. Up front planning and understanding of the standards, preliminary meeting with local utility, and early involvement of a qualified testing company, preferably working directly for the owner, are the keys to a successful project.

REFERENCES 1 Federal Energy Regulatory Commission’s Office of Energy Projects., June 2012. URL: https://www.ferc.gov/legal/staff-reports/jun-2012-energy-infrastructure.pdf James G. Cialdea, P.E. is currently President of NETA and has worked in the testing industry for over 30 years at 3C Electrical Company in Massachusetts. Now Chief Technology Officer of CE Power Engineered Services, LLC, headquartered in Cincinnati, Ohio, he is a NETA Certified Senior Technician, a member of the NETA Standards Review Council, MA Electrical Code Subcommittee, NFPA Code Making Panel 4, and Secretary for the IEEE PES Boston Chapter. Jim is a past president of the MA Electrical Contractors Association and is a licensed Master Electrician and licensed Construction Supervisor. He earned a B.S. degree in Electrical Engineering from Worcester Polytechnic Institute in Worcester, Massachusetts.

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FAULT CLEARANCE ON GROUNDED NEUTRAL SYSTEMS NETA World, Winter 2014 Issue Jeff Jowett, Megger As described by the National Electrical Code® (NEC®), effective grounding must include three elements. It shall provide a permanent and continuous path from structure or equipment. It shall have ample carrying capacity to conduct any fault current likely to be imposed upon it, and it shall have sufficiently low impedance to limit voltage to ground and facilitate operation of protective devices. As described in the previous article, it is recommended to have the grounding path and circuit conductors housed within the same metallic enclosure, or the metallic enclosure itself may be used to provide the grounding path for the circuit conductors within. Rather than specifying a maximum impedance of the groundfault circuit, the Code (250-51) indicates that it should be sufficiently low to facilitate operation of protective devices; i.e., the fuse or circuit breaker shall be able to reach its instantaneous pickup operating range. The overcurrent device will thereby operate quickly to remove the fault. Fault currents less than the instantaneous operating value will extend the opening time of the protective device. Manufacturers of fuses and circuit breakers publish operating or trip curve charts (Fig 1). These charts serve the purpose of providing a convenient means for assuring that the groundfault path has sufficiently low impedance to permit protective devices to operate quickly and without heat damage to the circuit or equipment. Circuit breakers will have different curves depending on the number of poles and ampere ratings. The multiple of the circuit breaker rating at which it reaches its instantaneous pickup rating is the zero time delay in operation of that breaker. The same process is applied to the selection of appropriately rated fuses. Clearing a short-circuit (fault from conductor to conductor) is the same for grounded and ungrounded systems and involves installing an overcurrent device in series with each ungrounded system conductor. Clearance time may have to be as low as a fraction of a cycle depending on the magnitude of short-circuit current and the characteristics of the device. High-interrupting capacity, current-limiting fuses accomplish this for virtually all ranges of short-circuit currents. Similarly, current-limiting circuit breakers are available. Underwriters Laboratories defines current-limiting as: “The term ‘current-limiting’ indicates that a fuse, when tested on a circuit capable of delivering a specific short-circuit current (rms amperes symmetrical) at rated voltage, will start to melt within 90 electrical degrees and will clear the circuit within 180 electrical degrees (1/2 cycle).”1 They also clarify that a fuse may not be current-limiting on a circuit of lower maximum available current.

The standard also defines current-limiting circuit breakers: “… one that does not employ a fusible element and when operating within its current-limiting range, limits the let-through I2t (current squared time) to a value less than the I2t of a ½ cycle wave of the symmetrical prospective current. Current-limiting circuit breakers are marked current-limiting and are marked either to indicate the let-through characteristics or to indicate where such information may be obtained.”2 In addition to current-limiting circuit breakers, there are also circuit breaker current limiters. These UL describes as: “…designed in conjunction with specific circuit breakers and to be directly connected to the load terminals of the circuit breakers. They contain fusible elements which function only to increase the fault current interrupting ability of the combination which is intended for use in the same manner as the circuit breakers when installed at the service and for branch circuit protection. The limiters are rated 600 volts or less.”3 Because of the specific mating of these devices to protected circuits, it is vital to scrupulously adhere to manufacturer’s instructions when installing. It is important to be aware of the inverse time nature of overcurrent devices. This means that as current increases, operating time decreases (the more potentially destructive the current, the more quickly it is extinguished). Overcurrent devices see fault current at lower operating ranges as a load and do not react as quickly as at their current-limiting range. Often, two or more circuit breakers or fuses are installed in series. Tested for operating compatibility, the manufacturer may have marked them with a series-combination rating. In general practice, the device installed closest to the source is rated at or above available fault circuit here, however, is much different than that of a short circuit. In this case, the impedance of the ground-fault circuit can be high enough to become the controlling factor for current flow. The available capacity of the system is no longer the determining factor as it is in a short-circuit fault, but rather its ability to maintain full voltage. A relatively large voltage drop must be tolerated in the grounding conductor. A useful rule is that the impedance from the point of fault back to the transformer should never be higher than would allow a minimum current flow of about 600 percent of the protective device rating. This should overcompensate for the variable impedance that may result from the point of fault. Even with a comparatively low 2000 ampere overcurrent device and a fault current of 12,000 amperes (600 percent), clearing time will be less than a second. This is generally satisfactory if hazards are kept to a reasonable minimum.

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Fig1: Circuit Breaker Operating Curve The service entrance is especially vulnerable to ground faults because there is no overcurrent protection on the incoming line. This is protected only by the utility transformer’s short circuit protection on the primary, which can be many times the rating of a secondary overcurrent device. Overload protection is provided by the overcurrent device in series with the service-entrance conductors at the load end, and is required by the NEC to be outside the building or at least nearest the point of entry of the conductors into the building (230-70a). If a ground fault does not develop on the load side, it can only be cleared by the transformer’s primary fuse which can be many times the rating. Often this results in the

fault only clearing by burning itself clear or developing into a short circuit. The NEC requirement, then, limits the risk of having conductors with no protection inside a building. If equipment on the line side of the service entrance is not properly bonded and a properly-sized main bonding jumper in place, it is unlikely that enough current will pass to clear the fault through protective devices on the line side of the utility transformer. The neutral of a grounded system serves to energize loads at line-to-neutral voltage and carry unbalanced current back to the source. It also provides a low-impedance path for fault currents to facilitate the operation of overcurrent devices. Whether needed for

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Fig 2: Service Conductor Grounded to Service

Fig 3: Service Conductor Not Grounded to Service

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Protective Relay Vol 1 voltage requirements or not, the neutral still must be connected to the equipment grounding conductor at the service (250-23b). On a balanced load and carrying no load current, the neutral is still serving a vital role in fault clearance as a grounded conductor. It provides a low-impedance path directly to the transformer. A fault current is not required to travel through the earth, as the grounded neutral will allow sufficient current flow to operate the protective device. In parallel, the grounding electrode and earth still operate as a fault-current path, but typically 90 percent or more of the current returns through the grounded neutral (Fig. 2). This configuration is essential for circuit protection even when the neutral is not required to serve the load. In situations where the neutral is required to serve the load, it must be remembered to size the neutral not only against the load but also include the fault current and overcurrent protection requirements. What is the situation in the case where there is no grounded neutral? Consider a 120/240V single-phase grounded system where the load is supplied at 240. A grounding conductor from the load is properly connected to a grounding electrode and bonded to the equipment grounding conductor. But the neutral is not carried into the service equipment, as all power utilization is at 240 volts (Fig. 3). If a ground fault should occur, voltage between equipment and ground will rise, often to a dangerous level. The fault path consists of the impedance of the fault, then the grounding conductor and the grounding electrode, as determined by the surrounding earth. The fault current must travel through the earth to the neutral ground at the transformer, then through the transformer and back to the service and the overcurrent device to the point of the fault. As all the series impedances are added up, this circuit is unlikely to have an impedance of less than 22 ohms. For the circuit as described, the maximum current would be 5.5 amperes. With a typical 100 ampere service and 20 ampere overcurrent device, the circuit protection would not operate and a serious shock and fire hazard would exist, for minutes and possibly even days. Imagine, finally, that the remote but possible situation of the transformer and electrical system being grounded to the same water pipe system existed. The resistance of the fault path would be greatly reduced, but because of the wide separation in distance, reactance and therefore impedance of the fault circuit would still be high. The fault current light still not reach a level to operate overcurrent devices and the shock hazard remain.

REFERENCES Underwriters Laboratories Electrical Construction Materials Directory Guide Card (JCQR)

1

2

Ibid. ((DIVQ)

3

Ibid. (DIRW)

Source of information: Int’l Ass’n of Electrical Inspectors (IAEI) Soares Book on Grounding Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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ELECTRICAL COMMISSIONING: TOP PRIORITIES TO ENSURE A SUCCESSFUL PROJECT NETA World, Spring 2015 Issue Dan Hook and Tim Conley, Western Electrical Services, Inc. Electrical commissioning is a multistep and complex process focusing on the verification and documentation of an electrical system to ensure it performs as intended and meets applicable standards and manufacturers’ tolerances. Electrical commissioning should identify and document the correction of discrepancies so that it is a reliable system that has been installed in accordance with design specifications when it is turned over to the owner. A successful electrical commissioning project also provides the necessary baseline data for the system against which future maintenance tests can be compared for accurately trending the health of the electrical system. Electrical acceptance testing and electrical commissioning are terms that have been and continue to be used interchangeably. Although the electrical acceptance testing may be largest component, the commissioning process is more comprehensive. Typically, commissioning activities begin prior to acceptance testing and ideally will commence very early in the overall project schedule. In our experience the inclusion of a commissioning process in the early stages of the project can identify problems that will be encountered later and allow for correction of those issues in a timely manner.

DOCUMENTATION All required design documentation should be gathered prior to formulating a commissioning plan. On the surface this may appear like elementary guidance that is easily provided by the customer. However, there are many situations that may arise which present challenges to obtaining accurate documentation. Change orders can happen in the design and construction phases of a project. This can result in many revisions to drawings and specifications, even those marked as released for construction. Often there is more than one entity responsible for the documentation required to adequately develop a commissioning plan. It can be very frustrating to dedicate significant time and effort to a project, only to learn that the documentation provided was not correct, with the result that the work must be redone. At a minimum the following items are recommended to generate a comprehensive commissioning plan, with a brief statement of explanation for each.

ELECTRICAL PLANS One-Line Diagrams This overall view of the electrical distribution system is absolutely critical to identifying the individual components of the system that will undergo electrical acceptance testing in the field.

One-line diagrams also show the interconnection of various parts of the system in a simple view that can be used for switching order development and is a large, but not all inclusive, part of developing lockout-tagout requirements.

Three-Line Diagrams Three-line diagrams allow the test team to determine if the wiring supports the anticipated functionality. Three-lines are critical to the technician and the commissioning party in that they enable the development of test plans, especially when dealing with instrument transformers and how they are required to be connected to metering and protection circuits.

Schematics, Control Device Truth Tables, and Connection Diagrams These drawings, which show the actual physical locations of connections, electrical connection points, and appropriate states of contacts and other control devices, are essential in developing point-topoint continuity test requirements. They are also of critical importance in the event that a discrepancy is found and must be corrected. These drawings are often altered or updated during the installation and testing activities, commonly referred to as red-line updates, and can present a challenge near the end of a project with regard to ensuring the customer has the most up to date set. One of the most important goals of the commissioning process is the accurate documentation and updating of the actual system configuration, or as builts, of the final product.

ELECTRICAL SPECIFICATIONS Design Criteria The design criteria are of paramount importance for the commissioning team to fully understand how the system is required to perform. Recent trends show an increase in design-build type projects. One of the goals when this project structure is chosen is a more cohesive relationship between the design team and construction team. Often these structures are chosen in an attempt to shorten the project timeline as well as streamline project actions and smoothly address issues that may arise during construction. In any case the project drawings and specifications must be developed and approved prior to beginning construction.

Factory Test Requirements In many specifications factory testing is required to be performed and witnessed by a designated representative. The factory witness

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Protective Relay Vol 1 testing requirement is often missed and may create delays in shipping the materials to the job site, or worse yet, may cause delays on site because problems that should have been found during factory witness testing are not found until commissioning begins. When the commissioning process is started and approved early in the project’s timeframe, the chance of missing critical items such as this is reduced.

Field Electrical Acceptance Testing Requirements Field acceptance testing criteria must be clearly delineated. In some cases there are optional tests or alternate testing methods required. For example, medium voltage cables have multiple approved methods for performing acceptance tests. The commissioning team must ensure the correct method of testing is performed by the testing agency.

MANUFACTURER’S DOCUMENTATION Manufacturers often have specific installation instructions and startup/commissioning guidelines. Some specialized equipment may have unique requirements that even a very experienced electrical contractor and testing technician may not know. The commissioning team is responsible to the owner for correct installation and startup and, therefore, must have this information when developing the commissioning plan.

COMMISSIONING PLAN The components of the commissioning plan should be finalized early. By its very nature, the commissioning plan often has implications and requirements prior to the mobilization of construction crews and the independent testing organization. For example, the contracted companies and the personnel themselves may be required by the specifications to submit qualifications for approval. The commissioning plan may also require specific tests to be performed or specific test methods to be used during acceptance testing. If this plan has not been developed and approved prior to the testing period, the acceptance testing firm may perform testing by their own standard operating procedures and practices, rather than by the requirements for the project.

INSTALLATION INSPECTIONS Installation inspections can be performed by the commissioning team or by a quality assurance representative of the electrical contractor depending on project requirements. In some cases an installation inspection must be performed prior to moving on to the next step in the construction process.

PREENERGIZATION

POWER SYSTEM STUDIES

Preenergization (Electrical Acceptance Testing) testing typically includes component testing, continuity testing on interconnections, and functional testing on controls and interlocks.

Short Circuit Study

ENERGIZATION

Requirements in the National Electric Code for labeling of switchgear have been updated to include available fault current information. The short circuit study is the source for that information. The design requirements for switchgear ratings should stem from this study and must be verified by the commissioning team.

The first energization event for newly installed electrical equipment should address two important items. The first is safety and the second is confirmation of the expected system parameters.

Coordination Study with Device Setting Sheets/Set Point Files The protective device settings verification must be documented in the commissioning plan. Protective devices are usually shipped from the factory with minimum or default settings applied. Protective device settings can be altered during the testing and startup process. The final commissioning report should include all finalized settings. A coordination study is an integral part to be incorporated into a set point file, but it must be understood that a qualified protective relay engineer with a programming background must generate accurate set point files that include the logic necessary to perform all required functions based on system design demands.

Arc-Flash Hazard Analysis This power system study continues to be at the forefront of the electrical safety industry. The commissioning team must verify labeling requirements.

Commissioning Plan The commissioning plan should include or reference the job hazard analysis for required testing procedures. A detailed Method of Procedure (MOP) needs to be developed and include the following: ●● Summarized scope of work statement ●● Test team organization ●● Testing prerequisites (plant conditions) ●● Sequential procedural steps for the testing ●● Expected system responses ●● Actions to be taken in the event of a failure ●● Safe back out points including actions to establish safe plant conditions should the need arise to cease testing operations ●● Safety Briefing

System Parameter Measurements System parameter measurements should be included during the energization procedure. Phase rotation, and phase sequence are of paramount importance. Prior to system functional testing, other installed indications should be checked. Metering and protective relay indication checks will ensure that the instrument transformers, wiring, and programming are as specified.

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POST ENERGIZATION

HIERARCHY

Post energization (System Functional) testing occurs near the end of the physical process. All component testing has been completed; interconnection continuity has been verified; and controls schemes have also been verified. The system has been energized and all indications verified such that simulations of real life situations may be performed.

In many projects the commissioning team is part of the overall contract from the owner and could be a subcontractor to the prime contractor, or a secondary subcontractor to the electrical subcontractor. However the commissioning team has a professional responsibility to the owner to deliver a reliable system with all required documentation, even if the prime contractor has the ultimate responsibility. Commissioning is a quality assurance engagement where the importance of professional relationships and expertise cannot be understated. A successful commissioning team must attain a practical hierarchy with the owner while operating within the contractual hierarchy present.

Transfer between Modes This testing may include switching power supplies from normal to emergency in an overall system test where utility power is removed, or a simple transferring from double ended to single ended on a capable substation.

Load Banking The purpose of this test to replicate real load, or perhaps full load conditions at nominal voltage to prove the system will operate as intended.

Power Quality Testing In our experience an increasing number of specifications require the documentation of power quality on the newly-installed system, especially when UPS systems are involved.

Utility Parallel Operation The ability to parallel safely with the serving utility and in some cases document power flow in both directions may be one of the most critical post energization tests that can be performed. Many serving utilities will have specific requirements and complex steps to perform this work.

DISCREPANCY LOG Maintain a sequential discrepancy log during the entire commissioning process including resolution for each discrepancy. This log can serve many purposes near the end of the project but can be nearly impossible to recreate after the fact. This record can be thought of as a type of journal for the project and assist with contract management, troubleshooting of systemic discrepancies, and provide a track record of such. The size and complexity of the job will drive the extent of the discrepancy log. A practice incorporated successfully on large projects is to generate a rapid deficiency report with pictures along with the daily progress reports. This enables a deficiency to be identified for quick release to a quality control representative. It then allows the builder or others to take corrective actions and lessens administrative delays.

ELECTRICAL ACCEPTANCE TESTING Utilize industry-recognized standards for acceptance testing by an independent, third party that can function as an unbiased testing authority, professionally independent of the manufacturers, suppliers, and installers of equipment or systems being evaluated. When performing functionality testing, one may need to tailor data sheets to address all aspects of the installed design features. A simple block on a check sheet with a pass/fail often will not meet the project specifications and requirements.

The complexity of the electrical systems being installed and their interrelation with other systems is growing. The electrical commissioning process is included in an increasing number of projects as a strategy to combat issues during construction, testing, and operation systems. The ultimate goal is to turn over a safe and reliable system that will operate as designed to the owner. The ANSI/NETA ECS-2015 Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems has been designed to establish an industry recognized standard for these activities. Dan Hook is the Executive Vice President in charge of Business Development at Western Electrical Services, Inc. where has previously held Field Service Engineer, Sales Engineer, and Chief Operating Officer positions. He has been in the industrial electrical industry for over 20 years with US Navy and civilian experience. Dan holds a master’s degree in Electric Power Engineering from Rensselaer Polytechnic Institute in Troy, New York, and he maintains his professional engineer’s license in Washington, Utah, Arizona, and Oregon. He earned an MBA in 2012 from Pacific Lutheran University with a concentration in Entrepreneurship and Closely Held Businesses. Dan is a certified NETA Certified Senior Technician Level IV as well as a NICET Level IV. Tim Conley is a Senior Technical Advisor at Western Electrical Services, Inc., where he has previously held Field Service Technician and Project Manager Positions. Tim is a NETA Certified Technician Level III as well as NICET Level III. He is a member of Electronics Advisory Committee for Olympic College in Bremerton, WA. Tim has direct experience with the commercial nuclear industry as well as disaster recovery, represented by the year he spent with the Eaton Corporation deal with Hurricane Ike recovery for most of his tenure there. Tim spent nearly 24 years in the US Navy as an Electrician’s Mate leading the divisions and department maintaining and testing all aspects of generation, distribution, control equipment, and distribution system protection as it applied to nuclear submarines. In addition, he completed successful Nuclear Instructor tours mentoring the US Navy’s future nuclear officers and enlisted men.

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MODERN ADVANCES IN TESTING MULTIFUNCTION NUMERICAL TRANSFORMER PROTECTION RELAYS NETA World, Winter 2015 Issue Steve Turner, Beckwith Electric Company, Inc. This article demonstrates different techniques to test multifunction numerical transformer protection relays, so that these techniques can easily be incorporated into automated test software. The Common Format for Transient Data Exchange (COMTRADE) for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays because it can replay actual operating conditions or simulate a very complex event such as transformer energization when there is remnant flux on the core of a winding. The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using the Electromagnetic Transient Program (EMTP). Lastly, automated testing of the boundary of the phase differential operating characteristic is illustrated to properly test the relay settings.

This is an excellent case to use the COMTRADE record captured by the relay since you can test transformer differential protection to ensure it does not operate during inrush for many applications—that is, most two-winding transformers and auto banks with five-amp, secondary-rated CTs on the high side. Figure 2 shows very little restraint current and high magnitude differential current in B-Phase during the transformer energization. The trip occurred when the ratio of B-Phase 2nd harmonic to fundamental current dropped too low.

COMTRADE SIMULATION – 2ND HARMONIC RESTRAINT ON INRUSH COMTRADE records captured by numerical relays and digital fault records from actual system events are of particular interest since these provide the ability to test protection for critical faults or disturbances that are difficult to create using off-the-shelf, test-set software. Utilities consultants and equipment manufacturers can build a library of test cases. The first example is the case of transformer differential protection operating during energization due to low 2nd harmonic current content in the inrush current. This event was recorded by the numerical relay protecting a 400 MVA 230/115 kV auto-transformer that was energized from the high side while the low side was open (Figure 1). The auto-transformer is connected to a 230 kV straight bus through a motorized disconnect switch. The CTs are wye-connected on both sides. The 230 kV CTs are on the transformer bushings connected with the full ratio (1200:5). Fig. 2: High Side CT Secondary Fundamental Versus 2nd Harmonic Current The relevant current phasors measured by the relay at the time of the trip along with the 2nd harmonic contents are listed in Figure 3. Fig. 1: Auto Transformer High-Side Energization

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Fig. 3: Current Phasors Measured at the Relay with 2nd Harmonic Current The numerical transformer differential relay that tripped uses internal zero-sequence current compensation to prevent unwanted operations during external ground faults since the current transformers are wye-connected, and the transformer is an auto bank. Calculating the phase-to-phase current automatically eliminates zero-sequence current as follows: Ia = I1 + I2 + I0 Ic = a I1 + a2 I2 + I0

Fig. 5: Current Phasors Measured at the Relay with 2nd and 4th Harmonic Current

Iab = Ia – Ib = I1 (1 – a2) + I2 (1 – a)

TEST REQUIREMENTS

Ibc = Ib – Ic = I1 (a2 – a) + I2 (a – a2)

You will need a three-phase test set that can playback COMTRADE records. Three current channels are required. Connect the three-phase test set to the relay as shown in Figure 6A.

Ib = a2 I1 + a I2 + I0

Ica = Ic – Ia = I1 (a – 1) + I2 (a2 – 1) If the transformer differential relay uses phase-to-phase current to eliminate zero-sequence current, then Ibc is the most depleted of 2nd harmonic content and also corresponds to the phase that actually tripped (B-Phase). Figure 4 illustrates the following signals: ●● Ibc ●● Fundamental component ●● 2nd harmonic component ●● Ratio of 2nd harmonic to fundamental The ratio decreases in magnitude over the first two cycles following energization. The relay tripped at the point when the ratio dropped to 14%. Note that transformer differential relays are typically set to restrain at 15%. Figure 4 illustrates how the phase differential protection is restrained using 2nd harmonic current. Ratio =

2 nd I diff

Fig. 6A: Test Connections Figure 6B shows off-the-shelf software available to play back this particular COMTRADE record through the test set to the relay.

I diff •100%

Fig. 4: Current 2nd Harmonic Restraint Logic

Fig. 6B: Test Software

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Protective Relay Vol 1 TEST PROCEDURE 1. Play back the inrush case to the relay with harmonic restraint disabled. 2. The relay should trip when harmonic restraint is disabled.

2. Re-assemble the B-Phase current by adding the fundamental and 2nd harmonic back together (depleted IB in the case of Figure 8). 3. Inject the adjusted current into the relay.

3. If the relay trips, then play back the inrush case again with harmonic restraint enabled. 4. The relay should not trip when harmonic restraint is enabled. Figure 7 shows the corresponding flowchart.

Fig. 8: Adjusted Inrush Current

EVEN HARMONIC RESTRAINT DURING TRANSFORMER INRUSH

Fig. 7: Transformer Inrush Test Procedure Flowchart

ADVANCED TEST—ADJUSTING THE LEVEL OF 2ND HARMONIC CONTENT It is possible to reduce the amount of 2nd harmonic content present in the inrush current during the injection test. You can reduce the level of 2nd harmonic current until the restraint no longer blocks the differential protection. For example, 10% is typically the minimum level acceptable to set the 2nd harmonic restraint; if it were set lower, tripping might be significantly delayed for heavy internal faults due to harmonics generated by CT saturation. The software shown in Figure 8 illustrates this process: 1. Isolate the fundamental component and 2nd harmonic component in B-Phase current (IB). Multiply the 2nd harmonic content by a factor to reduce its magnitude to the pickup level selected for the 2nd harmonic restraint. For this particular case, the minimum pickup is 10%. Therefore, 10% the multiplication factor is 0.7 (i.e.,14% ).

Events such as transformer energization can be captured by utilities using digital fault recorders or numerical relays and then later played back via COMTRADE to observe relay performance. Some customers have access to software such as the Alternative Transients Program (ATP) and can build their own transformer models to simulate inrush. This is a practical method to check that the relay is properly set. One example of playback is to evaluate the performance of the restrained differential protection for transformer inrush with varying levels of harmonic content in the current waveforms. Transformer differential protection has historically used the 2nd harmonic content of the differential current to prevent unwanted operation during transformer inrush. It is advantageous to use both the 2nd and 4th harmonic content of the differential current. The relay can internally calculate the total harmonic current per phase as follows: I2-4 =

I 22 + I 42

The sum of the two even harmonics per phase helps to prevent the need to lower the value of restraint, which could cause a delayed operation if an internal fault were to occur during transformer energization.

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Cross-phase averaging also helps prevent unwanted operation during transformer inrush. Cross-phase averaging averages the even harmonics of all three phases to provide overall restraint. The cross-phase averaged harmonic restraint can be internally calculated by the relay as follows: Ir2-4 =

I A2 2 4 + I B2 2 4 + I C2 2

First Case — Balanced Inrush Energized Line with Bank from Single End (No residual flux)

4

The transformer relay with even harmonic restraint and crossphase averaging tested for the following cases did not malfunction. The inrush currents presented here were created using EMTP and have a very slow rate of decay. Figure 9 is a one-line diagram illustrating the 600 MVA auto-transformer.

Fig 10A: Total Phase Currents for Balanced Inrush

Fig. 9: 600 MVA Auto-Transformer Single-Line Diagram (Delta Winding DAC)

87T RELAY SETTINGS The auto-transformer differential protection settings are as follows: TAP1 =

= 4.18

[27]

TAP2 =

= 3.77

[28]

87T Pickup =

0.5 per unit

Slope 1 =

25%

Slope 2 =

75%

Break Point =

2.0 per unit

Fig. 10B: 2nd Harmonic Component Currents for Balanced Inrush

Even Harmonic Restraint = 10% (cross-phase averaging enabled)

Fig. 10C: 4th Harmonic Component Currents for Balanced Inrush

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Protective Relay Vol 1 Second Case — Balanced Inrush Energized Bank from Winding Two with Winding One Open (No residual flux)

Fig.11A: Total Phase Currents for Balanced Inrush

Third Case — Unbalanced Inrush Energized Line with Bank from Single End (Severe A-phase residual flux)

Fig.12A: Total Phase Currents for Unbalanced Inrush

Fig 11B: 2nd Harmonic Component Currents for Balanced Inrush Fig.12B: 2nd Harmonic Component Currents for Unbalanced Inrush

Fig. 11C: 4th Harmonic Component Currents for Balanced Inrush

Fig.12C: 4th Harmonic Component Currents for Unbalanced Inrush

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Protective Relay Vol 1 Fourth Case — Balanced Inrush Energized Bank from Winding Two with Winding One Open (Severe A-phase residual flux)

TRANSFORMER DIFFERENTIAL CHARACTERISTIC BOUNDARY TEST A simple procedure can automate testing the phase differential operating characteristic. A common practice for commissioning distance protection is to test along the boundary of the operating characteristic— for example, circles, lenses. or quadrilaterals. This practice can also be applied to transformer differential protection. Consider the simple example of a two-winding transformer with both sets of windings wye-connected. To keep the example simple, also assume both sets of CTs are wye-connected and have the same CT ratios — that is, both windings are at the same potential. If you connect the current leads from the test set such that the test currents I1 and I2 are flowing through the transformer windings, then the perphase differential and restraint currents can be expressed as follows:

Id =

[1]

I1 + I 2 [2] 2 Where

Ir = Fig.13A: Total Phase Currents for Unbalanced Inrush

I1 = Winding 1 per unit current (A, B, or C-phase) I2 = Winding 2 per unit current (A, B, or C-phase) Express equations [1] and [2] using matrices as follows:

Id I r =

•

I1 I 2

[3]

Where

IC = M•IT [4] IC = Fig.13B: 2nd Harmonic Component Currents for Unbalanced Inrush

Id ,M= Ir

, IT =

I1 [5] I2

Invert the matrix M in equation [3] to determine the two equations for the test currents:

I1 = I2

•

I d [6] Ir

Calculate the test currents based on an operating point on the differential characteristic as follows:

I1 =

Id + I r 2

[7]

I2 =



[8]

Note: This test simulates through current, so the second test current should actually be represented as follows when injecting current: Fig.13C: 4th Harmonic Component Currents for Unbalanced Inrush

I2 =

[9]

First Example: Consider a transformer differential characteristic for the two-winding transformer described earlier with the following settings:

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Protective Relay Vol 1 Pickup = Slope =

0.2 per unit 28.6%

From Table 1: I1 = 0.8 per unit I2 = 0.6 per unit

[15] [16]

IA1 = 0.8•TAP1 IA2 = 0.6•TAP2• 3

[17] [18]

IA1 and IA2 are the two test currents.

CONCLUSION

Fig. 14: Phase Current Differential Characteristic for Two-Winding Transformer Table 1 lists the four operating points on the characteristic along with the corresponding test currents. All values are in per unit. Table 1: Test Currents for Transformer Differential Characteristic Boundary Id

➀ ➁ ➂ ➃

Ir

I1

I2

0.2

0.3

0.4

-0.2

0.2

0.7

0.8

-0.6

0.4

1.4

1.6

-1.2

0.6

2.0

2.3

-1.7

Remember that the test currents are connected at 180 degrees out of phase (i.e., through current). Second Example: Now consider a transformer differential characteristic for a two-winding transformer connected delta (DAB) — wye with wye connected CTs on both side. A numerical transformer differential relay internally compensates the CT currents as follows: Winding 1 (DAB)

Winding 2 (Wye)

IA1relay =

I A1 TAP1

[09]

IA2relay =



[10]

IB1relay =

I B1 TAP1

[10]

IB2relay =



[11]

IC1relay =

I C1 TAP1

[11]

IC2relay =



[12]

Where IA1, IB1, IC1, IA2, IB2 and IC2 are the CT currents. Use the following equations to test the A-Phase differential element at point ➁ of the characteristic shown in Figure 14: IA1 = I1• TAP1 [13] IA2 = I2•TAP2• 3 [14]

This article demonstrates different techniques to test the multifunction numerical transformer protection relays and shows how to incorporate them using automated test software. COMTRADE for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays since it can be used to replay actual operating conditions or simulate very complex events, such as transformer energization when there is remnant flux on the core of a winding. The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using EMTP. The first case can be used to test harmonic restraint for any transformer differential protection relay that has phase current inputs rated 5 amps 60 Hz; therefore, it is a universal test. The second case shows that by using the RMS value of both the 2nd and 4th harmonic current, it is possible to have proper restraint for a difficult case of transformer energization where the core has significant remnant flux. Finally, it is shown how to automate testing the boundary of the phase differential operating characteristic to properly test the relay settings; at least four points are tested, which verifies the minimum pickup, break point, and both slopes. Steve Turner is a Senior Application Engineer at Beckwith Electric Company, Inc. He has more than 30 years of experience, including working as an application engineer with GEC Alstom for five years, primarily focusing on transmission line protection across the United States. He was an application engineer in the international market for SEL, Inc., again focusing on transmission line protection applications including single pole tripping and series compensation around the world. Steve wrote the protection-related sections of the instruction manual for SEL line protection relays, as well as many application guides on various topics such as transformer differential protection, out-of-step blocking during power swings, and properly setting ground distance protection to account for mutual coupling. Steve also worked for Duke Energy (formerly Progress Energy) in North Carolina, where he developed a patent for double-ended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Texas A&M Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and serves in the IEEE PSRC.

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TESTING NUMERICAL DISTRIBUTION RELAYS USING RELAY VENDOR SOFTWARE TOOLS NETA World, Fall 2015 Issue Steve Turner, Beckwith Electric Company, Inc. Testing numerical distribution relays can be a complex task. Some of the issues include: ●● Multiple settings groups (e.g., fuse-blow scheme versus fuse-save scheme) ●● Multishot automatic reclosing ●● Complex programmable relay logic The goal of testing protective relays in general is to verify that the overall application works properly, according to design, and no hidden flaws can lead to a human performance event. Using software tools provided by the relay vendor for support can greatly simplify testing and decrease the overall time required. Test personnel and field craft should consider using these software tools. Relay vendor software is designed to support the product and has inherent advantages when used in conjunction with relay test set software.

RELAY SELF-TEST AND AUTOMATIC ALARMING In the past, numerical relays provided only an output contact to alarm for general conditions, such as the power supply is being energized or the relay self-test failed. Modern numerical relays provide much more detailed self-test results that can be monitored through output contacts or communication protocols, such as Modbus or DNP. Figure 1 shows an example of multiple alarm points that can be individually monitored to pinpoint the root cause of the alarm.

The following alarm points are monitored in Figure 1:. ●● Profile Switch (settings group has changed) ●● SF6 Input OK ●● Write Activity (e.g., setting has changed) ●● Battery Not Charging ●● Battery Load Test Failure ●● Battery Not Present ●● AC Power Error ●● Power Supply OK The individual battery alarms are shown ganged together driving one OR gate for a general battery alarm; however, they can also be individually monitored. Other alarm points are available,, such as protection enabled-disabled, hot-line tag, and remote-control disabled. Note that the programmable logic can be tested using the logic editor as well.

TOOLS FOR MULTISHOT AUTOMATIC RECLOSING Figure 2 shows example settings for a four-shot automatic reclose sequence.

Fig. 2: Four-Shot Automatic Reclose Sequence

Fig. 1: Multiple Point Alarm Using Programmable Logic

51P phase time overcurrent protection elements (see Figures 4A and 4B) drive the phase-shot sequence, and 51GS sensitive ground-time overcurrent protection elements drive the ground-shot

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Protective Relay Vol 1 sequence. HCL (high current lockout) is a high-set phase overcurrent element that drives the automatic reclosing cycle straight to lockout (see Figure 3).

Fig. 5A: Exporting Time Overcurrent Characteristics — Custom Curve Editor Fig. 3: Drive-to-Lockout Protection Elements (HCL High Current Lockout)

Fig. 4A: Phase Time Overcurrent Element #1 Settings

Fig. 5B: Exporting Time Overcurrent Characteristics — Curve Selection

REAL TIME AUTOMATIC RECLOSER STATE MONITOR Figure 6 shows the real-time automatic recloser state monitor (RTARSM).

Fig. 4B: Phase Time Overcurrent Element #1 Operating Characteristic (5x Pickup) The time-current characteristics can be exported to facilitate testing these elements (see Figures 5A and 5B).

Fig. 6: Real-Time Automatic Recloser State Monitor

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The RTARSM displays the following information: ●● Recloser state (reset, reclose in progress, or lockout) ●● Breaker state (52A open or 52B closed) ●● Trip time (per shot)

the operate current (Iop) for maximum torque conditions, such as a bolted fault on the distribution feeder. If the fault current is inside the forward-operating side of the characteristic, then a trip occurs (i.e., ±90°)

●● Recloser interrupting time (per shot) ●● Time to reset from lockout ●● Fault type (phase or ground) ●● HCL operation ●● Cold load pickup asserted ●● Bus voltage supervision asserted The cold load pickup function substitutes alternative settings for overcurrent protection elements after the breaker is tripped and has been locked out for a period exceeding the programmable timer setting. Higher pickup settings prevent unwanted tripping due to inrush when the breaker is closed. This is available and independently settable for phase and ground overcurrent inrush. Bus voltage supervision prevents an autoreclosing cycle from starting until all the supervisory conditions are met, which are selectable — bus or feeder undervoltage and synchronism across the breaker. If the timer expires before these conditions are met, the logic goes to lockout.

Fig. 8: Directional Overcurrent Operating Characteristic The second maximum sensitivity angle (MSA2) creates a tent characteristic (shaded) for the purpose of securely restricting the trip region of the characteristic (see Figure 8). The restricted operating characteristic region is given as follows: MSA1 ± MSA2 Figures 9A and 9B illustrate how the directional element is derived from the fault voltage and current. An impedance angle of 75 degrees corresponds to the maximum sensitivity angle (MSA1) as shown. Note that the operating current lags the polarizing voltage by this angle.

Fig. 9A: Directional Overcurrent Operating and Polarizing Signals as Fault Signals Fig. 7: Bus Voltage Supervision

VISUALIZATION TOOLS Tools that aid test personnel and field craft in visualizing the functions they are testing are extremely important because they help them to understand how they actually operate. Consider Figure 8 for a directional overcurrent element as an example. The vector residing at zero degrees in Figure 8 corresponds to the polarizing voltage (Vpol), which is the reference. The classic directional element has one maximum sensitivity angle, which corresponds to

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Fig. 9B: Directional Overcurrent Operating and Polarizing Signals as Phasors

CONCLUSION Numerical distribution protection relays are multifunctional, and as such, many individual functions must be tested. Using the software and visualization tools provided by the relay vendor can greatly simplify testing and decrease the overall time required. Test personnel and field craft should consider using these tools. Relay vendor software is designed to support the product, which has inherent advantages when used in conjunction with relay test set software. Steve Turner is a Senior Application Engineer at Beckwith Electric Company, Inc. He has more than 30 years of experience, including working as an application engineer with GEC Alstom for five years, primarily focusing on transmission line protection across the United States. He was an application engineer in the international market for SEL, Inc., again focusing on transmission line protection applications including single pole tripping and series compensation around the world. Steve wrote the protection-related sections of the instruction manual for SEL line protection relays, as well as many application guides on various topics such as transformer differential protection, out-of-step blocking during power swings, and properly setting ground distance protection to account for mutual coupling. Steve also worked for Duke Energy (formerly Progress Energy) in North Carolina, where he developed a patent for double-ended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Texas A&M Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and serves in the IEEE PSRC.

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ACCEPTANCE, COMMISSIONING, AND FIELD TESTING FOR PROTECTION AND AUTOMATION SYSTEMS NETA World, Winter 2016 Issue

Michael Obrist, Stephen Gerspach and Klaus-Peter Brand, ABB Switzerland The introduction of the IEC 61850 standard for communication in power systems enables companies to build enhanced substation automation (SA) systems and to distribute requested functionalities in an optimal and standardized way. This brings new challenges and opportunities related to interoperability between compliant IEDs and tools, as well as for testing and maintenance processes. This article discusses: The complete sequence of testing from products to systems and the impact of IEC 61850 on these tests ●● The testing and maintenance requirements of the utilities for IEC 61850-based systems The potential of IEC 61850 related to testing and maintaining an SA system, along with some typical examples ●● The key role of the System Configuration Description (SCD) file and the importance of the system integrator The complete testing life cycle as well as related support from IEC 61850 regarding testing tools

INTRODUCTION The introduction of IEC 61850 opens up new possibilities for functionalities in multi-vendor SA systems. These new functionalities can lead to challenges if a user’s requirements for a customized SA system are fulfilled according to specifications. At the same time, IEC 61850 provides the mechanism to develop tools that facilitate testing and maintenance processes and enable users to benefit from the opportunities provided by the standard. Since IEC 61850 is based on mainstream communication technology and any treatment needs powerful software-based tools, utility maintenance staff must possess the necessary skills and tools to exploit the potential for new testing and maintenance strategies.

TESTING IN THE LIFE CYCLE OF SA SYSTEMS The complete sequence of testing — from product development to installed, customized systems — is necessary to fulfill the general and dedicated user needs for SA systems. Behind the life cycle of any SA system are the life cycles of all integrated products and related tools. From the development and production of a device (IED) and the required software tools to the on-site system tests, a variety of test phases must be passed.

This Life Cycle Testing sequence was defined and described in a previous Cigre paper. Generally, all testing is intended to improve quality and reduce risks for supplier and users. This article summarizes the required testing sequence, starting with the development process of single products (IEDs and tools) through a commissioned system customized to the user’s needs as indicated by the project-specific requirements. The basis for reliable in-house testing is the quality system of the supplier and vendor, according to ISO 9001/9002 as far as applicable.

SA System Project Independent Testing Sequence Handled by the Vendor The classic testing sequence starts with the Device Type Test and ends with the Integration Test to ensure proper functioning of the new product (IED and tool). The Conformance Test is part of the Device Type Test according to standards such as IEC 61850. Normally, the conformance of the IED or tool is confirmed by a certificate issued by a UCA International Users Group (UCAIug) qualified test center. The test requirements of IEC 61850-10 and the derived test procedures defined by the UCAIug are focused only on IED (single-product) testing. As a result, today’s conformance certificates are no guarantee of interoperability from a system perspective, but they are an important step to reaching interoperability. The goal of IEC 61850 is interoperability of the IEDs and tools in SA systems. Therefore, a generic system test should also belong to the vendor’s testing sequence. In this step, the interoperability between the different system components and tools is verified and validated. Part of this validation is the overall system performance of the provided services, tested in a reference system. This project-independent test reduces substantially the risks for all SA system projects to be executed. A second benefit is that the system configuration tool and its interfaces with the product tools are also tested. The system test described in “Exploiting the IEC 61850 Potential for New Testing and Maintenance Strategies” is not yet formally defined by IEC 61850 or by the UCAIug. Routine tests or manufacturing tests in the production chain ensure a constant quality of delivered devices.

Testing Project Specific Configurations The entire SA system project-testing sequence consists of project-related tests based on the user specification for the ordered

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Protective Relay Vol 1 SA system. They are performed by the system integrator (supplier, customer, third party, etc.) as directed by the user. These tests confirm that the delivered individual SA system is running as specified. The testing sequence starts with the Factory Test. It is a project-related test to prepare the customized system for the Factory Acceptance Test (FAT). The FAT determines whether the equipment operates according to its specifications and covers all functional requirements. The FAT is witnessed and confirmed by the user and ends with a shipping release to site. On site after the installation, the site tests are carried out. During these tests especially, the system interface to the real process will be verified and the SA system prepared for the Site Acceptance Test (SAT). The SAT witnessed and confirmed by the user is the final acceptance of the delivered system. Then the warranty and maintenance phase starts if applicable.

Maintenance Testing in Operation Using the advantages of self-supervision provided in modern numerical system components, many of the tests described in the previous sections will not be repeated as part of periodical maintenance testing during the operational phase of the SA system. Vendor tests especially may be excluded. During the operational phase of the life cycle, the testing is focused on: ●● Identifying faulty system components by periodic tests or self-supervision ●● Exchanging and reconfiguring faulty system components ●● Testing the repaired system Periodic functional testing is especially related to the hardwired process interface due to its limited self-supervision capabilities. Maintenance activities like extensions of the substation or its functions need appropriate testing of the altered system. In any case, the traceability of configuration changes must be ensured.

CHANGES IN THE TESTING PROCESS INTRODUCED BY USING IEC 61850 Modern IEC 61850 SA systems are distributed software applications based on exchanging standardized information over the substation local area network. Instead of testing the functionality of single components as in the past, system tests performed today show more similarities with testing of software applications than traditional testing of individual devices in SA systems. Because the different SA system components share common system functionalities, the interoperability between those components is a prerequisite. With the introduction of IEC 61850 Edition 2, online testing capabilities are enhanced. Several additional features such as Identifier for Simulated Messages are introduced, and the definition of the Mode/Behavior introduced in IEC 61850 Edition 1 is clarified to be more usable.

Conformance versus Interoperability Standard conforming products (IEDs and tools) from different suppliers, or products conforming to different standards from the same supplier, need not fulfill the same functional scope of supply. They may have different communication profiles. A communication profile defines the mandatory subset of the standard with the selected options and vendor-specific extensions that are implemented. Different profiles provided by different products may conform to the standard but still not be 100 percent interoperable with each other. It is the responsibility of the system integrator to check the interoperability of two or more products based on the conformance statements of the different products and the required system functionality. Additionally, the performance of devices, including delays caused by communication equipment like switches, has to be verified. These tests, preferably done independently from SA system projects as a kind of generic system test, will greatly reduce the risks for all projects.

Re-Use of Formal System Description in the Testing Process With the Substation Configuration Language (SCL), the IEC 61850 standard has introduced an interoperable and machine-readable description used for the standardized exchange of configuration data between engineering tools. Based on this configuration language, several file types have been defined in the standard. One of these files is the Substation/System Configuration Description (SCD) file providing the full documentation of the SA system as built. The typical content of the SCD file is: ●● Description of complete topology of the primary equipment of the substation (single line diagram) ●● Relationship between SA functionality defined by Logical Nodes (to be implemented in the selected IEDs) and the primary equipment ●● All IEDs (servers) and station-level equipment (clients), including their data models ●● Complete communication system with addressing and logical data flow From the communication system point of view, the interfaces for each device, client, or server connected to the system are described in this file. This allows a comprehensive evaluation and documentation of the physical dataflow between all system components. These results stay valid if the configuration of related datasets and control blocks is only changed during engineering time and not created dynamically during runtime. Therefore, the static configuration is recommended. As seen from the definition, the comprehensive SCD file is the central part of the system documentation and can be used as a standardized reference for all testing activities related to IEC 61850. This allows comparing data models, configuration version information, and the dataflow of the actual IEDs with the information as engineered in the SCD file. As a result, configuration mismatches can be easily detected in the entire SA system.

96 The message analysis of the communication between IEDs at the application level also requires the information about the content of the IEC 61850 datasets. Without this information, the transmitted values cannot be assigned to the related attributes of the data model, and an analysis at user level — i.e., a user-friendly analysis — is not possible. To fully benefit from the version information contained in the SCD file, all engineering tools must follow the rules for handling configuration changes as defined in IEC 61850, i.e., to update all relevant configuration indices of the impacted IEDs. Keeping the SCD file up to date with the commissioned SA system also ensures one common reference for later extensions or maintenance tasks. The information in the SCD file is also the basis for simulating physically nonexistent IEDs for communication (GOOSE, SV, and MMS services), for example, during factory testing where the complete SA system is not available.

TOOLS FOR ACCEPTANCE, COMMISSIONING, AND FIELD TESTING A previous Cigre paper confirmed different tool requirements in the different phases of the life cycle of an SA system. Testing tools are generally required during the entire life cycle for the related testing sequences.

Testing Tools Testing tools are used in all phases and must support the testing process and automate testing activities as much as possible. The testing activities during acceptance, commissioning, and field testing can be divided into integration testing and functional testing. The SA system has to be tested for correct communication and configuration by an Integration Test tool. With the help of the Function Test tool, the SA system functions are tested according to user-dependent specifications. For both testing tasks, it is required to simulate missing components crucial for the correct behavior of the SA system. Therefore, it is most efficient when the testing tool provides simulation capabilities as well. During testing activities in process-bus environments, a test engineer needs a way to measure the analog values sent from a merging unit (such as a current transformer) to the IEDs. In this case, the testing tool will act as an enhanced volt and ampere meter. In addition to these classic measured values, it shows useful information like phase angles and other quality attributes to the test engineer. For SA functions with embedded GOOSE functionality like protection, the testing tool guides the test engineer to operate the IED under test while setting the impacted functions of all involved IEDs in the necessary modes (as defined in IEC 61850 Ed.2). One example is the Test-Blocked mode to avoid sending out unwanted trip signals to a circuit breaker in the process (switchyard). Additionally, under test conditions, it monitors the reaction of the complete involved IED chain to verify the expected result for the specific test case.

Protective Relay Vol 1 Diagnostic Tool A diagnostic tool isolates the root cause of problems reported by the self-supervision of the SA system or detected during testing. To identify configuration issues, it is often enough to detect that different versions of the configuration files are used within the system. This information helps pinpoint the parts that need to be re-loaded with the latest version. Where the version information is consistent, an in-depth comparison of the data models may help identify further implementation problems with the functions. Finally, the application-level protocol analysis makes it easy to detect whether the information sent from one IED to another is correct. This application-level information captured on top of the ethernet can even be enriched by adding information from the SCD file, such as links to the substation section or signal texts. In the IEC 61850 world, switched ethernet is a communication backbone. Since managed switches are used, communication issues can also be related to the configuration of these active network components (e.g., wrongly defined multicast or VLAN filters). Here a diagnostic tool will help check whether the configuration of the ethernet equipment matches the logical and physical needs. These parameters can be retrieved online and later compared with the documented values in the project-specific SCD file. For horizontal IED-IED communication services (GOOSE, SV), it is helpful if the tool also includes the graphical representation of message content at the application level. This helps the engineers focus on the application level, rather than counting bits and bytes.

Simulation Tool When simulating a server IED, a client that acts toward a control center as an HMI or protocol converter, for example, could be tested. The simulation is restricted to the pure IEC 61850 data-model simulation. Any vendor-specific functional implementation cannot be provided by a generic tool. A simulation will also not replace the point-to-point test from the physical process to the HMI or gateway, but can be used to separate the testing processes to allow sequential tests with minimal effort. In this case, the HMI will be tested with signals from the process ensuring correct wiring up to the IED, and the gateway functionality can be tested by generating artificial signals with an IED simulator. Protection or control IEDs can be tested using a generic IEC 61850 client simulation. Such a client will browse the content of an IED and provide an intuitive interface based on the result — for example, to send commands to an IED and display the resulting feedback in the event list. Another case for IED simulation is the usage of GOOSE and SV messages. In case a GOOSE or SV sender is not physically available, a simulation can produce the required messages on the bus for the IED under test. The key to ensure consistency of simulation is the re-use of the SCD file for the simulation. All required information including

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Protective Relay Vol 1 configuration information is contained in the SCD file, making additional configuration of the tool superfluous. The simulation tool should contain a way to block an unintended simulation of an IED. In case an IED with the same addressing information as the IED to be simulated is already available on the network, simulation must be blocked to avoid duplicated sending of potentially different values.

licensing for testing tools, it is most convenient if all tool types are combined in a single software package.

REFERENCES Communication Networks and Systems in Substations, IEC 61850. K. P. Brand, V. Lohmann, W. Wimmer, Substation Automation Handbook, ISBN 3-85759-951-5, 2003, www.uac.ch

Documentation Tool

UCA International Users Group, www.ucainternational.org

At the end of the commissioning, the Documentation Tool should gather all relevant maintenance information from the commissioned SA system, such as IED firmware and configuration versions, serial numbers, etc., and store them in a report. This information is implicitly contained in the final updated SCD file since it presents a kind of standardized project database. This may be a very large file, and linear searching can be time-consuming. Therefore, the equivalent project information is normally stored in a vendor-specific project database for fast access. A complementary documentation tool reading out the information of interest directly from the installed system is very convenient.

W. Baass, K. P. Brand, S. Gerspach, M. Herzig, A. Kreuzer, T. Maeda, Exploiting the IEC 61850 Potential for New Testing and Maintenance Strategies, Cigre B5-201, 2008

REQUIRED SKILLS AND EXPERIENCE FOR TESTING IEC 61850 SYSTEMS IEC 61850 systems demand additional skills for the operational and process know-how of an SA system. These skills are essential for project engineers as well as for maintenance personnel in the utility. With the introduction of communication in an SA system, basic data communication know-how for a field user was required. With the introduction of IEC 61850, the major principles of IEC 61850 such as the data model and functional representation in logical nodes (LN) must also be known. The same applies for using ethernet and switches. In any case, the maintenance engineer needs to be trained in relevant techniques to isolate and fix problems in a structured way. Engineering and testing tools can help fulfill the related new requirements, but a tool does not replace the know-how of an engineer. The main objectives of the tool must be to facilitate the configuration process, address system complexity, and provide the required information at a practical level. An IT and communication (ITC) specialist is not needed for every project, but rather a substation engineer with all his skills. The ITC expertise is embedded in the tools.

CONCLUSION On one hand, IEC 61850 allows the combination of system components from different vendors within one SA system with enhanced and distributed functionality and a complex interaction between these components. On the other hand, IEC 61850 supports the simplification of related configuration, testing, and maintenance activities by providing SCL used by tools in all phases of the testing life cycle. To ease the handling of software updates and

K. P. Brand, T. Maeda, P. Owen, W. Wimmer, Requirements for Different Tools Over the Life Cycle of IEC 61850-Based Substation Automation Systems, Cigre B5.PS119, 2011 Michael Obrist is the Global Product Manager for Software Tools within Substation Automation at ABB Switzerland Ltd. Michael has spent nearly 20 years at ABB working across R&D and product management within substation automation. His work has focused on developing simple-to-understand software tools and technologies that help customers see the unseen from a new perspective. Stephan Gerspach is the Systems Architect for Products and Tools at ABB Switzerland Ltd. He is responsible for the compliance of the substation automation product portfolio to the requirements from an SA System perspective. Stephan has more than 18 years of experience in the substation automation domain after working various positions in project execution, product verification and validation, and system architecture. He is an active member of the UCAIug IEC 61850 Testing Subcommittee. Klaus-Peter Brand is part of the small team introducing Substation Automation in BBC/ABB Switzerland. The co-author of the “Substation Automation Handbook,” Klaus-Peter is a board member of the Cigre SC B5 and is an IEEE Fellow. With the beginning of the development of IEC 61850, he became a member, TF leader, and editor in the IEC TC57 WG10. He is also a consultant and teacher in the ABB University Switzerland.

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CONDITION MONITORING: AUTOMATING RESPONSE NETA World, Winter 2016 Issue

Tony McGrail, Doble Engineering Company Condition monitoring can provide up-to-the-minute, real-time information about the status of key substation assets. It can be a great benefit to organizations — but only if we plan ahead and respond automatically to issues. Figure 1 is an example of what useful condition-monitoring data can look like. It shows the variation in online bushing leakage-current magnitude readings for a generator step-up (GSU) transformer over the course of a week. Fig. 2: Rapid-Onset Failure Mode

DEFINING THE RESPONSE PLAN

By itself, the data is quite revealing, showing the variation in applied voltage on the bushing as cycles appear and sudden changes reflect the altering tap positions. The data reflects not only the status of the bushing, but also the status of the system, resulting in a daily variation of several percent in current magnitude.

When setting alarm limits, also consider the response and action plan: who must be notified, what steps need to be taken, and when. Two of the documented saves for rapid-onset failure of bushings occurred as the bushing owners had a systematic plan in place — and then followed the plan. Bushing monitors were applied to a large population of bushings with suspected failure modes involving the deterioration of insulation under voltage stress and subsequent degradation of dielectric performance. Limits were set based on the leakage current magnitude with an expectation that if the bushing failure mode were in operation, the leakage current would rise. Limits on information being a small percentage above nominal and higher level alerts for warning and action were also in place.

How do we use this type of data to set an alert or alarm to indicate a possible problem? Usually, we look at thresholds, or limits, and see if the data has exceeded such a limit. Keep in mind that there may be several such limits.

For each alert level, a response plan was put in place. At low level, a planned investigation in a timely manner; for a top level alert, the transformer would be switched out within two minutes and a test crew sent to perform offline tests to confirm condition.

A slightly more advanced approach is to look at trends to detect a continued rising trend. These approaches certainly allow for detection of variation in the readings, but they will require interpretation: Is the cause of an alert the bushing or is it the system?

The response to each alert was agreed, detailed, and approved as a written policy document within the company’s documentation system by operations, engineering, and management.

Analysis of data may require time, and we may be precious short of it after an alarm comes in. How much time we have depends on the failure mode encountered. Some bushings, for example, tend to fail gracefully over the course of several weeks to months, while others may fail with a rapid onset over a few hours, as in Figure 2. Our response has to be commensurate with the timescale of the failure mode, or we will miss an opportunity to act. We must understand the asset being monitored, the monitoring methodology, the resulting data, and the expected variation should a failure mode be in operation.

THE PLAN IN ACTION

Fig. 1: Variation in Bushing Leakage Current

When a bushing generated a high-level action alert, the action plan was followed, with offline testing confirming the condition of two suspect bushings on two separate occasions. The forensic teardown showed that deterioration was advanced; maybe a few hours separated the bushing from catastrophic failure and tens of millions of dollars in consequential losses. The key was to have an automatic response: a failure mode identified, actions planned, actions followed, and saves made.

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Protective Relay Vol 1 READING THE DATA

REFERENCES

Condition monitoring can provide information related to many parameters: dissolved gases, moisture, operational data, or partial discharge. In many cases, a monitored parameter can show dramatic changes. Figure 3 shows a number of large changes in the single-value dissolved gas analysis (DGA) level associated with a unit transformer. The monitor type gives an aggregate representation of several of the key gases; variation in the response could be caused by variation in the level of any of the key gases. In the data shown, the variation may be <50 percent in the course of an hour or two.

Ken Wyper, “Condition Monitoring in the Real World,” International Conference of Doble Clients, 2013.

Fig. 3: Cyclic Variation in DGA The changes are dramatic and by an amount that is a cause for concern. However, the variation is also cyclic, corresponding to load on the transformer, which was cyclic and reached different levels on different days. The generation of gas reflected the load on the transformer, with rapid gas generation and slower subsequent gas loss from the oil. How would we plan for such variability? The DGA level by itself is a reflection of the transformer condition as well as the transformer load. A response must take into account both factors: We must plan ahead and work out the expected response based on the level of load change and the level of DGA variation. This approach is much less common in substation monitoring where single-parameter analysis prevails. An automated response has to look at both factors, such as the setting of alerts based on a rise in DGA that does not correspond to a rise in load. And a plan: What action will be taken when an alert comes in? A low-level alert may trigger a review of available data; a high-level alert may trigger an oil sample and analysis if it can be done safely. In either case — with due reference to safety — a written procedure helps clarity of action when an alert comes in.

CONCLUSION To gain benefit from condition monitoring, we should understand the monitoring system and the parameter being monitored, specifically in the context of operational variables such as load. Failure modes identified should be understood, and an automated response should be agreed and acted upon in a timely manner.

Tony McGrail is Doble Engineering Company’s Solutions Director for Asset Management and Monitoring Technology, providing condition, criticality, and risk analysis for many organizations. Previously, Tony spent more than 10 years with National Grid in the U.K. and the U.S. In the U.K, he was a substation equipment specialist, with a focus on power transformers, circuit breakers, and integrated condition monitoring. In the U.S., he took on the role of substation and distribution asset manager, identifying risks and opportunities for investment in infrastructure.

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EVALUATING DIGITAL RELAY TESTING STRATEGIES NETA World, Fall 2016 Issue Brian Cronin, CSA Engineering Services, LLC Look at a sales brochure, or even an instruction manual, for many relays available today and you’ll find only a small portion of it dedicated to protection. Much of what you’ll find is dedicated to the integration of the device into the power system so it can replace what was previously performed by a myriad of devices. Metering, monitoring, and control features allow for significantly more functions than the predecessor to the modern digital relay. These additional features are part of the digital relay and can be used to remotely control and monitor portions of a system. To implement these remote features, the relay must be incorporated into a communications system, which requires the selection of appropriate network architecture. In addition to the remote control and monitoring, one incredibly powerful feature of the digital relay is its ability to record and evaluate system events. Recorded data can also be used to aid in operations. Many of these devices require a significant number of settings to take advantage of these features and often times these ancillary elements may be overlooked. The ANSI/NETA Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems, 2013 Edition, identifies various methods to inspect and test microprocessor-based relays. These procedures identify the recommended methods for testing the protective functions, inputs, and outputs associated with digital relays; however, many of the functions available in the digital relay requiring testing are not included in these specifications. Testing of metering and the relay logic are indicated in this standard, although no specific methods are identified. Perhaps the accuracy of additional features such as fault recording and display data does not seem apparent; however, when properly used, these features are extremely helpful in evaluating events. As with any product class, the functions and features of digital relays will vary between manufacturers and even within the varying product lines of the same manufacturer. Some digital relays have built-in features, which cannot be altered by the end-user; other digital relays allow the user to create an incredibly complex scheme to meet the user’s specific requirements. A relay will require settings for each protection element, and its output must be identified. Some schemes will require additional elements or logic (Figure 1) to implement the complete function of the relay, so either the manufacturer’s logic is enabled or the user must create their own logic to implement the required functions. In addition to the protective settings, many modern digital relays require settings to drive the relay target, initiate event reports and fault recordings, and transmit data to report

the event. (Figure 2) There is no consensus on whether and how these additional features should be tested. When the digital relay is used as a remote control and monitoring unit, these features must also be incorporated into the test plan.

Fig 1: Logic Diagram for Programmable Functions Testing a digital relay is performed to determine whether its desired functions will operate when required. Since there are typically multiple functions used in a digital relay, multiple tests are typically performed. These tests are generally approached as if the various elements were discrete components and the individual elements are evaluated; however, it is not always possible to isolate the elements in a digital relay. A simple example is a three-phase overcurrent relay having a neutral element. When testing the phase element for pickup or time, the neutral element will typically operate because the simulation of a single-phase fault causes zero sequence current to flow and the neutral element will respond. In many test environments, the neutral element is turned off for the phase testing and turned back on for the neutral testing. When testing multiple functions includes changing settings throughout the testing, it is possible to inadvertently leave the element in the off position. A different approach may be to test the element using analog quantities that don’t produce the pickup of other elements. In this example, a three-phase test set can be used to generate a pickup on the phase under test and the return current split between the remaining two phases. This sort of strategy may save the time of changing a setting and will avoid the risk of not returning a setting to its proper value.

Protective Relay Vol 1 An alternate method used to test multifunction relays is to map the element under test to a spare output and test it in isolation (Figure 2). When isolated, the element can be tested without being affected by other elements in the relay. This type of testing may allow for testing of every aspect of the element to ensure the relay performs as expected; however, it does not prove the relay is working properly at the correct output. At a minimum, a time overcurrent relay will require a setting for its pickup, its time delay, and its characteristic curve. It would be extremely unusual for a properly functioning digital relay to not operate correctly given a proper setting, so the only purpose achieved by isolating a protective element to a spare output is to test the relay algorithm. Unless there are multiple analog-to-digital converters in the relay (for example, one for low levels of current [load] and one for high levels of current [fault]), the conversion will remain within the accuracy of the specification.

Fig. 2: Relay Block Diagram Depending on the purpose of the test, acceptance testing may have different meanings to different people. To some, acceptance testing is to run a rigorous set of tests to ensure all functions of a relay will perform at extremes — testing the operation of the algorithms. To others, acceptance testing may simply imply testing to verify the relay operation at defined points. When field testing digital relays, it should be sufficient to verify the settings without testing the various relay algorithms. For example, a three-phase overcurrent relay should not have to be tested for every type of fault (i.e., A-B-C, A-B, B-C, C-A, A-N, B-N, and C-N). All of these faults will respond to the same settings; testing any type of these faults will determine if the pickup, time delay, and characteristic curve are correct. The only remaining function would be to determine whether the individual input filtering and the analog-to-digital converters are operating correctly. Testing specifications of an overcurrent relay require a test for the pickup and two test points of the overcurrent relay. It does not indicate the extent to which testing should be done. Can testing be limited to two points on one phase and one point on the remaining phases? The two points verify pickup, time delay, and characteristic curve. The other phases test the analog input — the input filtering and the

101 analog-to-digital converter. However, although not clearly indicated in the specification, testing should not only verify the proper relay output operates, it should also verify that the target information and event recordings operate properly for the individual tests. Is it necessary to test the protection algorithm of a standard product or should an acceptance test simply verify the proper setting was applied? Without question, it is necessary to test usercreated logic. Some manufacturers have protection algorithms that prevent simple test methods from being used because the algorithm expects to see a condition to occur over time — a real-world condition — which cannot be generated using simple test methods. Some relays, for example, can evaluate a loss of voltage as a fuse or PT failure. This feature can be used to block certain voltage-based protection functions. If this is an internal feature provided by the manufacturer, should it be tested? If it can be switched off to effect protection, it should be tested with the elements. For example, if an electro-mechanical loss of excitation relay were used to protect a generator and its operation was supervised by an electro-mechanical voltage balance relay, the two relays would be tested individually and the complete trip path would be tested separately. In a digital relay, a supervising feature similar to a voltage balance relay may have to be switched off because it will make testing difficult, if not impossible, without sophisticated test methods. Since the purpose of testing the relay is to evaluate its performance, oscillographic recordings could capture the simulation of the element and its block by the supervising component, which can be used to prove the relay performed correctly. Since a feature of the digital relay is its ability to capture the event, specifications should exist to identify that it is tested and working properly. Many digital relays require the user to identify the various conditions that should be used to trigger events or waveform capture (Figure 3).

Fig 3: Voltage Disturbance from Relay Oscillography Where user modifications are required as part of the relay settings, anything affected by these settings should be tested. Some may consider these settings part of the relay logic. Even though the relay logic is to be tested, I have yet to see a test report indicating that the event record or waveform capture operate properly. Tests performed on protective elements are performed on a per-phase basis but, unless the event is triggered on a per-phase basis, there is no reason to test these event records on a per-phase basis. There is good reason to verify individual elements are recorded in the various records. When

102 evaluating a fault, all conditions associated with the event should be included, or the evaluation of the event may be misleading. Protective elements, analog signals, inputs and outputs, and other intermediate logic are extremely useful in evaluating events, so proper operation of these recordings must be validated. Other functions, such as when the digital relay is being used as a remote control and monitoring device, also require testing to ensure these functions are proper and should be integrated into the testing plan. Does a coordination study really provide the information required to set a digital relay? Studies may identify the protection elements and the required outputs; however, most do not indicate the target and event record data. Upon review of most digital relay manuals, the testing section is sparse. For the most part, it seems the manufacturer’s position is clear: The relay will function properly if it is set properly, given no internal alarms have been detected, and the analog conversion is functioning properly. It is often difficult to determine how to properly set a digital relay without testing it based on the lack of data provided in some of the instruction manuals. A coordination study often does not convey the finer points required in the setting of the relay, such as the minimum trip time or the unlatch settings. Often, the test technician is deemed responsible to determine the appropriateness of the settings, as the default settings will not always be an appropriate choice. ANSI/NETA ATS calls for downloading the setting file and comparing it to the coordination study. With so many required settings not included in the study, it is strongly recommended that this review be completed not by the technician, but by the person responsible for issuing the relay settings. Review by additional personnel will typically be more exhaustive. At the extreme end, if a complete setting file is provided without significant direction, it is difficult to determine the desired functions of the digital relay. So what should be included in an acceptance test of a relay? If the relay is treated as a collection of individual items in a singular device and the acceptance test includes the testing of these, individual testing should include the following items: ●● Verification of all metering functions ●● Verification of required protection elements ●● Verification of required inputs ●● Verification of required outputs ●● Verification of device targets ●● Verification of event records ●● Verification of protection logic (including its interaction with internal and external elements) Generally, acceptance testing exists in a vacuum, and it is not until systems are commissioned that the device integration into a larger system is evaluated. A digital relay is truly a small system and must be tested as such. ANSI/NETA ATS calls for testing of pilot schemes and in-service monitoring. These are tests that can

Protective Relay Vol 1 only be performed when other components are in service. Instrument transformers, external contacts, coils, and other devices must be tested with the digital relay as part of its system, and its testing should be as detailed as the acceptance testing. The digital relay should be tested using a method that closely represents the system that it is intended to protect and the conditions it will be expected to withstand. It should also be tested for all functions and features it is expected to perform. The ANSI/NETA, Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems, 2015 Edition, provides good direction on developing complete testing protocols to ensure the digital relay system will provide its intended function. Brian Cronin, PE is the President of CSA Engineering Services, LLC. and has extensive control and protection engineering experience, both as a Senior Protection Utility Engineer for a privately owned electric utility and as a field applications engineer/ business development manager for a major OEM. Mr. Cronin holds a BEE from Manhattan College, an MBA from New York Institute of Technology. Additionally, he is a registered professional engineer, a member of the NYC Electric Code Interpretation Committee, a member of IEEE, and a member NFPA.

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GOING BEYOND AUTOMATED RELAY TESTING: USING POWER SYSTEM MODELS NETA World, Summer 2016 Issue Steve Turner, Beckwith Electric Company, Inc. Automated testing is often used to test protective relays, but special cases exist that cannot be adequately covered. This article presents three examples that illustrate how to test protection functions using simple model power systems and symmetrical components. Model power systems calculate test signals that are equivalent to the actual steady-state fault conditions when precise test signals are required. The ability to calculate test signals rather than solely relying upon software is a valuable skill for testing protective relays. The three examples given are: ●● Zigzag transformer inside transformer differential zone ●● Sensitive ground directional overcurrent protection for ungrounded systems ●● Directional power for intertie protection

ZIGZAG TRANFORMER INSIDE TRANSFORMER DIFFERENTIAL ZONE The first example demonstrates how zero-sequence current elimination is applied for transformer differential protection. A shunt-connected zigzag transformer provides a zerosequence current sink for ungrounded systems by establishing a connection from ground to neutral (Figure 1). During ground faults, zero-sequence current (I0) flows up through the neutral of the zigzag transformer. By applying the zigzag transformer as a ground source, it is now simple to apply non-directional overcurrent protection for the detection of single line-to-ground faults. If the system is left ungrounded, very low current is produced on the faulted phase during single line-to-ground faults, due only to the capacitance-to-ground of the unfaulted phases. Conventional ground over-current protection is useless. A zigzag transformer consists of three 1:1 ratio transformers. Each leg of the zigzag transformer consists of two windings that are 120 degrees out of phase. Windings are wound around the core such that zero-sequence current flows through the bank when system unbalance exists (i.e., ground fault). Only exciting current flows through a zigzag transformer during balanced system conditions; positive- and negative-sequence current cannot flow since they are 120 degrees out of phase. The grounding transformer appears as the leakage reactance of the core during a ground fault.

Fig. 1: Zigzag Transformer Three-Line Diagram A grounding resistor is sometimes used to limit ground faults to lower levels than with the zigzag transformer solidly grounded. Typically, the zigzag transformer is sized such that its impedance is 100 percent on its own base; 400 amps primary is the 10-second rating commonly applied throughout the United States. If the zigzag transformer is located inside the zone of transformer differential protection, as in the delta-connected windings shown in Figure 2, then the zero-sequence current contribution during external ground faults must be eliminated or a misoperation can occur. Here is one method showing how numerical transformer protection relays can reliably remove the ground current.

Fig. 2: Ungrounded System with Zigzag Transformer for Ground Current

104 Zero-Sequence Current Elimination (Figure 2)

Protective Relay Vol 1 Zigzag Transformer Impedance Model and Symmetrical Component Calculations Figure 5a shows the zero-sequence model for the zigzag transformer. Note that it does not appear in either the positive- or negative-sequence networks.

The currents shown above are taken directly from the CT secondary and have been divided by the tap setting for the delta winding to convert them into per unit. If zero-sequence current elimination is selected (Figure 3), then the numerical relay calculates the ground current as follows:

IA’, IB’ and IC’ are the internally compensated currents:

Fig. 5a: Zigzag Transformer Zero-Sequence Impedance Model Figure 5b shows the symmetrical component diagram for the two-winding wye-delta transformer with the zigzag transformer connected to the delta side. Note that the load is connected wye and solidly grounded at the neutral. The CTs for the delta side are shown as well. ZT is the impedance of the two-winding wye-delta transformer, and ZZig is the impedance of the zigzag transformer. The zigzag transformer provides 400 amps primary during a ground-fault current when the system is unloaded.

Fig. 3: Zero-Sequence Current Elimination (Relay Settings) Figure 4 shows the transformer differential operating characteristic. Point A is the filtered operating point for an external ground fault, and Point B is unfiltered.

Fig. 5b: Symmetrical Component Diagram Fig. 4: Transformer Differential Operating Characteristic Note that custom settings that properly account for the phase shift can also be used for this application.

Figure 5c shows the ground-current distribution for a single phase-to-ground fault. Note the current magnitudes are normalized to the total zero-sequence current (3I0).

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Fig. 6: SEF Pickup Setting Range Figure 7 illustrates how the operating current is commonly measured for distribution feeders. Note that IG is the ground current input. A toroidal CT is also used but is only applicable at lower voltages since all the phase conductors must pass through the center opening. Fig. 5c: Ground Current Distribution Figure 5d shows the base values and impedances used for this particular example.

Fig. 7: SEF Current Input Figure 8 shows a single line-to-ground fault on a distribution feeder supplied via an ungrounded wye winding. The power system is grounded through the total stray capacitance to ground (XC0g).

Fig. 5d: Base Values and Impedances (Mathcad)

SENSITIVE GROUND DIRECTIONAL OVERCURRENT PROTECTION FOR UNGROUNDED SYSTEM The first example was for an ungrounded power system grounded via a zigzag transformer. Remember, as stated previously in regards to an ungrounded power system: If the system is left ungrounded, high magnitude voltage appears on the unfaulted phases during single line-to-ground faults and conventional ground-overcurrent protection is useless due to the very low magnitude ground current. It is possible to protect the feeders for single line-to-ground faults using sensitive-earth-fault (SEF) protection. SEF protection can detect ground-fault current in the order of milli-amps secondary. Figure 6 shows the pickup range for an SEF element. If the CT ratio is 100:5 then the range in primary is 0.5 to 20 amps.

Fig. 8: Single Line-to-Ground Fault on Ungrounded System Directionality makes SEF secure since ground current flows in the unfaulted phases for the non-faulted feeders as shown in Figure 9a.

106

Protective Relay Vol 1 the fault resistance until the ground fault current is equal to the minimum pickup setting to test the maximum sensitivity of the SEF protection. Figure 10 shows the symmetrical-component zero-sequence network.

Fig. 9a: Ground Current in Unfaulted Feeder(s) Figure 9b shows the SEF directional operating characteristic. The maximum torque angle between the zero-sequence voltage and ground current is 90 degrees leading, since the voltage drop behind the relay in the zero-sequence network is across the total stray capacitance to ground (XC0g).

Fig. 10: Zero-Sequence Network

DIRECTIONAL POWER FOR INTERTIE PROTECTION The last example demonstrates how to calculate test signals for directional power protection (Figure 11). Note that this type of protection typically operates on real power (W). Power protection may be useful to detect the loss of utility supply, depending upon the size of the distributed generator (DG) and its load, feeder load, and the local utility import/export restrictions. Forward power is defined as power exported from a DG to a utility. Reverse power is defined as power imported by a DG from a utility.

Fig. 9b: SEF Directional Operating Characteristic Calculate the ground fault current (Ig) as follows: Ig = 3I0 Where:

Fig. 11: Directional Power It is convenient to set the pickup in per-unit (PU) based upon the numerical relay nominal power. The choice of the base PU is typically taken from the kVA rating of the interconnection transformer, the DG aggregate generating capacity, or some other value agreed upon by the DG and the utility. Normalized PU power flow measurements are based on the Nominal Voltage and Nominal Current setting, as shown in Figure 12.

f = nominal frequency Cg = total stray capacitance to ground RF = ground fault resistance Note that the impedance of the distribution feeder can be ignored since the impedance of the stray capacitance is so high. This calculation does not take any load into account. You can increase

Fig. 12: Relay Configuration

Protective Relay Vol 1 Use the forward over-power function to limit the amount of power flow into the utility if the DG is allowed to supply power to the utility (export). Use the reverse under-power function to ensure that the DG is importing a minimal amount of power from the utility for peak shaving applications when no export of power from the DG to the utility is allowed.

Nominal Power Here is how one particular numerical relay internally calculates the nominal power (Pnom): VT Configuration

Line-Ground (L-G)

Nominal Power = 3•Vnom•Inom VT Configuration

Line-Line (L-L)

Nominal Power = 3•Vnom•Inom

Pickup Setting Suppose, for example, the utility requires that the directional power (32) elements trips at 50 kW primary. VT Ratio = 4160/120 = 35 (Open Delta) Vnom = 120 volts L-L CR Ratio = 400/5 = 80 (Wye) Inom = 5 amps Note: The values above were arbitrarily selected but are typical. ●● Pickup = (50 kW)/(VTR•CTR) = 18 watts secondary ●● Pickup = (18 watts)/( 3•120V•5A) = 0.02 per unit

Maximum Sensitivity The maximum sensitivity required is calculated as follows: Inom·Pickup = 5 A·0.02 = 100 milli-amps

CONCLUSION To summarize, there are several ways to test protection functions using simple model power systems and symmetrical components. Model power systems calculate test signals that are equivalent to the actual steady-state fault conditions when precise test signals are required. The ability to calculate test signals rather than solely relying upon software is a valuable skill for testing protective relays.

REFERENCES Beckwith Electric, M-3410A Intertie Protection Instruction Book, pp. 3-14.

107 Steve Turner is a Senior Application Engineer at Beckwith Electric Company, Inc. He has more than 30 years of experience, including working as an application engineer with GEC Alstom for five years, primarily focusing on transmission line protection across the United States. He was an application engineer in the international market for SEL, Inc., again focusing on transmission line protection applications including single pole tripping and series compensation around the world. Steve wrote the protection-related sections of the instruction manual for SEL line protection relays, as well as many application guides on various topics such as transformer differential protection, out-of-step blocking during power swings, and properly setting ground distance protection to account for mutual coupling. Steve also worked for Duke Energy (formerly Progress Energy) in North Carolina, where he developed a patent for double-ended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Texas A&M Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and serves in the IEEE PSRC.

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Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

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122

missouri 114

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117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

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new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

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HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

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148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

182

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184

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189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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200

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

206

207

208

209

210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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244

Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

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ANDBOOK

VOLUME 2

SERIES III

PROTECTIVE RELAY

PROTECTIVE RELAY Vol. 2 HANDBOOK

SERIES III

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PROTECTIVE RELAY VOLUME 2

HANDBOOK

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InterNational Electrical Testing Association

PROTECTIVE RELAY–Vol. 2 HANDBOOK TABLE OF CONTENTS A Practical Approach to Line Current Differential Testing......................................... 5 Karl Zimmerman, David Costello

Why Apply Protective Relays?........................................................................... 15 Karl Zimmerman

Why We Should Measure Line Impedance?........................................................ 22 W. Knapek, U. Klapper

Basic Transformer Differential Protection............................................................. 27

Jay M. Garnett

Current Transformer Saturation and Residual Magnetism....................................... 34 Will Knapkek

How Disruptions in DC Power and Communications Circuits Can Affect Protection... 38 Karl Zimmerman, David Costello

Energy-Based Tripping and Its Effects on Selective Coordination ........................... 48 John Carlin

Microprocessor-Based Relays: Out with the Old, in with the New.......................... 54 Dennis Moon

Evolution of Power System Protection Testing....................................................... 55 Ed Khan

Modern Advances in Testing Multifunction Numerical Transformer Protection Relays............................................................................ 61 Steve Turner

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Moving from Element Testing to Protection System Testing...................................... 68

Christopher Pritchard

Electrical Commissioning for Improved Availability, Safety and Cost Savings........... 72 Michael Donato

IEC 61850 – A Tale of Two Decades................................................................. 75 Joseph Menezes

Protective Relay Misoperations and Analysis....................................................... 76 Steve Turner

The Future of Integrated Power and Process Automation....................................... 79 David C. Mazur, John A. Kay

Using Test Plans as a Tool for Protection Testing Specifications............................... 85 Benton Vandiver

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Protective Relay Vol. 2

A PRACTICAL APPROACH TO LINE CURRENT DIFFERENTIAL TESTING PowerTest 2014 Karl Zimmerman and David Costello, Schweitzer Engineering Laboratories, Inc.

ABSTRACT

REVIEW OF MODERN 87L PROTECTION

Line current differential (87L) protection of transmission lines is preferred because of its speed, sensitivity, security, and selectivity. 87L scheme performance is dependent on reliable communications, because measured currents from all terminals must be communicated and time-aligned. Several misoperations due to channel problems and noise led to the implementation of disturbance detectors and watchdog counters to increase scheme security in newer relay designs. While these features increase security, they can complicate testing and led to the implementation of “test mode,” the ability to simplify 87L testing while bypassing some of the relay security logic. Practical testing recommendations are presented in this paper. Several common 87L testing scenarios are discussed, including single-relay tests using loopback communications, single-relay tests of the operating and restrain characteristics of the relay using test mode, multiple-relay tests of the characteristics and channel using test mode, and multiple-relay tests of the characteristics and channel without test mode where real-world conditions are simulated.

Digital 87L systems are popular for a number of reasons. As with any differential scheme, 87L systems offer sensitivity, security, and selectivity. These systems provide fast and simultaneous fault clearing for faults located anywhere along a protected transmission line. Fig. 1 shows a one-line diagram of a typical two-terminal 87L scheme.

INTRODUCTION Line current differential (87L) protection is applied on long and short lines and on various voltage levels. Because the relays are located independently at each terminal of a line, 87L schemes depend on reliable communications to exchange and align the currents. Modern 87L schemes account for actual power system conditions more than their predecessors by implementing security improvements such as local and remote disturbance detection, watchdog counters, advanced time alignment and fallback methods, line charging current compensation, and external fault detection. Some of these advancements affect 87L scheme testing by making it necessary for engineers and technicians to apply system conditions that more closely replicate power system conditions or, in some cases, to use a “test mode” for testing certain functions. This paper presents some practical recommendations for testing 87L schemes. Several single-ended and multi-ended scenarios are discussed, including multi-ended 87L scheme testing where real-world conditions are simulated.

Relay

Bay 1 Bay 2 Digital Multiplexer

Dedicated Fiber Hot Standby Channel

Bay 1 Relay Bay 2 Digital Multiplexer

Fig. 1: Two-Terminal Digital 87L Application. 87L systems are applicable to both long and short lines and are a good solution for complicated applications, such as seriescompensated lines, multiple-terminal lines, and lines with zerosequence mutual coupling. They perform well for evolving faults, intercircuit and cross-country faults, internal faults with outfeed, current reversals, and power swings. Typical challenges for these systems include line charging current, in-line and tapped transformers, and current transformer (CT) saturation during external faults 1. Also, these systems require a reliable, highcapacity, low-latency communications channel and must reliably time-align currents sampled at remote terminals in spite of channel noise, delays, and asymmetry 2. Traditional current differential schemes use a percentage restraint characteristic. Operate, or difference, current is calculated as the magnitude of the sum of the terminal current phasors. Restraint current is a measure of the terminal current magnitudes and, depending on design, could be the sum of the terminal current magnitudes, the average of the terminal current magnitudes, and so on. The differential relay traditionally operates when the operate current exceeds a percentage of restraint, as determined by a slope setting. A limitation to this design is that sensitivity and security are inversely proportional. The slope-based characteristic increases security for higher restraint values by lowering sensitivity. Security can be increased by manipulating the restraint values and slope characteristics.

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Protective Relay Vol. 2

Reference 1 introduced the original concept of a digital 87L principle that used a restraint characteristic implemented in the Alpha Plane. The Alpha Plane is a current-ratio plane (see Fig. 2).

Im(k)

Restrain

•B loc

kin

g

An g

le

Im(k)

2

Re(k)

1/

Restrain Operate

–1

Ra d

Re(k)

Ra d

ius

–1

Operate

1/

Ra d

ius

An

ius

gle

Fig. 3: Generalized Alpha Plane.

Fig. 2: Alpha Plane. The ratio of remote terminal current to local current is plotted on the Alpha Plane. Ratios that lie within the restraint region prevent the differential element from operating. This characteristic responds well to phase alignment errors by explicitly looking at the angle difference between the local and remote currents. Sensitivity is further controlled by a separate comparison of operate current versus a minimum sensitivity setting. Sensitivity is further enhanced by the presence of zero-sequence and negative-sequence elements, in addition to segregated phase elements 3. Reference 4 introduced an enhanced generalized Alpha Plane method. The generalized Alpha Plane develops two equivalent currents, IL(EQ) and IR(EQ), that produce the same operate and restraint as any number of original terminal current phasors. The ratio of smaller current to larger current is always plotted; thus, the ratio on the generalized Alpha Plane always has a magnitude of one or less. Because the Alpha Plane is symmetrical, all ratios are reflected to positive angles in the first and second quadrant (see Fig. 3). IL(EQ) and IR(EQ) themselves are composite signals, made up of operate and restraint values, as shown in (1).

IL(EQ) =

(

(

Im(Ix)2–[IRST –Re(Ix)]2 +j•Im(Ix) •1 β 2•[IRST–Re(Ix)]

IR(EQ) = (IRST – |IL(EQ)|) •1 β

(1)

This generalized Alpha Plane allows for manipulation of the operate and restraint values to improve security and performance. The difference current can be reduced after compensating for line charging current, improving relay sensitivity. The restraint current can be increased, for example, during in-line or tapped transformer energization, improving relay security. Ix is the difference phasor, rotated by a reference angle β. The reference angle β is chosen so that IR(EQ) sits at 0 degrees, eliminating one unknown. β is chosen by determining which terminal current has the longest projection on, or is most in phase with, the difference current. To accommodate CTs with different nominal ratings, the generalized Alpha Plane relay automatically calculates taps and performs difference calculations in per unit. The original Alpha Plane-based relay used secondary amperes normalized to the local relay nominal rating and the highest CT ratio within the differential scheme. The generalized Alpha Plane relay also employs an external fault detector that uses raw samples to determine if a fault is external to the zone of protection within one-quarter of a cycle. Once an external fault is detected, the relay switches automatically from normal to more secure settings, improving security in case a CT saturates during the external fault. Further, for data alignment, a traditional ping-pong method is used for symmetrical channels. However, the generalized Alpha Plane relay employs Global Positioning System (GPS) satellite time, wide-area terrestrial time from an integrated communications optical network, or a well-established fallback time source to improve data alignment with asymmetrical channels. As technology has advanced, relay designs have been improved and enhanced. With these enhancements have come changes in testing practices. For example, overcurrent schemes are now combined with light sensing for arc-flash protection, so we must use current and light together for testing 5. Bus and transformer differential relays now automatically switch to a higher percentage

7

Protective Relay Vol. 2 slope setting for better security during external faults, so we must apply dynamic state simulations to precisely test the higher slope setting 6. Similarly, technology advancements have been introduced in 87L elements.

contact, and logs an entry in the sequence-of-events record. In rare cases, SEUs can cause a change of state in an element that produces a trip, like that shown in Fig. 4.

Some of these advancements have led to improvements in the security of the 87L performance and with it, changes in the approach to testing. As we see in the following section, 87L elements have proven to be more secure, on the average, than most protection schemes. Still, we evaluate several system events to root cause to show why we wish to further improve 87L security.

87L PERFORMANCE WITH CASE STUDIES The rate of total observed undesired operations in numerical relays is extremely low, 0.0333 percent per year (a failure rate of 333 • 10–6). By comparison, relay application and setting errors (human factors) are 0.1 percent per year (a failure rate of 1,000 • 10–6) 7. The rate of total observed undesired operations in 87L schemes is even lower, 0.016 percent per year (a failure rate of 160 • 10–6). If disturbance detection (described later in this paper) had been applied in all cases, this number would drop even lower, to 0.009 percent per year (a failure rate of 90 • 10–6). Some of these undesired operations were due to single event upsets (SEUs) 8, sometimes called soft memory errors, in relays. Diagnostics have greatly improved and reduced these errors in the last several years. The rate of observed 87L undesired operations due to channel problems is less than 0.002 percent per year (a failure rate of 20 • 10–6). Had disturbance detection been applied in all cases, this number would drop even lower, to less than 0.0005 percent per year (a failure rate of 5 • 10–6). All this is to say that protective relays are very secure. Still, every undesired operation is cause for concern and drives efforts to identify, measure, and improve. In the following discussion, we analyze three actual events that produced an undesired 87L operation.

Fig. 4: 87L Asserts for an SEU.

Case Study 2: 87L Misoperation Due to a Channel Problem With Disturbance Detector Disabled In the system event shown in Fig. 5, the channel experiences a degradation of the output of one of the optical fiber transmitters used in the 87L scheme. We can observe the ROKX bit chattering (it should be solidly asserted). Eventually, bad data (erroneous remote current IBX) make it through error checking to cause an undesired 87L operation. In this case, disturbance detection was disabled. If it had been enabled, the 87L element would have been prevented from tripping instantaneously, and the undesired operation would have been avoided. Early 87L relays had a setting to enable (or disable) disturbance detection at the local terminal. Newer relays use disturbance detection at all terminals by design.

Case Study 1: 87L Misoperation Caused by an SEU Fig. 4 shows an event where there was no apparent fault. In this case, 87L asserted and produced an undesired trip, and the root cause was attributed to an SEU, also called a soft memory error. An SEU is a temporary unintended change of state in a single memory location. Soft memory failures are transient, infrequent events occurring at a rate of about one per million memory-device operating hours. Such errors are caused by high-energy particles striking a memory storage capacitance and disturbing the charge stored at a particular location. These high-energy particles can come from high-energy cosmic rays or from the emission of alpha particles from impurities in some microcircuit packaging materials. Improvements in internal diagnostics and memory storage design have been implemented to reduce the occurrence of these events. Enhanced firmware now detects the soft memory error event, automatically resets the relay, pulses the alarm

Fig. 5: 87L Produces Undesired Trip During Communications Failure With Disturbance Detection Not Enabled.

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Protective Relay Vol. 2

Case Study 3: 87L Misoperates With Disturbance Detector Enabled In Fig. 6, an apparent communications error produces a trip condition. In this case, even with disturbance detection logic enabled, the trip was not prevented.

Disturbance Detection Supervision Even with powerful data integrity checks, additional security is needed because 87L schemes exchange so much data. For example, by sending packets every 4 milliseconds, a relay transmits and receives 7.884 billion packets per year. Even with a very small probability of an undetected error (1.2  • 10–10), a standing noise in the communications channel could possibly produce corrupted data and potentially an undesired 87L operation 11. As seen previously in Case Study 2, applying disturbance detection improves security. Typically, a disturbance detector (DD) looks for a change in measured current compared to the current one cycle ago (or within a similar window). Schemes can use the local data, or both the local and remote data, to supervise instantaneous tripping of an 87L element. Typically, the raw (unsupervised) 87L is allowed to trip without DD supervision after a short time delay (for example, two cycles). Fig. 7 shows disturbance detection logic using both local and remote (87DDL and 87DDR) data to supervise 87L trips as well as a received direct transfer trip (87DTT).

Fig. 6: Apparent Communications Error Produces 87L Misoperation With Disturbance Detection Logic Enabled. Monitoring the performance of the 87L scheme over time using advanced channel diagnostics and alarms is a method to secure the relay for such events, as discussed in the following section. In original designs, channel monitoring and poor channel performance could be ignored or missed by users. Watchdog counters now disable the 87L element for repeated close calls.

SECURITY IMPROVEMENTS

87DDL 87DDR

87DD

Raw 87L 2 Cycles

0 (To Trip Logic)

Raw 87DTT(RX)

0.75 Cycles

Data Integrity Check Noise in the communications channel can corrupt data. The term noise refers to such issues as interference coupled to the channel media or electronics, failing components used in the network, poor quality of fiber terminations and associated losses, and marginal power budget for fiber transceivers. In multiplexed networks, frame slips can corrupt the data. Noise is not necessarily a sporadic event. A failing component in the communications channel can create a persistent noise that is constantly threatening the integrity of the transmitted 87L data. Undetected errors can lead to 87L misoperation. Detected errors cause a temporary loss of dependability because the relay needs to flush the bad data or to resynchronize. Solutions include using a data integrity check, such as a Bose, Ray-Chaudhuri, Hocquenghem (BCH) code check. The security is based on the bit check resolution and packet size. For example, a 32-bit BCH code used on a 255-bit packet size secures the data so that the probability of undetected error is less than 1.2 • 10–10. 9, 10

87L

87DTT(RX)

0

Fig. 7: 87L Disturbance Detection Logic. Disturbance detection logic impacts testing in three ways. First, if DD uses local and remote data, a single-ended test is inadequate. The local 87L would always experience a time delay. Second, slowly ramping a current from a prefault to a fault value is inadequate. A step change in current (or voltage, if used) is realistic and required; otherwise, DDs will not assert. The relay would again trip with a time delay. Third, raw 87L operations without accompanying DD may eventually disable the 87L element due to channel monitoring and improved security. This will be discussed in more detail shortly. As we can see, to properly test an 87L element with disturbance detection, the test quantities must closely replicate an actual fault.

Watchdog Counters

9

Protective Relay Vol. 2 It may happen that the raw 87L element picks up due to noise but does not operate because it is initially stopped by the lack of disturbance (no sensitive DDs assert at the same time as the 87L operation). Afterwards, the 87L resets itself when the channel problem disappears. For this reason, it is important to log such events as close calls and incorporate logic that responds to unexpected and persistent events that impact the 87L function. This logic, called a watchdog counter, maintains the security of the 87L function by first alerting the user about significant channel issues through alarms to force rectification of the channel problems. Second, watchdog counters may inhibit the 87L function after a significant number of persistent events or close calls so that misoperations are prevented. Watchdog counters impact testing. If users insist on testing relay schemes with in-service settings and no special test mode(s), then the testing method must emulate actual power system conditions. If testing is not realistic, the watchdog counters log unexpected 87L events and eventually inhibit the 87L element during testing. Consider an analogy to loss-of-potential (LOP) logic in distance (21) or directional (67) element schemes. In the case of a failed voltage transformer (VT), VT wiring problem, or blown VT fuse, users can decide through relay settings whether to inhibit 21 or 67 elements, or both. Alternatively, the user may decide to simply leave the elements to operate based on unreliable voltages. In either case, the user may choose to alarm and call immediate attention to the problem. Similarly, the user must decide to enable or to disable 87L watchdog counter supervision to determine how the 87L element behaves if a communications channel is deemed to have had too many close calls.

Generalized Alpha Plane Increases Security for Advanced Requirements The generalized Alpha Plane is transparent for common two-terminal applications, while allowing the same principle to be applied to three-terminal (or x-terminal) lines by reducing the system to a two-terminal equivalent, as described in Review of Modern 87L Protection. Keep in mind, a two-terminal transmission line with dual breakers at each terminal is a four-terminal differential problem. Moreover, if applied on lines with charging current, the total charging current can be removed, bringing the balanced current closer to the ideal blocking point (1 per unit at 180 degrees). For applications with in-line transformers or any other case where higher restraint is required, harmonics can be added to the restraint, thus moving the Alpha Plane point closer to the ideal blocking point. By using external fault detection, the differential can be placed in a high-security mode—essentially increasing the Alpha Plane restraint region. Moreover, these principles can be applied on segregated phase, negative-sequence, and zero-sequence quantities alike.

Advanced Time Alignment

In addition to traditional channel-based data alignment using a ping-pong method, modern relays can use external time sources, if desired. These time sources are useful when applying 87L over a network that may experience asymmetrical channel delays. When high-accuracy GPS clocks are used, data can be synchronized without compensating for clock offset. This reduces concerns of channel asymmetry and channel switching because the time source is independent of the channel. Finally, if a time source is lost or degrades, schemes must have graceful fallback modes, so 87L integrity is maintained during any loss or degradation of the time source.

87L TESTING CONSIDERATIONS Purpose of Testing This section deals with considerations for testing the 87L element. Many papers on comprehensive test practices have been published. The content of this section is not intended to provide a complete discussion on testing. Rather, it deals with some specific issues related to, and methods of, testing 87L elements. Testers must comply with North American Electric Reliability Corporation (NERC) standards and manufacturer recommendations and use other good practices. These good practices include developing test plans and checklists, creating complete documentation, moving testing to the lab when possible, performing peer review, and improving training. There are different categories of testing—type or acceptance testing, commissioning testing, and maintenance testing 12. Type or acceptance testing is performed on a new relay make or model to qualify it for use on a given system. One important aspect of type or acceptance testing is to validate performance, such as speed, security, and sensitivity. Another aspect is to verify adherence to specifications, such as dielectric strength, output contact current interruption, shock, and vibration. Lastly, this type of testing serves to provide familiarity, proficiency, and training. Commissioning testing encompasses a wide range of goals. Commissioning tests verify, among other things, the correct installation and operation of the following: ●● Polarity, ratio, phasing, and grounding of ac signals. ●● Metering. ●● DC power supply. ●● Input and output wiring. ●● All communications (protection channels, supervisory control and data acquisition [SCADA], remote engineering access, security). ●● Relay settings and logic. ●● Application and documentation. In short, the goal of commissioning tests is to verify that the pro-

10

Protective Relay Vol. 2

tection system is ready to go into service. Further, proper commissioning certifies with 100 percent confidence that the protection system trips for in-section faults within a prescribed time and that it does not trip for out-of-section faults or nonfault conditions 13.

or disabling the 87L element altogether (87L enabled), putting the entire relay into test mode (relay test mode), or putting the 87L element into test mode (87L test mode). Independent control switches or test switches can be used for these purposes, too.

Maintenance testing is performed to supplement automated selftests, which extensively monitor the relay health. It is recommended that relay users perform the following actions:

87L Enabled or Disabled

●● Monitor self-test alarm contacts via SCADA systems and annunciators in real time, and investigate any alarms immediately. ●● Compare metering and input statuses between independent devices with automated systems. Investigate event and fault records to determine root cause and validate protection system performance, including output contact closure. ●● Perform minimal periodic testing to supplement automated self-testing and the practices above by validating inputs, outputs, and metering. In short, maintenance testing is performed to ensure that the protection system is still healthy and available 14.

Considerations When Testing 87L Schemes Many challenges must be addressed when testing an 87L scheme. 87L protection is inherently a distributed protection scheme with relays located at different line terminals, in most cases separated by considerable distance. While current differential schemes are ubiquitous, line 87L schemes are more complex because of the communications and data alignment requirements. We must consider how channel characteristics, multiplexers, and external clocks impact the data exchange between the relays. For example, channel noise can produce delayed operation, and asymmetrical delays can produce standing differential current. The testing requirements for an 87L scheme can be complicated. Supervising logic, including disturbance and external fault detection, channel status, and enabling control logic, secures in-service relays but can obstruct testing. Unfamiliarity with supervising logic can create contradictory or confusing results and lead the tester to waste time trying to determine root cause. One of the purposes of testing a microprocessor-based relay is to confirm that it has been configured correctly; therefore, the application of temporary settings changes should not be required for testing. Crews are required at multiple line terminals using GPS-synchronized test sets to perform complete system end-toend testing 15 16. Finally, we must consider the risks of testing lines that are in service, including human errors during testing that could potentially lead to undesired trips. 87L trip outputs must be isolated locally and remotely. However, it may be desirable to allow remote distance and directional overcurrent elements to remain in service. Microprocessor-based relays have configurable front-panel control switches that can be used for functions such as enabling

87L Enable pushbuttons or switches simply turn the 87L element on and off, locally and at all remote terminals. We use such an isolation mechanism to allow distance and directional overcurrent elements within a multifunction relay to be tested without worry of operating a local or remote 87L element. As with any differential scheme, the 87L element should be turned off locally and at all remote terminals anytime current circuits are disturbed.

Relay Test Mode The first objective of a Relay Test Mode pushbutton or switch is to allow all the protection functions to be thoroughly tested but to avoid closing actual trip output contacts. The same functionality has traditionally been supplied by external test and isolation switches. Relay test mode does not interfere with any relay element operation; the relay merely blocks the normal output contacts used for breaker tripping, closing, and pilot scheme keying. In addition to isolating normal tripping contacts, relay test mode may be used to enable specific output contacts for test purposes. The other significant function of this pushbutton or switch is to supervise the communications command to enter 87L test mode. In other words, to further specify 87L element testing and enter 87L test mode, the relay must first be in relay test mode, with normal tripping contacts isolated from doing harm.

87L Test Mode When a relay is in 87L test mode, a signal should be transmitted over 87L channels to all remote relays to block the 87L element in those devices while the test mode is active. Note that other protection functions, such as the distance elements, are free to operate in both the local relay and at the remote terminals. Fig. 8 shows a screen capture of the 87L test mode. =>>T E S T 87L E nt e r i ng 87L T e s t Mode . S e l e c t T e s t : Cha r a c t e r i s t i c or L oopba c k ( C, L ) L oopba c k T e s t Cha nne l : ( 1, 2) L oopba c k Dur a t i on: ( 1- 60 mi nut e s )

? L ? 1 ? 5

Ar e y ou s ur e ( Y/ N) ? Y T he 87L e l e me nt i nhi bi t e d, a ddr e s s c he c k i ng ov e r wr i t t e n, T e s t i ng i s e na bl e d T y pe “ COM 87L ” t o c he c k t he l oopba c k s t a t us Wa r ni ng! Ct r l X doe s not e x i t t e s t mode T y pe “ T E S T 87L OF F ” t o e x i t

Fig. 8: Entering 87L Test Mode.

11

Protective Relay Vol. 2 During maintenance testing, for example, a technician can put the local relay into relay test mode via a front-panel pushbutton and put the 87L protection scheme into 87L test mode. The normal tripping output contacts will be isolated. Further, this disables 87L tripping at the local and remote terminals and allows element testing in the local relay using the specific testing output contacts. Remote relay backup elements, such as distance and directional overcurrent elements, remain functional.

87L Test Mode 1: Loopback Test A single relay and single test set can be used, either in the lab or in the field, to test an 87L element to a minimal degree. No working channel to the remote line terminal is available in this scenario. Therefore, the relay is tested with a loopback test, where the single relay transmit output is looped back to its own receive input (see Fig. 9). When a loopback test is active, the local relay ignores channel transmit and receive addresses to allow the 87L element to respond to the data it transmits. A loopback duration is added to prevent the relay from being stuck in loopback mode indefinitely. Alternately, a communications command can be used to disable loopback testing when complete. Test Set

V, I

Locally injected currents represent local and remote currents via an analog substitution used only during testing. Internally, the locally injected remote current is placed into an alignment table in the correct order for proper operation. Because local and remote currents are measured and phase magnitudes and angles can be independently controlled, the restraint characteristic of the 87L element can be fully tested 17 18. Differential and Alpha Plane restraint ratio (k) results are observed in metering commands for the element under test (see Fig. 10). Note that the angle of k is always displayed in positive degrees for simplicity. The idea for the single-terminal test comes from the fact that each of the phase elements does not require information from other phases in order to operate; the phases are segregated. Therefore, a particular phase (A, for example) can be chosen as the local test phase, and an unused phase (B, in this case of the 87LA element) can be used to simulate the current coming from the remote terminal (see Fig. 11). =>>ME T DI F Rel a y 1 S t a t i on R

87L

87L Communi c a t i on: Ma s t er 87L F unc t i on: Av a i l a bl e S t ub Bus : Di s a bl ed

Fig. 9: Loopback Test. Because any current injected into the local relay is measured as local and remote current, it is not possible to test restraint characteristics with a loopback test. There is no way to vary the angle of local and remote currents with respect to one another. The Alpha Plane in the differential metering is inactive during loopback tests. However, simple pickup sensitivity tests of the differential element can be performed; any current injected is viewed as operate or difference current. While loopback tests are not so good at checking the characteristics of the differential element in detail, they are handy for determining where a communications channel or network problem exists. Use all channel monitoring and statistics to determine root cause. In loopback mode, we physically apply an external loopback connection or condition. We can perform the loopback test at several points, such as at the relay terminals, at a local patch panel, at a local or remote multiplexer, and so on. The placement of the loopback at various locations allows testers to troubleshoot and isolate communications problems systematically.

87L Test Mode 2: Single-Relay Characteristic Test Another innovative testing scheme involves a single relay with no need for a working channel or loopback connection. Test currents are injected at one terminal with one test set. 87L test mode is used to specify and allow a single-relay characteristic test.

Da t e: 05/ 11/ 2012 T i me: 10: 42: 35. 698 S er i a l Number : 1111240304

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA 1. 634 0. 00 1. 634

IB 0. 000 37. 44 0. 000

L oc a l T er mi na l 3I 0 3I 2 I1 IC 1. 634 1. 634 0. 545 0. 000 0. 00 0. 00 0. 00 37. 44 0. 000 0. 000 0. 000

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA 6. 535 79. 97 6. 534

IB 0. 000 37. 44 0. 000

Remot e T er mi na l 1 3I 0 3I 2 I1 IC 6. 535 6. 535 2. 178 0. 000 79. 97 79. 97 79. 97 37. 44 0. 000 0. 000 0. 000

MAG ( pu) ANG ( DE G)

IA 7. 007 66. 70

IB 0. 000 37. 44

k a l pha ( DE G)

Al pha Pl a ne 87L C 87L B 87L A 1. 000 1. 000 0. 250 79. 94 180. 00 180. 00

Di f f er ent i a l IC 0. 000 37. 44

3I 0 3I 2 7. 007 7. 007 66. 70 66. 70 87L Q 0. 000 0. 00

87L G 0. 000 0. 00

Fig. 10: Operate and Restraint Quantities— Single-Relay Test. NORMAL TEST

Ia Ib

LOC

87L A

REM

To Trip Output To Test Output

NORMAL TEST

Fig. 11: Single-Relay Characteristic Test.

Remote Relays

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Protective Relay Vol. 2

This methodology enables tests to be conducted using the 87L element logic in its entirety and allows testers to gain familiarity with the relay and prove scheme operation before a working end-toend channel is in place. A simple analog substitution table defines which terminal currents to use for specific differential element tests (see Table 1). 87L Quantity

Local IA

A

Local IB

B

Local IC

C

Q

G

IA

IA

IC

Remote IC

87L

87L

87L

IB

Remote IB

V, I

Fault Element IA

Remote IA

Test Set

IB

IB

IB

IC IA

Table 1: Single-Relay Analog Substitution When performing a characteristic test, specify the phase (A, B, or C) or sequence element (3I0, 3I2) under test and either normal or secure mode. Specifying the phase or sequence element eliminates confusion that can occur when multiple elements pick up and operate for the same test or fault condition. When in secure mode, the Alpha Plane restraint region becomes larger and the protection becomes more secure to protect against misoperation with extreme CT saturation during an external fault. No channel is required for a single-relay characteristic test. This testing method is therefore useful in the lab for settings and scheme testing, without need for a channel or even a second relay. If a channel is in place and working, remote terminals ignore locally injected test quantities based on a signal that is permanently keyed over the channel to all remote relays, which blocks the normal 87L element in those devices. Other protection functions, such as the distance elements, are free to operate at the remote terminals. Single-relay characteristic tests can also be performed at multiple terminals simultaneously.

87L Test Mode 3: Multiple-Relay Characteristic Test A third test mode involves multiple relays, one at each terminal of the line, and a working channel. This test can also be done in the lab, but still, a working channel is required. 87L test mode in the relay is used to specify and allow a multiple-relay characteristic test. Currents can be injected at one terminal with one test set or at multiple terminals at the same time (see Fig. 12). If testing is performed in the lab, a single test set can be used to simultaneously inject currents into multiple relays. By definition, the test signals provided to each relay from the common test source are synchronized; the current phase angles are absolutely referenced to one another.

Fig. 12: Multiple-Relay Characteristic Test With One Test Set. If the test is done in the field, satellite synchronization of the test sets must be used so that the current phase angles in different test sets are absolutely referenced to one another (see Fig. 13). Disturbance detection and watchdog logic dramatically improve the security of the 87L function. Disturbance detection requires that local and remote currents change before differential elements and transfer trip signals are acted on. Watchdog logic inhibits 87L tripping after a number of persistent close calls. Close calls are momentary pickups of the raw differential element without accompanying disturbance detection and can indicate significant channel or hardware problems. The watchdog logic has two levels. The first stage is correlated with channel activity in order to provide an actionable alarm to the user. When the counted illegitimate 87L pickup events are associated with the channel problems, the channel is suspected as the root cause and should be inspected. The second stage counts all unexpected 87L pickup events. Stage 2 inhibits only the 87L function and does not inhibit other local protection functions of the relay. Test Set

V, I

87L

Test Set

V, I

87L

V, I

Test Set

87L

Satellite Time

Fig. 13: Characteristic Test with Multiple Relays and Test Sets. While improving system security during real-world operation, these features complicate traditional, simple test methods. Ramping currents during testing can quickly generate many pickups and dropouts, increment the watchdog counters, and disable the 87L element. Without a specific 87L test mode, a communications command would be needed to reset watchdog counters, but this could become a tedious process after each test 19. Fig. 14 shows a traditional test where one terminal is held constant while another terminal is modified. This is an unrealistic power system fault simulation and will increment watchdog counters without 87L test mode.

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Protective Relay Vol. 2

The Alpha Plane result defaults to 0 per unit at 0 degrees when the differential and restraint currents are nearly equal. The reason for this is that the (IRST – Ix) term in the denominator of the generalized Alpha Plane k calculation converges to zero for this condition and the calculation is therefore unsolvable. This is always the case when we use one injected current in a multiterminal test. When the differential current is less than 50 percent of pickup, the Alpha Plane is forced to 1 per unit at 180 degrees. This makes the relay more secure by forcing the relay to the ideal blocking point. Fig. 14: Unrealistic Power System Fault Simulations Require 87L Test Mode. When performing a multiple-relay characteristic test in 87L test mode, currents at one terminal can be held constant while currents at the other terminal(s) are changed. In 87L test mode, the relay ignores local and remote disturbance detectors and watchdog logic to allow simpler testing. While ramping one terminal current while holding another current constant does not simulate a realistic power system fault, it works well to test the 87L operate and restraint characteristics. The advantage to multiterminal testing is that the 87L protection can be treated as a complete system. It allows charging current compensation and in-line transformer functions to be tested as well. Multiterminal testing ensures that the communications system is running properly and that the dynamic behavior of the communication is reliable enough for the protection. Differential element metering can be observed. The operate and Alpha Plane restraint results are valid for the element under test. Fig. 15 shows a C-phase element under test, using multiterminal characteristic testing. =>>ME T DI F Rel a y 1 S t a t i on R

Da t e: 05/ 11/ 2012 T i me: 13: 59: 54. 456 S er i a l Number : 1111240304

87L Communi c a t i on: Ma s t er 87L F unc t i on: Not Av a i l a bl e S t ub Bus : Di s a bl ed

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA 0. 001 - 88. 10 0. 000

IB 0. 000 2. 56 0. 000

L oc a l T er mi na l IC I1 3I 0 3I 2 0. 327 0. 109 0. 326 0. 328 120. 15 0. 00 - 119. 78 120. 21 0. 327 0. 327 0. 327

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA IB 0. 000 0. 000 - 80. 87 - 118. 66 0. 000 0. 000

Remot e T er mi na l 1 IC I1 3I 0 3I 2 0. 409 0. 137 0. 408 0. 409 119. 57 - 0. 48 - 120. 47 119. 64 0. 408 0. 408 0. 410

MAG ( pu) ANG ( DE G)

IA 0. 001 - 86. 09

Di f f er ent i a l IB IC 3I 0 3I 2 0. 000 0. 736 0. 735 0. 737 - 120. 16 119. 89 - 108. 81 119. 83

k a l pha ( DE G)

87L A 1. 000 180. 00

87L B 1. 000 180. 00

Al pha Pl a ne 87L C 0. 000 0. 00

87L Q 0. 000 0. 00

87L G 0. 000 0. 00

Fig. 15: Operate and Restraint Quantities— Multiple-Relay Test.

Real-World Testing—No Use of 87L Test Mode The last method of testing the 87L element is by simulating a realistic power system event and not using 87L test mode at all. 87L test mode can be disabled if all relays at all terminals are available, the channel is working and available, and we have the ability to synchronously inject test signals into all relays simultaneously. Note that realistic test values must be injected. In other words, we cannot inject current into only one terminal to simulate a fault; on a real power system, all closed and in-service terminals would assert a disturbance detector during internal and external faults. Some testers will be philosophically opposed to using any sort of test mode. They may want to challenge the relay as it exists in service. This method can be used; however, problems can arise by using test sets at each end of the line that are not applying realistic test values (i.e., current is changed at one terminal only) or using test sets that are not perfectly synchronized. For example, the authors have witnessed problems with satellite-synchronized test equipment that does not turn off state simulations simultaneously. In these cases, the tester must reset the watchdog counters manually after each test. For multiterminal system testing, we apply signals at each end of the line simultaneously for complete system testing. Multiterminal testing verifies the overall performance of the relays and the associated channel equipment.

CONCLUSION Modern digital relays offer dramatic improvements in capabilities, sensitivity, speed, and security. Improvements include enhanced channel monitoring, satellite time-based time alignment, disturbance detection, the generalized Alpha Plane, external fault detection, adaptive characteristics, charging current compensation, in-line and tapped transformer compensation, watchdog counters, improved relay self-test diagnostics, and more. Security failures are rare. Still, every undesired operation is cause for concern. Three real-world cases are shared in this paper. In one, an SEU caused a misoperation; improved diagnostics and memory storage prevent this from reoccurring. In the second, a communications error produced a misoperation; disturbance detection would prevent this from reoccurring. In the third, another communications error produced a misoperation, in spite of disturbance detection being enabled; monitoring channel alarms and performance, in addition to allowing watchdog counters to disable the 87L element after a number of close calls, improves security.

14 As 87L protection has advanced, so have testing capabilities and requirements. Channel statistics and monitoring help diagnose problems more easily today. Loopback test mode allows channel problems to be pinpointed quickly and allows simple relay testing to be done without the need of a working channel. Full characteristic testing in the lab is allowed with new test modes, including the ability to substitute a locally injected current for a remote terminal current. Traditional, simple tests using ramped currents or changing currents at only one terminal are still allowed, but test mode must be used. If this is not done, disturbance detection and watchdog counters may log 87L element assertions without accompanying disturbance detection as close calls and eventually disable the 87L element. If real-world testing is preferred without altering settings or using special test modes, the tester must simultaneously inject realistic power system values into all terminals. If this is not done, disturbance detection and watchdog counters may log 87L element assertions without accompanying disturbance detection as close calls and eventually disable the 87L element.

Protective Relay Vol. 2 6

 . Alexander, D. Costello, B. Heilman, and J. Young, “Testing G the SEL‑487E Relay Differential Elements,” SEL Application Guide (AG2010-07), 2010. Available: http://www.selinc.com.

7

 . O. Schweitzer, III, D. Whitehead, H. J. Altuve Ferrer, E D. A. Tziouvaras, D. A. Costello, and D. Sánchez Escobedo, “Line Protection: Redundancy, Reliability, and Affordability,” proceedings of the 64th Annual Conference for Protective Relay Engineers, College Station, TX, April 2011.

8

 . Normand, “Single Event Upset at Ground Level,” IEEE TransE actions on Nuclear Science, No. 6, Vol. 43 (December 1996): 2742–2750.

9

 . E. Shannon and W. Weaver, The Mathematical Theory of ComC munication. Board of Trustees of the University of Illinois, 1998.

10

 . Ward and W. Higinbotham, “Network Errors and Their InfluS ence on Current Differential Relaying,” proceedings of the 64th Annual Conference for Protective Relay Engineers, College Station, TX, April 2011.

11

ACKNOWLEDGMENTS

 . Miller, J. Burger, N. Fischer, and B. Kasztenny, “Modern H Line Current Differential Protection Solutions,” proceedings of the 63rd Annual Conference for Protective Relay Engineers, College Station, TX, March 2010.

12

The authors wish to gratefully acknowledge Normann Fischer, Doug Taylor, Dale Finney, Brian Smyth, Héctor Altuve, Bogdan Kasztenny, and Bin Le for their assistance and contributions in developing this paper.

J . J. Kumm, M. S. Weber, E. O. Schweitzer, III, and D. Hou, “Philosophies for Testing Protective Relays,” proceedings of the 48th Annual Georgia Tech Protective Relaying Conference, Atlanta, GA, May 1994.

13

 . Zimmerman and D. Costello, “Lessons Learned From ComK missioning Protective Relaying Systems,” proceedings of the 62nd Annual Conference for Protective Relay Engineers, College Station, TX, March 2009.

14

 . Zimmerman, “SEL Recommendations on Periodic MainteK nance Testing of Protective Relays,” December 2010. Available: http://www.selinc.com.

As protective relay algorithms and capabilities adapt and evolve, so must the engineer, technician, and test practices.

REFERENCES 1

J . Roberts, D. Tziouvaras, G. Benmouyal, and H. Altuve, “The Effect of Multiprinciple Line Protection on Dependability and Security,” proceedings of the 55th Annual Georgia Tech Protective Relaying Conference, Atlanta, GA, May 2001.

2

 . Kasztenny, N. Fischer, K. Fodero, and A. Zvarych, “CommuB nications and Data Synchronization for Line Current Differential Schemes,” proceedings of the 38th Annual Western Protective Relay Conference, Spokane, WA, October 2011.

15

I . Voloh, B. Kasztenny, and C. B. Campbell, “Testing Line Current Differential Relays Using Real-Time Digital Simulators,” IEEE/PES Transmission and Distribution Conference and Exposition, Atlanta, GA, October 2001.

3

 . Benmouyal and J. B. Mooney, “Advanced Sequence EleG ments for Line Current Differential Protection,” proceedings of the 33rd Annual Western Protective Relay Conference, Spokane, WA, October 2006.

16

 . Lee, D. Finney, N. Fischer, and B. Kasztenny, “Testing ConK siderations for Line Current Differential Schemes,” proceedings of the 38th Annual Western Protective Relay Conference, Spokane, WA, October 2011.

4

 . Kasztenny, G. Benmouyal, H. J. Altuve, and N. Fischer, “TuB torial on Operating Characteristics of Microprocessor-Based Multiterminal Line Current Differential Relays,” proceedings of the 38th Annual Western Protective Relay Conference, Spokane, WA, October 2011.

17 A. Rangel and D. Costello, “Setting a Two-Terminal SEL-311L Re-

5

 . Zeller, A. Amberg, and D. Haas, “Using the SEL-751 and M SEL-751A for Arc-Flash Detection,” SEL Application Guide (AG2011-01), 2011. Available: http://www.selinc.com.

lay Application With Different Nominal Currents,” SEL Application Guide (AG2012-12), 2012. Available: http://www.selinc.com.

18  A.

Rangel and D. Costello, “Setting and Testing a Two-Terminal SEL‑311L Application With Different CT Ratios,” SEL Application Guide (AG2012-10), 2012. Available: http://www.selinc.com.

19

 . Zimmerman, “Viewing and Resetting the Watchdog Counters K in the SEL-411L Relay,” SEL Application Guide (AG2013-01), 2013. Available: http://www.selinc.com.

Protective Relay Vol. 2 Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying. David Costello graduated from Texas A&M University in 1991 with a B.S. in Electrical Engineering. He worked as a system protection engineer at Central Power and Light and Central and Southwest Services in Texas and Oklahoma and served on the System Protection Task Force for ERCOT. In 1996, David joined Schweitzer Engineering Laboratories, Inc. as a field application engineer and later served as a regional service manager and senior application engineer. He presently holds the title of technical support director and works in Fair Oaks Ranch, Texas. David has authored more than 30 technical papers and 25 application guides and was honored to receive the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference. He is a senior member of IEEE, a registered professional engineer in Texas, and a member of the planning committees for the Conference for Protective Relay Engineers at Texas A&M University, the Modern Solutions Power Systems Conference, and the I-44 Relay Conference.

15

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Protective Relay Vol. 2

WHY APPLY PROTECTIVE RELAYS? PowerTest 2013 Karl Zimmerman, Schweitzer Engineering Laboratories, Inc.

“Protective relaying is a vital part of any electric power system: unnecessary during normal operation but very important during trouble, faults, and abnormal disturbances. Properly applied protective relaying initiates the disconnection of the trouble area while operation and service in the rest of the system continue.” —January 1987; J. Lewis Blackburn

ABSTRACT Protective relays have been applied for decades. During this time, most of the basic functions and applications have not changed a great deal. Protection is still required to detect faults and electrical disturbances to safely and securely isolate the affected part of the power system. One of the most important advancements of the past 25 years is event data provided by relays and with them, the ability to discover root cause of power system disturbances. In this paper, we show a basic approach to analyzing field data and then show several real-world events and practical solutions that improve the safety and reliability of the power system. We also show how advancements in technology produce challenges in applying and testing protection systems.

PHILOSOPHY OF SYSTEM PROTECTION In general, the basic objective of system protection has not changed. In short, it is to isolate the problem area of the power system as quickly as possible, while allowing the rest of the power system to remain in service. Protective relays measure the system parameters (usually voltage and/or current) and work together with circuit breakers and other circuit interrupters to isolate faulted or damaged portions of the power system. The foundational principles of protection are the following: ●● Reliability. In protection, reliability has two parts: security and dependability. Security is the degree to which protection does not operate incorrectly. Dependability is the degree to which protection operates correctly. Both security and dependability are important, and protection engineers must weigh the advantages and disadvantages of each when selecting and applying relays. ●● Selectivity. Selectivity maximizes the availability of the power system. For example, Figure 1 shows a system one-line diagram with many power system components. Each component is subdivided into a zone of protection, highlighted for the generator, transformers, a bus, a motor, a capacitor, and several lines. In practice, protection systems are designed to operate the breakers that isolate only the part of the system affected by the problem. ●● Speed of operation. Protection is designed to operate as quickly as possible, as long as it does not compromise the security of the power system. Many relays operate within 1 or 2 cycles

1

(e.g., differential protection relays), and others operate with a time delay (e.g., inverse overcurrent relays that must coordinate with downstream fuses). In Figure 2, the relay Zone 1 distance element (M1P) asserts in about 1 cycle, and the total clearing time is under 4 cycles. ●● Simplicity. Protection should be as straightforward as possible and include only what is necessary. For example, microprocessor-based relays provide many benefits to the protection of the power system and significantly reduce and simplify wiring compared with traditional relays, but may require more settings. If we evaluate only protection functions, for example, adding up all the discrete relays and settings and comparing them with the settings of a microprocessor-based relay, the actual number of settings is similar. However, adding more functions (programmable logic, communications ports, supervisory control and data acquisition [SCADA], IEC 61850 Sampled Values and/or Generic Object-Oriented Event [GOOSE] messages, metering, monitoring, satellite time synchronization, synchrophasors, and so on) results in adding more settings and complexity. Engineers should evaluate all of the factors.

Ring Bus

Generator

Plant Distribution Feeder

Transformer

Transmission Line Bus

Motor

Single Bus Distribution Lines

Transformer Capacitor

Fig. 1: Example Power System One-Line Diagram with Several Zones of Protection

17

Protective Relay Vol. 2

Fig. 2: Instantaneous Trip for Transmission Line Fault The challenge for protection engineers and technicians is to weigh all of these factors, while also considering the life-cycle cost of the protection (installation, maintenance, and so on) in light of the cost of repairing or replacing the protected lines and apparatus, if protection is not applied or reduced. Protection is not called upon to operate very often, but can pay for itself with one fault, if the protected equipment is isolated properly. Moreover, newer relays have greatly improved the ability to find root cause when faults and electrical disturbances do occur, as discussed next.

Fig. 3: Event Report Capture of an Evolving Fault on a Distribution Feeder This detailed information allows users to have an excellent understanding of the fault, which would have been impossible in the past. In addition, engineers and technicians have discovered and corrected countless numbers of wiring, setting, and application errors through event report analysis during commissioning. Fortunately, many technical specialists are using improved testing and commissioning practices, resulting in an increasing number of problems found before relays are placed into service 2.

THE EVENT REPORT

ADVANCEMENTS IN PROTECTION

Of all the advancements in the protection industry the past 25 to 30 years, perhaps the one with the most impact is the ability of relays to take a snapshot of the power system during a disturbance or fault. Older electromechanical and solid-state relay designs performed the actual protection task admirably, but it was often difficult or not possible to determine the cause of failure for many power system disturbances. Microprocessor-based relays that produce event reports now provide engineers the ability to identify root cause of operations on nearly 100 percent of system occurrences. It has truly been a revolution in improving the safety and reliability of power systems and providing data, not only for postfault analysis, but for actually preventing problems during testing and commissioning.

In addition to determining root cause for system events and during commissioning, relay designers have used the lessons learned and new technologies to dramatically improve protection and control.

Figure 3 shows a screen capture of an evolving fault on a distribution line. In this event, we see the fault start out as an A-phaseto-ground fault, then evolve to an A-phase-to-B-phase-to-ground fault, then to a three-phase fault. We can see the zero-sequence current (IGMag) increase initially and cause the ground overcurrent element (51G) to pickup and start timing toward trip. Then, when the fault evolves, IGMag decreases and eventually drops close to nearly zero for the three-phase fault. The phase overcurrent (51P) stays picked up the entire time.

●● Adaptive relay settings on distribution relays for cold load inrush, feeder switching, or distribution automation.

The improvements include the following: ●● Settable transformer differential protection to allow flexible application for varying power transformer connections, current transformer (CT) ratios, and grounding practices. ●● Motor protection using adaptive elements that emulate the thermal characteristics of the motor. ●● Directional elements that have better sensitivity to detect high-resistive faults.

●● Programmable time-overcurrent characteristics to allow better coordination between distribution protection devices. ●● Light sensing in protection schemes to detect arc-flash events. ●● Improvements in security for differential protection to avoid operations for external faults due to CT saturation without losing the ability to detect internal faults. ●● Addition of disturbance detection to supervise high-speed tripping.

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Protective Relay Vol. 2

All of these advancements and innovations contribute greatly to the improvement of system protection. At the same time, new technologies create challenges in keeping up with the changes of how to properly apply, set, test, and commission these relaying schemes. In the following subsections, we highlight three protection advancements and the challenges to engineers and technicians who apply them.

Directional Elements Detect High-Resistance Faults In the event shown in Figure 4, a utility crew was installing new structures for a 115 kV line on an existing right of way. One of the trucks was in close enough proximity to the in-service transmission line to cause a flashover. One of the line terminals took approximately 55 cycles to clear the fault while personnel were in a truck engulfed in the fault. Even though the fault was close in, the relay did not pick up on its Zone 1 or Zone 2 distance elements. Figure 4 shows the phasors. In this case, the relay used the Zone 2 distance elements in a permissive overreaching transfer trip (POTT) scheme with only overreaching phase and ground distance set to trip.

where: 45

135

Re[V2•(1 Z1ANG•I2)*]

|I2|2

(1)

V2 is the measured negative-sequence voltage. I2 is the measured negative-sequence current.

IC

Z1ANG is the positive-sequence line angle. VB(kV)

180

IA

225

In 1993, the directional element referenced in Figure 5 using the calculated negative-sequence impedance was introduced that lies collinearly to the protected positive-sequence line impedance. Z2measured=

90

VA(kV)

Fig. 5: High-Resistance Fault Would Have Been Detected by Ground Directional Overcurrent Element

VC(kV)

IB

0

315

270

* indicates complex conjugate. In practice, a forward fault yields a Z2measured equal to –ZS2 (the source impedance behind the relay). A reverse fault yields a Z2measured equal to ZL2 + ZR2 (the line impedance plus the remote source impedance). This is shown graphically in Figure 6. The relay compares Z2measured with thresholds ZR2 (reverse) and ZF2 (forward) to declare whether the fault is forward or reverse.

Fig. 4: Fault Currents and Voltages During the HighResistance Fault on a 115 kV Line A more sensitive relay (specifically, a ground directional overcurrent relay), if applied, could have detected this fault and reduced the trip time to nearly instantaneous tripping. Ground overcurrent elements are comprised of two main components: an overcurrent (50) threshold and a directional element (32) to torque control the overcurrent element. Figure 5 shows a screen capture of the zero-sequence current magnitude (IGMag) and the directional element (32QF) that would have asserted and cleared this fault, if applied. Fig. 6: Measured Negative-Sequence Impedance Yields Fault Direction

19

Protective Relay Vol. 2 Similarly,3 provides more evidence of the need for improved sensitivity through a case study of a 500 Ω fault on a 525 kV transmission line in Brazil. The cause of the fault was a flashover from the transmission line to trees near a river crossing. There was practically no voltage dip on the faulted phase, and with such high fault impedance, the angular difference between the faulted phase voltage and current was less than 10 degrees, as shown in Figure 7.

tic implementation, as shown in Figure 9. The minimum operate threshold is defined by a pickup setting (O87P). When the magnitude of the restraint quantity is greater than IRS0 and less than IRS1, the relay operates based on the Slope 1 (SLP1) setting. When the magnitude of the restraint quantity is greater than the setting IRS1, the operating characteristic changes from Slope 1 to Slope 2 (SLP2). Iop (pu)

90 U87P

135

VC(kV)

45

87R Restrained Element Operate Region SLP2

IC(A) IA(A) VA(kV)

180

SLP1

0

Restraint Region O87P

IG(A)

IRS0

VB(kV) 225

IRS0 =

315

IB(A)

Irst (pu)

IRS1

O87P • 100 SLP1

270

Fig. 9: Dual-Slope Differential Characteristic

Fig. 7: Voltage and Current Phasors for 525 kV BG Fault with 500 Ω Fault

When testing this element, we can use steady-state currents in the winding inputs to determine whether the relay is performing within its specification. To test the minimum pickup, the restraint current must be less than IRS0. To test SLP1, the restraint must be within IRS0 and IRS1. To test SLP2, the restraint current must be greater than IRS1. Test U87P by applying an operate current, regardless of restraint current.

Figure 8 shows a screen capture of the directional overcurrent element (67G2) asserting and producing a trip for this fault.

Next we consider one of the challenges of current differential protection: the impact of CT saturation. Figure 10 shows a fault external to the zone of protection. Ideally, all of the CTs (CT-1, CT-2, and CT-3) perform well and produce a replica of the primary current to the relays. Strong Source CT-1

Power Transformer

Remote Source CT-3

CT-2

Fig. 8: Directional Overcurrent Element (67G2) Detects 500 Ω Fault Challenge: Testing the thresholds for this directional element challenges the technician to be more proficient in understanding symmetrical components to generate proper test values and to understand how these elements torque control directional overcurrent elements.

Adaptive Slope Characteristic Many current differential relays use a dual-slope characteris-

Fig. 10: External Fault Produces Through-Fault Current However, if the fault current is severe enough, it is possible for CT-2 to saturate, as shown in Figure 11. This could produce a false differential (operate) current and could lead to a misoperation. The false differential current occurs in the secondary CT circuit but is shown on the primary side in Figure 11 for illustrative purposes. This is why many relay designs offer a higher slope characteristic with higher restraint currents.

20

Protective Relay Vol. 2 Strong Source CT-1

Power Transformer

Remote Source CT-3

CT-2

CT-2 saturates, causing false differential current

An example of why this is important in the power system was observed in an actual system fault, as shown in Figure 14. A feeder relay and transformer differential relay both operated, which started an investigation of the event reports. The initial report from the field was that a transformer differential relay incorrectly tripped for an external feeder fault. However, after examining the event reports, the fault turned out to be an external feeder fault that evolved into an internal differential zone fault.

Fig. 11: External Fault Causes CT-2 to Saturate There have been instances where, even with the higher Slope 2, differential relays have misoperated 4. Figure 12 shows a case where a current differential relay operated incorrectly due to CT saturation.

Simultaneous Faults?

87

50/51

Fig. 14: Transformer Relay and Feeder Relay Operate for Fault If we examine the feeder relay screen capture in Figure 15, we observe that the C-phase voltage decays as the C-phase current increases. About 1 cycle later, the B-phase voltage decays. Fig. 12: Current Differential Element (87U) Operates for External Fault During Severe CT Saturation As a result, relay designers have developed a scheme whereby the relay dynamically switches between SLP1 or SLP2, depending on fault-sensing logic, as shown in Figure 13. This allows increased security for external faults, without sacrificing sensitivity for internal faults. Iop (pu)

U87P 87R Restrained Element Operate Region

SLP2

Fig. 15: Simultaneous Faults SLP1

Restraint Region

O87P IRT2 IRT2 =

Irst (pu)

IRT1

O87P • 100 SLP2

IRT1 =

O87P • 100 SLP1

Fig. 13: Adaptive Slope Characteristic

This is hard to comprehend until we see a photograph of the substation, shown in Figure 16. The differential zone bus work is physically above the feeder bus work, so when the C-phase-toground fault occurred on the feeder, the energy of the flash caused the B-phase on the differential zone to flash over.

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Protective Relay Vol. 2

Fig. 16: Distribution Substation Shows Transformer Zone Bus Work Physically Above Feeder Bus Work In order to demonstrate this, we performed some post-fault analysis, asking what might happen if we applied the adaptive slope characteristic relay from Figure 13. Figure 17 shows the restraint currents (IRTA, IRTB, and IRTC) increase before the operate currents (IOPA, IOPB, and IOPC) and the control bits CONA and CONC assert. This switches the relay to Slope 2 but still allows a differential trip (87RB, 87RC) when the fault evolves to an internal fault.

Fig. 18: Overcurrent and Light Sensors Together Produce Lower Fault Clearing Times Challenge: Testing and commissioning the arc-flash combined light and current element requires testing the light-sensing fiber cables and sensors, along with conventional current injection to validate the performance of the scheme 9. This discussion highlights just three significant advancements in technology that affect relay engineers and technicians, but almost all protective relaying applications are changing. For example, many motor protection relays may require testing a thermal element that emulates the thermal characteristic of the motor 10; some line current differential relays employ a test mode, which allows characteristic testing from a single end of the line; and virtually all relays are programmable multifunction devices that have multiple elements directed to produce a trip output.

CONCLUSIONS Fig. 17: COMTRADE Playback of Evolving Fault Through Adaptive Slope Characteristic Relay Challenge: Testing current differential relays with an adaptive characteristic, as found in many new bus and transformer differential relays, requires a new approach to testing. In order to validate the precise threshold of Slope 2 (SLP2), we now must perform dynamic state simulation, whereby we apply an external fault initially to force the relay into the higher security SLP2 setting, then switch to an internal fault within a few cycles 5.

When we ask, “Why apply protective relays?,” we recognize that the basic philosophy of protection, reliability, selectivity, simplicity, and speed, are all still very similar to what they were 50+ years ago. It is sometimes easy to reminisce about the good ol’ days of protection, when all relays were single function devices and could be easily isolated and tested. But while we look back to keep perspective, we should recall the complexity of external wiring required in the electromechanical relay panels built in the past decades, such as the one shown in Figure 19.

Arc-Flash Mitigation: Using Overcurrent and Light Sensing Together Personnel safety regarding arc-flash hazards has always been of utmost concern to engineers 6 7. In recent years, protection engineering and philosophy has moved beyond solely the protection of electrical power lines and apparatus to how protection can improve personnel safety by mitigating arc-flash hazards 8. Relays can now be applied using light sensors and fiber cables within switchgear to detect an arc-flash event. Figure 18 shows an event capture with the overcurrent and light sensors. Note that the combined overcurrent and light element (50PAF) operates in 0.25 cycles.

Fig. 19: Electromechanical Relay Panel

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Protective Relay Vol. 2

The invention of the relay event report has created a new ability and, now, expectation to find root cause of virtually every power system disturbance. Data found in event reports can assist in commissioning to prevent problems before they occur. We can debate whether testing modern relays is easier or more difficult but, at the very least, the shift in complexity requires a modern technician to have a stronger understanding of protection fundamentals such as symmetrical components, good computer literacy, and a broad command of test equipment capabilities. Moreover, a modern technician needs to adapt to the challenges that new and changing technology brings.

D. Costello, “Lessons Learned Through Commissioning and Analyzing Data From Transformer Differential Installations,” proceedings of the 33rd Annual Western Protective Relay Conference, Spokane, WA, October 2006.

Regardless of advancements, do not overlook the following fundamentals:

7 NFPA

●● Make documentation complete and up to date. ●● Perform as many tests in the laboratory as possible ●● Create thorough checklists for commissioning. ●● Use peer reviews for test plans and work performed. ●● Perform primary and secondary current and voltage injection when appropriate. For example, when testing power transformers, budget time and resources to perform primary injection of current signals to test transformer differential relay settings and CT ratios and connections for both three-phase and single-phase events. ●● Test inputs and outputs, including dc control wiring and communications links. ●● When developing test plans, say what you do, and do what you say. ●● Invest in training. ●● Make commissioning a separate line item for budgeting and planning. ●● Go beyond compliance and ask questions. Lessons learned from system operations, advancements in processing capability, and overall technological advancements have led to many industry changing improvements. It is a challenge for relay professionals to stay current with new and changing technology, but the best advice is to “stay curious, my friends.”

REFERENCES J. L. Blackburn, Protective Relaying Principles and Applications, 1st ed. Marcel Dekker, Inc., New York, NY, 1987. 1

2 K.

Zimmerman and D. Costello, “Lessons Learned From Commissioning Protective Relaying Systems,” proceedings of the 62nd Annual Conference for Protective Relay Engineers, College Station, TX, March 2009. 3 P. K. Maezono, E. Altman, K. Brito, V. A. dos Santos Mello Maria,

and F. Magrin, “Very High-Resistance Fault on a 525 kV Transmission Line – Case Study,” proceedings of the 35th Annual Western Protective Relay Conference, Spokane, WA, October 2008.

4

5 G. Alexander,

D. Costello, B. Heilman, and J. Young, “Testing the SEL-487E Relay Differential Elements,” SEL Application Guide (AG2010-07), 2010. Available: http://www.selinc.com. IEEE Standard 1584-2002, IEEE Guide for Performing ArcFlash Hazard Calculations. 6

70E®: Standard for Electrical Safety in the Workplace®, 2004 Edition. 8 J.

Buff and K. Zimmerman, “Application of Existing Technologies to Reduce Arc-Flash Hazards,” proceedings of the 60th Annual Conference for Protective Relay Engineers, College Station, TX, March 2007.

M. Zeller, A. Amberg, and D. Haas, “Using the SEL-751 and SEL-751A for Arc-Flash Detection,” SEL Application Guide (AG2011-01), 2011. Available: http://www.selinc.com. 9

G. Alexander and S. Patel, “Testing the Thermal Model in the SEL-710 Motor Protection Relay,” SEL Application Guide (AG2011-12), 2011. Available: http://www.selinc.com.

10

Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying.

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Protective Relay Vol. 2

WHY WE SHOULD MEASURE LINE IMPEDANCE? PowerTest 2013 W. Knapek, OMICRON electronics, USA U. Klapper, OMICRON electronics GmbH – Austria

ABSTRACT The paper analyzes the impact of errors in the line impedance parameters on the accuracy of the short circuit currents and voltages calculation, the settings of the distance and overcurrent relays and the fault clearing times for different line lengths and fault locations. The accuracy of the fault location calculation is also affected. This paper explains the difficulty of k-Factor settings and points out cost effective solutions for preventing incorrect behaviour of distance protection schemes. The inaccurate values of the mutual coupling of parallel transmission lines are another important factor that may affect the operation of the relays for faults involving ground. This is also discussed in the paper. Actual measurement of the fault-loop impedance is the best way to ensure that the distance and overcurrent relay settings are correct. The second part of the paper describes an advanced method for these measurements and calculations that provide the impedance data for the different applications that use it. Comparisons of estimated and measured line impedances are presented at the end of the paper.

The transmission line impedances used for short circuit currents calculation and the setting of distance relays are normally derived from the results of a line constants program calculation or systems studies. Due to the large number of influencing factors (e.g. wire types, spiraling and average sag of the wires, shield handling on cables, specific soil resistivity) these calculations can be prone to error. Actual measurement of the fault-loop impedance is the best way to ensure that the distance and overcurrent relay settings are correct. The second part of the paper describes an advanced method for these measurements and calculations that provide the impedance data for the different applications that use it. Comparisons of estimated and measured line impedances are presented at the end of the paper. Measuring mutual coupling between power lines can be done using a similar method.

IMPORTANCE OF K-FACTORS

INTRODUCTION

To protect an overhead line or a power cable protective relays are needed. When a fault occurs on the line, such as an arc between phases or against ground, it has to be cleared safe, selective and fast. Selectivity means that the line is only switched off, if the fault is really on this very line 1.

The performance of transmission line protection relays when a fault occurs in the system is important for improvements in the stability of the system and reduction of their effect on sensitive loads. Reducing the fault clearing time for more possible fault conditions is one of the main goals in the development, application and setting of such relays.

There are two basic methods to obtain selectivity on power lines, differential protection or distance protection. The better principle is the first one, but there is by far more effort involved, because the relays on both ends of the line need to communicate with each other. This paper does not further discuss this method. For cost reasons on most power lines distance protection relays are used.

The operating time of a transmission line protection relay is a function of many different factors. Some of them are related to the operating principle and the design of the relay itself. The paper analyzes the impact of errors in the line impedance parameters on the accuracy of the short circuit currents and voltages calculation, the settings of the distance and overcurrent relays and the fault clearing times for different line lengths and fault locations. The accuracy of the fault location calculation is also affected. This paper explains the difficulty of k-Factor settings and points out cost effective solutions for preventing incorrect behaviour of distance protection schemes.

One of the most important settings of a distance protection relay is the Positive Sequence Impedance, which is half of the complex impedance of the phase to phase loops (Figure 1).

The inaccurate values of the mutual coupling of parallel transmission lines are another important factor that may affect the operation of the relays for faults involving ground. This is also discussed in the paper.

Fig. 1: Impedance loop between two phases

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Protective Relay Vol. 2

When a fault occurs the distance relays on both ends measure the impedance. If the impedance is (typically) below 80% or 90% of the line impedance they switch off as fast as possible (zone 1), because it is for sure that the fault is on this very line. If the impedance is higher the relay switches off delayed (≥  zone  2), to give another relay that might be closer to the fault the chance to clear it first.

in zone 1 and trip, a second power line is dead. The customer lost power for no reason. Besides the damage of customers having no power, the risk of loosing system stability becomes also higher by such false trips.

On faults of one or more phases against ground, the impedance of the fault loop is different (Figure 2). Because the impedance of the ground path, or to be more precise, of this ground loop, is different, a factor within the relay gives the relation between the line and the ground impedance. This factor is called ground impedance matching factor or simply k-factor, as it is often referred to.

Unfortunately the k-factor does not exist. There are various formats out there; the three major types are discussed here. For all types it is to say that they are constants of the line, in general independent from the length. They express the relationship of the impedance of a phase-to-phase loop and a three-phase-to-ground loop. Half of a phase-to-phase loop (i.e. the impedance of one line) is referred to as Positive Sequence Impedance (Z1); three times the impedance of a three phase to ground loop is referred to as Zero-sequence Impedance (Z0).

DIFFERENT K-FACTOR FORMATS

One common format is the complex ratio of the Zero-sequence Impedance and the Positive Sequence Impedance. (1) Z0

k0 =

Z1

Because Z1 is the impedance of one line it is also referred to as ZL quite often. (2) Fig. 2: Impedance loop on a single phase ground fault If the relay settings are done properly a customer that is supplied from two ends (Figure 3) continues to receive energy from one line if the other trips.

ZL = Z1

The ground (or British “earth”) impedance ZE can be calculated from the Zero-sequence Impedance as follows: Z0 – ZL ZE = 3

Fig. 3: Relays with optimum zone 1 reach If the impedances or k-factors of a relay are not set properly, zone over- or under-reaches will occur (Figure 4).

(3)

Defining the ground impedance this way, obviously leads to strange results with a negative inductive component in ZE, as soon as the three-phase-to-ground inductance is much smaller than the inductance between two phases. This is the case on some power cables when the shield is close to the conductors but the conductors are relatively far from each other. This fact is of no further concern; it is just good to know that it can happen. Another possibility to express the relationship is the ratio of ground-to-line impedance. (4)

kL =

ZE ZL

kE or sometimes referred to as k0 are other common names for this definition. One has to be careful how a k-factor is defined before using it.

Fig. 4: Relays with zone 1 over-reach In the example above three relays instead of two see the fault

Splitting the complex impedances ZE and ZL into their real and imaginary parts R and X defines real ratios, this leads us to the third commonly used definition. (5, 6)

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Protective Relay Vol. 2

RE X — and —E RL XL

(7)

Conversions between the different k-factor formats are possible. (8)

k 0 = 1 + 3k L

For converting from the format (5) and (6) to the other formats the other line constants (or at least the line angle) have to be known. kL =



RE/RL XE/XL ________ + _______ 1+jXL/RL 1–jRL/XL

(9)

The line angle can be used to obtain the ratio XL / RL that is needed for the conversion in (8). Distance protection relays use algorithms that make use of these different k-factors to convert all phase-to-ground faults, so they can be assessed as if they were phase-to-phase faults. This allows using the same zone polygons independent from the line geometry. Because different relays can use different algorithms, identically measured voltages and currents may lead to different calculated impedances depending on the algorithm used. Details of these algorithms 2 are not further discussed in this paper; it is only to mention that the entry format of the k-factor does not allow deducing which algorithm is used by the relay.

CALCUALTION OF K-FACTORS Up to now the effort to measure line impedances and k-factors was so great that it has hardly been done. To obtain this data it had been calculated manually using physical constants, or by using appropriate software tools 3 like PowerFactory from DIgSILENT, PSS from Shaw PTI or CAPE from Electrocon, to name a few. The parameters needed to calculate the line impedance are many. The geometrical configuration is needed (Figure 5): ●● height above ground and horizontal distance for each phase conductor and each ground wire ●● average sag of the line and ground wires at mid-span

Fig. 5: Overhead line geometry

Several electrical parameters have to be known: ●● ground/soil resistivity ●● DC resistance of all conductors ●● spiralling construction of the conductors ●● geometrical mean radius of the conductors ●● overall diameter of the conductors Similar parameters are needed for calculating line impedances of power cables; on a first glance they might seem even simpler, but as this may be the case for new cables it might be the opposite for old installations where often a mixture of different cable types is used – and not documented too well either. In general it can be said that the calculation of the Positive Sequence Impedance works quite well and in general sufficient for the Zero-sequence Impedance as long as the ground or ground wire is a consistent good one. When the ground wire or shield is not a very good conductor and a large component of the fault current is flowing back through the soil, things tend to become complicated. The influence of the ground/soil resistivity, pipes, other buried metal structures, and the accurate distance of the wires above ground, make it very difficult to determine the impedance along the whole length of the line (especially in complicated landscape geometry and multiple infrastructure crossings). Another cause for concern is that a huge number of parameters are involved in the calculation of line parameters. If one parameter is wrong this might cause a substantial error. In the Positive Sequence Impedance there are several, but even more prone to error is the Zero-sequence Impedance or k-factor, because they need accurate parameters for their calculation. On several occasions when our team found incorrect relay settings it was the Zero-sequence Impedance or the k-factor that was in error. But we also had the situation that two similar lines were just mixed up.

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Protective Relay Vol. 2

MEASUREMENT OF K-FACTORS

Compared to the effort for accurate calculations, the actual measurement of line parameters including the k-factor is today relatively simple. The measurement of the line impedance requires the use of specialized equipment that includes several components: ●● test set comprising a frequency variable amplifier ●● signal coupling unit ●● ground protection device

Fig. 6: Test equipment for line Z measurement

The measurement is performed with currents between 1 and 100A depending on the line length. Using frequency selective measurement allows using injected currents a fraction of the size of the nominal currents. To ensure high accuracy of the measurement the highest current range for the given line length is chosen. Measurements on lines up to 270km (123 miles) have been performed so far. Overall seven measurements per system are made, three for each combination of phase to phase loops, three for each phase against ground and one for all three phases against ground. There is some redundancy in these measurements, allowing reliability crosschecks and calculation of individual k-factors for each phase. The latter seems strange at a first glance, but especially for short lines having a symmetrical line is not a priority, leading to very different values for the phases. This results in smaller k-factors and avoids zone overreaches in most cases. The actual measurement results can be loaded into Microsoft Excel allowing easy post processing; the results are displayed in a format for direct usage in relay settings (Fig. 7).

The test set used for the line impedance measurements is multi functional, frequency variable device for various tests on primary equipment. It may be required to generate currents up to 800A or voltages up to 2000V. Support for various automated tests on CTs, VTs, power transformers or other primary equipment is necessary to improve the efficiency of the primary testing process. In the application of line impedance measurement it is used as a frequency variable power generator, measurement tool and analyzer. Due to the variable frequency generation it is possible to generate signals first below then above mains frequency. Using a digital filter algorithm allows measuring frequency selective at the frequency that is currently generated, this means all other frequencies but the generated one are filtered out. Any disturbances at the mains frequency from nearby equipment or lines are therefore ignored during the testing. The coupling unit is used for galvanic decoupling of the generated signals in the output direction and analyzed signals in the input direction. The decoupling is needed mainly for safety reasons. For optimization of the performance it is an advantage to have a range selector switch and a built in voltmeter for a quick check of any induced voltages or high burdens. The protection device is a safety tool for easy connection to the overhead line or power cable. Existing grounding sets of the substation may be used. In case of unexpected high voltage on the power line due to faults on a parallel system, lightning discharges or transients due to switching operations, the protection device should be capable of discharging short transients or permanently shorting fault currents of up to 30kA for at least 100ms. These safety features are necessary to allow the user safe operation even in critical situations.

Fig. 7: Major measurement results

CASE STUDY This US utility had experienced some unexpected trips of unfalted line sections on their sub-transmission network. Investigations had lead to a suspicion of incorrect relay settings leading to zone over reaching, but the reason was not evident. Utilizing this method of directly measuring the line parameters, they were able to isolate the cause of the over reaching problem. So far, 16 lines have been tested and documented with actual measurements. A review of the results show 15 of 16 lines with consistent higher values for the calculated zero-sequence impedance as compared to the measured zero-sequence impedance. In fact, the average percentage error was 51%. (with a range of 10% to 107% error) Results are shown in the graph of Figure 9, and it is interesting to note that the positive sequence impedance measured values matched the calculated values within 3.5% on average. This validated the overall measurement results in the mind of the utility.

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Protective Relay Vol. 2

●● The ground resistivity “assumption” of 100 ohm-meters may be in error.

Comparison of Z Meas to Calc

●● How often the cable circuits are actually bonded to ground and where.

16.000 14.000 12.000

Ohms

10.000 8.000

Z1 Meas

6.000

Z0 Meas

Z1 Calc Z0 Calc

4.000

●● Neutral wires are not run on overhead construction; however no consideration is given to under-built distribution (4 or 13kV with a neutral cable). ●● Is there a big water pipe, gas pipe, railway, or other infrastructure in the ROW?

2.000 0.000

Z0 Meas B- U- O- DZ1 Meas VL- O-93 GZU- A-27 O-67 I-269 Z-26 262 151 301 212 568 272 AQ163 182 411 573 225 Line Name

If these variables can be accounted for then the calculated values may become closer to the measured values results.

Fig. 9: Measured impedance versus calculated impedance per line tested To put this in relaying settings perspective, the graph of Figure 10 shows the comparison of the k0 values of each line using the existing calculated results and those based on the measured results. It easily shows that 12 lines are exposed to serious over-reaching conditions and 3 lines to minor under-reaching conditions. The average error is 59% with a range of -15% to 147% error. So the overall effect on the relay settings was dramatic and points to the need for performing further testing. The utility has since implemented a program for testing all of the sub-transmission system and making the necessary settings changes based on the measured results. Murphy has not yet provided any tests of these new settings on the lines tested, but that’s just the way he works. Comparison of k0 Meas to Calc

CONCLUSION Today the costs and effort for Line Impedance and k-Factor measurements are a fraction of what they used to be. Measurements showed that for several reasons calculations often gave wrong results. Therefore, both measurement and calculation will be done in the future. Safe, selective and fast failure clearance is only possible, if all relay parameters are set properly. Line impedance and k-factor are of highest importance for a fully operational distance protection relay.

REFERENCES W. Doemeland, Handbuch Schutztechnik, Huss-Medien GmbH, Berlin, Germany, 48-49.

1

S. Kaiser, 2004, “Different Representation of the Earth Impedance Matching in Distance Protection Relays,” Proceedings OMICRON User Conference in Germany 2004, OMICRON electronics GmbH, 11.1-11.5. 2

A. Dierks, 2004, “Accurate Calculation and Physical Measurement of Transmission Line Parameters to Improve Impedance Relay Performance,” Proceedings Southern African Power System Protection Conference 2004, Eskom Enterprises, 143-149. 3

2.50

2.00

Mag

1.50

k0 Meas

1.00

k0 Calc

0.50

0.00 BUODV262 151 301 212 568

L- O-93 G272 163 Line Name

ZU- A-27 O-67 I-269 Z-26 182 411

k0 Meas A573

Q225

Fig. 10: Comparison of k0, measured versus calculated per line tested In the analysis of the results the utility wanted to arrive at a conclusion as to why the traditional method of calculated zero-sequence was so far off. It was previously thought that the physical data was accurate and sufficient for good results. The conclusions drawn were:

William Knapek received a BS degree in Industrial Technology from East Carolina University in 1994. He retired from the US Army as a Chief Warrant Officer after 20 years of service in 1995. During his time with the Army Corps of Engineers, he held positions as a power plant instrumentation specialist, a writer/instructor for the Army Engineer School, and a Facility Engineer for a Special Operations compound. He has been active in the electrical testing industry since retiring in 1995. He worked for NETA companies in the Nashville, TN area until joining OMICRON electronics as an application engineer in April of 2008. He is currently the Sales Manager for the Southeast Area of North America for OMICRON electronics Corp, USA. He is certified as a Senior NICET Technician and a former NETA Level IV technician. Will is a member of IEEE and vice chair of WG I23 of the PSRC.

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Protective Relay Vol. 2

BASIC TRANSFORMER DIFFERENTIAL PROTECTION PowerTest 2015 Jay M. Garnett, Principal Engineer, Doble Engineering Company

ABSTRACT This paper will cover the basics of transformer differential protection. Topics will include the components that contribute to the relay protection, the transformers themselves, basic ratings, and the different variables involved. Also covered will be how to correctly wire the current transformers to prevent zero-sequence currents from inadvertently operating the differential relays. The basic process of setting the differential relays will also be discussed.

INTRODUCTION Basic transformer relay protection takes into account many variables when designing a protection circuit. Because there are different voltages on each side of the transformer, as well as a phase shift in most cases, there are many things to consider when designing the relay protection. For instance, protecting only the transformer, or zone of protection. The components of the differential protection will be covered, as well as how an engineer must look at the ratings of the current transformers (CTs) and how they are connected, to protect from inadvertently producing operations from unwanted currents. Current transformer class ratings will be explained. Also, polarity markings, why they are important, and how they need to be wired when using electromechanical relays as compared to microprocessor relays. Symmetrical components, inrush, and harmonics will be touched upon. And lastly, how to calculate a simple relay setting for a differential scheme using a GE BDD relay, and some microprocessor relay setting features. Figuring out the currents using the base MVA ratings of the transformer and applying them to a relay setting. (Example is a GE BDD relay).

for "calculated". So, C400 means the value is calculated at 400. Breaking it down, 400 is the voltage which can be delivered at 20 times the rated secondary current without exceeding a one percent (1%) ratio error. This is important when the protection engineer is doing his system fault studies to determine what class of CT to use, and the tap setting so it will operate correctly during fault conditions—such as the impedance of the relays attached to the current transformers. In this example, a current transformer class C400 with a 500:5 ratio will be used. The product of the current multiplied by the impedance should not exceed 400 volts. So if we take 20 x 5A that equals 100A. That means that a C400 CT that has a full ratio output of 5 ampere, would mean 400V÷100A=4 ohms (maximum impedance). So the impedance of the wiring and relays connected to the current transformer cannot exceed 4 ohms or else another class CT must be used. This was very important in the earlier days when electromechanical relays were used, as they had a much higher burden on the circuit than newer microprocessor relays do in today’s world. Next up is the polarity markings on current transformers. Each CT usually has a high side and a low side polarity mark. This indicates how the current will flow in the secondary winding based on the direction of current flow on the primary winding of the current transformer. This is extremely important when wiring up the relays to the CT’s in differential schemes, or even in directional relays used for line or ground fault protection. In figure 1, is a representation of primary current flow and secondary current flow.

SECTION 1 - CURRENT TRANSFORMERS (CTS) First, how the rating of the CT is determined will be explained. Then how the current flows in relation to the secondary current of the CT, and lastly how a very simple differential scheme works. Current transformers (CTs) used in transformer differential protection (and in other relaying schemes) are rated differently than metering class CTs. Older CTs used to have a “T” in the prefix of the class rating which meant a tested value. Most used today for relaying have a “C” in the prefix which stands

Fig. 1

29

Protective Relay Vol. 2 Polarity marks–sometimes referred to as the Spot and Non-spot– on current transformer may also be labled H1 and X1 as the polarity mark. This dictates that when primary current flows from the polarity side of the CT towards the non-polarity side of the CT, the secondary current will flow out the polarity of the CT and returns to the non-polarity of the CT. Figure 2 shows the polarity marking on the primary part of the CT. If the primary current enters the non-polarity of the CT, then the secondary current will leave through the non-polarity of the secondary CT and return to the polarity of the secondary. Keep in mind that what leaves the secondary of the CT needs to come back to the secondary of the CT and it doesn’t care where that current comes from. This will be discussed in Figure 3.

Fig 2: Standard bushing current transformer with polarity marking “H1” for primary current direction. In Figure 3, the primary current runs through the opening of the doughnut style CT via the conductor in a breaker or transformer bushing, inducting a field in the CT primary turns. This builds a field in the secondary winding until the fields become saturated. Once saturated, the CT cannot resist current flow in the secondary winding. If the secondary is open, it will develop extremely high voltages trying to achieve the primary voltage. This is a very dangerous condition so never energize the primary of the CT without making sure the secondary is shorted or has a closed loop. The closed loop can be the relays attached to the circuit. If the secondary winding is a closed circuit, current will flow proportional to the ratio of the primary current to the secondary current based on the nameplate ratio. So as the primary current enters the polarity side of the CT, the secondary current leaves the polarity of the secondary winding. If primary current entered the non-polarity side of the primary winding of the CT, then current would flow out the non-polarity side of the secondary winding of the CT.

leaving the station with 100 amperes of current. As mentioned earlier, the secondary current will be based on the CT ratio on one side of the secondary winding and is looking for the same amount of current returning to the other side of the secondary winding. In this case the primary current is 100 amperes with the CT ratio being 500/5, which equals 100:1. So there is 1 ampere secondary leaving the polarity of the secondary winding of the CT on Line 1. As the primary current continues through the station bus and heads out line 2, the primary current is entering the primary winding of the CT on line 2 on the non-polarity side of the CT. Thus, the secondary current leaves the secondary winding on the non-polarity of that CT on Line 2

Fig 3: Shows polarity marks with primary, as well as secondary current flow in a bushing mounted current transformer. If you notice in Figure 4, the polarity of the CT on Line 1 is tied to the polarity or Line 2 CT and the non-polarity on Line 1 CT is tied to the non-polarity of Line 2 CT. Bridged across these two circuits is the differential relay. So, during normal bus flow conditions the secondary currents in each CT satisfy each other and no current will flow through the differential relay. (This is also due to the impedance of the differential relay). Please note that this assumes a normal configuration. If CT on Line 1 is located on the bus side of the breaker these can be wired differently to make the circuit function correctly. It’s all about understanding how current flows in current transformers. What leaves the CT has to see the same amount of current return.

The next section will show how the current will flow in a differential circuit when in operation during a bus fault. In Figure 4 there is primary current flowing into the bus from Line 1 of a transmission line. In this instance, 100 amperes of primary current flows through the bus and out the other transmission line (Line 2),

Fig 4: Normal current flow in a basic bus differential relay scheme with CT secondary currents.

30 When a bus fault is introduced into the system, the primary current will now feed the fault from both Line 1 and Line 2 as seen in Figure 5. So both CTs on Line 1 and Line 2 will have the secondary current flowing out of the polarity side of the secondary windings. These current can’t push to the other CT since they are in opposing directions. So they total up and are driven through the differential relay element operating the relay. Once through, the currents hit the connection point, and they split up and equal amounts go to satisfy each secondary CT current back to the non-polarity connections.

Fig 5: Primary and secondary current flow during a bus fault in a basic bus differential scheme.

SECTION 2 - SYMETRICAL COMPONENTS Next up are fault sequences and why they are important. There are three types of sequence currents and voltages; positive, negative, and zero-sequence. All three will be discussed for the differential relay circuit. Most people are familiar with the phasor relation diagram on the nameplate of a transformer. Figure 6 shows a typical phasor drawings, except in this case, magnitude and direction arrows to the opposite end of the origins for the Star (or Wye) connection and the Delta connection.1 Note: these are sometimes referred to as vector diagrams. However, vectors describe direction and velocity in reference to physics. Electrical and mathmatical references to the term "phasor" indicates direction and magnitude. The angular difference when comparing the two against each other is a 30° shift in phase relations when comparing the high side phasor phase relationships to the low side phasor phase relationships. It is assumed the reader already understands this concept.

Protective Relay Vol. 2 International standard for phasor rotation is a 1-2-3 counter-clockwise rotation.2 It does not matter what you call each phase, they are all a counter clockwise rotation. For this case study we will call them A phase for phasor 1, B phase for phasor 2 and C phase for phasor 3. Looking at the Star connected phasors in Figure 7, the rotation marking is showing normal rotation for a stable balanced three-phase current. During a three-phase fault, not to ground, the current phasors increase in magnitude but remain in the same relationship with B phase lagging A phase by 120° and C phase lagging B phase by 120°. These are called positive sequence currents.

Fig 7: Phaser diagram showing positive sequence currents. During a three-phase fault, not to ground, the sequence remains the same. In a phase-to-phase fault involving B and C phase currents, the current flows out on the line away from the station on B phase but returns back to the station on C phase. Thus the phasor is 180° out of phase from the original C phase phasor prior to the fault. This now changes the order in the phase sequence. It still is counterclockwise but now C phase comes after A phase instead of B phase. These are called a negative sequence currents as shown in Figure 8.

Fig 8: A phase-to-phase fault involving B and C phases produce negative sequence currents. Fig 6: Star (or Wye) phasor diagram and Delta phasor diagram for transformers.1

During a three-phase fault to ground, all the currents leave the station on the line, but now go to ground. These currents go through the earth ground and return to the station and enter the ground grid in the station. They then return back to the neutral

31

Protective Relay Vol. 2 part of the transformer. These currents all have the same direction of phasors as they return back to the neutral. These are called zero-sequence currents as shown in Figure 9.

But, if the secondary CT is wired in a Delta configuration on the Wye (Star) connection side of the transformer low-side winding, we can prevent the zero-sequence currents from flowing into the relay circuit. Figure 11 shows that the secondary currents for a through fault now just circulate inside the Delta connected secondary wiring of the CT’s and no zero-sequence currents are allowed to operate the relay.

Fig 9: Faults that go to ground create zero-sequence currents. In this figure, this represents a three phase to ground fault. So why are we looking at current sequences and why are they important? The answer is the relay wiring in the scheme. The current circuit in a differential scheme should have only one ground connection. The reason it does not have two ground connections– one from each contributing CT– is to prevent circulating currents in the ground connections that could stop the currents from being forced through the differential relay during a fault. Having the one ground connection allows negative-sequence currents to enter the differential scheme. And remember, the current will take any and all paths to return to its source. This creates a problem on through faults that are not inside the differential zone of protection. This is why they wire the CT secondary wiring in the opposite configuration as the primary configuration of the transformer phaser diagram. It is not because of the 30° shift, it is to keep zero-sequence currents from entering the differential scheme and falsely operation the relay for through faults. In Figure 10, you will see a Delta-Star connected transformer for the high voltage to low voltage windings and the secondary wiring of the CTs wired both in the Star (Wye) configuration. During a through fault, the zero-sequence currents can enter the differential single-point ground and cause the relay to misoperate for external faults.

Fig 10: If both secondary CT circuits are wired Star (Wye) connection, the through fault zero-sequence currents can return through the ground and enter the differential circuit causing the relay to have a misoperation for a through fault outside the zone of protection.2

Fig 11: With the secondary wiring of the CTs on the Star (Wye) side winding of the transformer wired Delta, the through currents circulate inside the Delta connections, satifying the current returns without needing the zero-sequence current that would be trying to enter the differential scheme. This prevents the relay from operating on zero-sequence currents on through faults outside the zone of protection.2

SECTION 3 – INRUSH CURRENTS AND HARMONICS When a transformer is first energized, you get transient magnetizing or excitation current to flow. This is called inrush current. There are many factors involved on how big the inrush current is and how long it can last. This is determined by the size of the transformer and the system, the type of core steel used in the transformer and the flux density, the resistance of the power system from the source to the transformer, the history or residual flux in the transformer, and how many other transformers may be in parallel with it. There are many papers written on this subject of inrush currents and what affects it.3 These papers are well worth reading. But, for the purpose of this paper, only the fact that these factors influence inrush current is mentioned. These inrush currents, depending on all those factors mentioned, can have instantaneous currents of eight to more than thirty times the full load rating of the transformer, and the inrush currents can last from around ten cycles to several minutes depending on the circumstances.1,2,3 Detailed system studies are required to see how your system can be affected by this phenomenon. There are also formulas for calculating inrush currents. 1,3 Harmonics are developed during CT saturation on inrush as well as faults. These harmonics can delay the operation of relays using harmonic restraint or harmonic blocking features in the relays. It takes about one cycle or longer to saturate a CT. Current transformers repro-

32 duce the primary current for a given time after the fault. The worst CT saturation is produced by the DC component of the primary current. During this saturation, the secondary current of the CT can contain DC offsets, odd and even harmonics. When the DC offset dies out, the saturation has only AC saturation that is dominated by odd harmonics and very little even harmonics in the secondary current. Fault currents tend to have high odd harmonics and inrush current tends to have high even harmonics, especially second harmonics at 120Hz. Second harmonics increase as the inrush current increases. That is why they use harmonic restraint relays. They use second harmonics to help restrain the operation on inrush. Other harmonics can also be used such as in microprocessor relays. The restraint coils prevent the relay from operating until the operating current at 60Hz increases enough to override the effect of the restraint coils. Figure 12 shows the location in the circuit where the restraint coils reside.

Protective Relay Vol. 2 Harmonic restraint relays, the 15 percent tapsetting for some relays, is based on an inrush current of 1.40 pu (per unit) at zero degrees closing angle. Modern transformers can have saturation density values as low as between 1.30 and 1.20 with some as low as 1.15 pu. What this means is that some modern transformers with these low density levels may not have enough second harmonics content to restrain the relay and can trip on inrush when energizing. This is not a common occurance but does happen. Newer microprocessor relays allow the engineer more options for restraint or blocking features to prevent false tripping. They may use second and fourth harmonics to restain or block tripping, which can be added together. Fifth harmonic blocking may be used to prevent undesired operation during over excitation.4 In the microprocessor relays, the harmonic restaint, or blocking setting, is referred to as the “K” factor. The restaint element is typically based on the inverse of the percent harmonic setting where the percent value is entered as a setting for each selected harmonic.5 See Figure 14.

Fig 12: Harmonic restraint coils use 120Hz to help restrain the operating coil during inrush currents until the 60Hz operating current increases enough throught the operating coil to override the restraint current. Most restraint relays have several tap setting to set the amount of restraint. They have 10, 25 or 50 percent tap settings. Generator differential relay usually use the 10 or 25 percent tap. Transformers use the 50 percent restraint tap because the current transformers on each side of the transformer have different voltage ratings. Harmonic restraint relays also have what is called a slope setting. The slope setting allow you to push, or increase, the restraint region while decreasing the operate region by pushing the operating slope line up, as seen in Figure 12, when there is increasing harmonics.5,6

Fig 14: Microprocessor relay logic for percent restraint with harmonic blocking element There are advantages and disadvantages when it comes to using harmonic restraint verses harmonic blocking. The advantage of using harmonic restraint is that it tends to be more secure than harmonic blocking. This is because any harmonic content, even small amounts, will increase the restraint. The disadvantage of harmonic restraint is that it may operate slightly slower for internal faults.5 Harmonic blocking needs enough harmonics to pick up the setting in the relay in order to operate. So, small amounts of harmonics may not block the relay from operating.

SECTION FOUR – HOW TO DETERMINE DIFFERENTIAL RELAY SETTINGS

Fig 13: Relay slope settings increase the restraint region while reducing the operate region.

For this example, General Electric BDD differential relays are used to protect a transformer configured Delta-Star (Delta-Wye), 115kV to 13.8kV and rated at 33.6MVA. But in this senerio, the low side bus normally runs at not 13.8kV but at 13.2kV. I use this example to show how engineers determine the settings on the relay, not based on the nameplate data, but more on how the system voltages run in their area.

33

Protective Relay Vol. 2 So first, the full load currents in the CT circuits for the high side and low side of the transformer will need to be calculated. To do this we use the formula shown in Figure 15. By looking at the diagram in Figure 16, we have all the information to calculate the primary currents for the high side and the low side of the transformer.

With loop circuits, not all of the current would get to the relay, thus preventing operation when needed. Newer microprocessor relays can convert the configurations inside the relay using software, so there is no need to wire the delta and star (wye) configurations. They can be wired either both star (wye), or both delta, but you still need to keep track of setting the relay to prevent zero-sequence currents from operating the relay as described earlier.5

Fig 15: The formula for calculating the full load current for either side of the transformer.3 Figure 16 shows the results of the following calculations: The high side primary current is: 33,600,000 ÷ (115,000 x √3) = 168.69A. The low side however needs to use the voltage that the bus normally runs at in this calculation. So the low side primary current is the result of the formula: 33,600,000 ÷ (13,200 x √3) = 1,469.62A. Fig 16: Transformer current differential circuits and calculations.

Now to find the secondary current in the CTs, we use the ratio of the CTs to determine the current. On the high side star (wye) connected CT, the ratio is 200/5 or 40:1. So 168.69A ÷ 40 = 4.22A secondary current. The current going through the CTs, that the secondary wiring is connected delta on the low side of the transformer, has a ratio of 2000/5 or 400:1. So the calculation is 1,469.62A ÷ 400 = 3.76A inside the delta connected secondary. To find the current going to the differential relay outside the delta connected secondary wiring, we have to multiply this amount by the square root of three (√3). So 3,76A x √3 = 6.36A. We now know the currents going to the GE BDD relay. From the high side, it is 4.22A and from the low side it is 6.36A. Obviously this in an imbalance current so the taps on the BDD relay will act as a current balancing transformer to balance the currents. The ratio of the current is 4.22 ÷ 6.36 = 0.66. So we have to select the correct taps to either match or as closely match that ratio. In this case selecting tap 3.2 and 5.0 gives us the closest match so looking at the ratio of the taps we get 3.2 ÷ 5.0 = 0.64 for a ratio. See Figure 16. Some utilities will install current balancing transformers in the circuit to balance the currents before they get to the differential relays so the relay will not have any mismatch and the taps can be set on the same tap settings. This allows almost no current to flow in the differential relay during normal operation. The current transformer circuits that feed the differential relay are only grounded at one point, usually at the relay. The reason for one ground is to prevent loop circuits in the multiple grounds.

SUMMARY: I hope this has given the reader insight on how current transformers work in a differential relay scheme and what happens during faults. I have tried to give you enough information to understand how a basic differential relay setting is done, as well as let you know some of the effects that inrush and fault currents can differ, thus effecting the operation of the relays. This is just an overview of the basic differential protection schemes. There are many more complex types of protection schemes that I did not cover in this paper. Other schemes such as wave form blocking, cross blocking, and negative sequence based internal and external discriminators are used.

REFERENCES: Electrical Transmission and Distribution Reference Book, ABB Power T&D Company Inc., 1997. 1

Applied Protective Relaying, Westinghouse Electric Corporation., 1982 2

Transform Interaction Caused by Inrush Current, H. S. Bronzeado, Companhia Hidro Elétrica do Sãn Francisco – CHESF – Recife, Brazil and R. Yacamini, University of Aberdeen, Department of Engineering, Aberdeen Scotland.

3

Differential Protection for Arbitrary Three-Phase Transformers. Zoran Gaji, Department of Industrial Electrical Engineering and Automation, Lund University.

4

34 Considerations for Using Harmonic Blocking and Harmonic Restraint Techniques on Transformer Differential Relays. Ken Behrendt, Normann Fisher, and Casper Labushagne, Schweitzer Engineering Laboratories, Inc., 2006 Western Protective Relay Conference. 5

6 "Transformer

Differential Relay with Percentage and Harmonic Restraint," in General Electric Relay Manual GEH-1816, BDD15B/BDD16B.

Jay M. Garnett has worked for Doble Engineering since 2011 as a principal engineer in the Client Services Department based in the Sacramento, California offices. Jay has worked in the utility industry for over thirty-four years and has experience in substations, hydroelectric, geothermal, fossil fuel, nuclear generation, construction, maintenance, and testing. He worked as a substation maintenance engineer for National Grid USA in the Substation O&M Services NE/NY Department from 2007 to 2011. Before that he was a supervisor overseeing the relay department for over five years. He also was a relay technician for National Grid (formerly Niagara Mohawk) in the Albany, NY area starting in 1992. Jay worked for Pacific Gas and Electric Company from 1983 until 1992, in the General Construction Department as an electrician and then as an electrical technician before moving to Albany, NY in December of 1992. Jay is a graduate from Napa Community College where he studied geology and received an Associate of Arts degree. Jay has also completed six years of apprenticeships, holding certificates as a journeymen Electrician and a journeymen Electrical Technician in the State of California. He has vice-chaired and chaired the Bushings Insulators and Instrument Transformer (BIIT) Committee at Doble while working at National Grid and is currently the assistant secretary of the Asset Management and Maintenance (AMM) committee at Doble. Jay has been a member of IEEE since 2007.

Protective Relay Vol. 2

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Protective Relay Vol. 2

CURRENT TRANSFORMER SATURATION AND RESIDUAL MAGNETISM PowerTest 2014 Will Knapek, OMICRON electronics Corp.

ABSTRACT The understanding of current transformers and the knowledge of all relevant current transformer data is of particular importance to optimize the performance of protection relays as well as the entire power system. For current transformers subjected to high fault currents or DC components the magnetic cores may saturate. For protection CT's this is an undesirable effect since particularly under heavy fault conditions a correct replica of the primary current is required for the protection relay to function properly. This paper will explore the effects of CT saturation and the resulting residual magnetism left in the current transformer. Techniques of how to measure residual magnetism and the consequences of residual magnetism will also be discussed. Current transformers are sometimes overlooked as a critical component of the fault clearing system. Their importance has been recognized by NERC in the recent issue of PRC 005-2. Current Transformers (CT’s) have been added as critical components to be tested on a periodic basis. However, the testing outlined by NERC, does not address a hidden problem that a CT can have. That problem is residual magnetism. To fully understand what residual magnetism is and how to avoid it, let’s examine CT basics. CT’s are designed to transform a high current to a lower current that can be used by relaying or metering devices. The following three basic principles are important to remember: ●● When AC current flows through a wire (Primary) an Electric Field is created. ●● Current passes through toroid made of ferromagnetic material such as iron; magnetic flux is generated in the iron core. ●● Wire is wrapped around the iron core, with a number of turns (N). This causes a current flow that is proportional to the magnitude of the primary current divided by the number of turns on the secondary winding. Looking at the CT from an equivalent current perspective we can better understand how the CT works. In Figure 1, is the CT equivalent circuit.

Fig. 1 Ip = Primary Current Np, Ns = Number of Turns in Ideal Transformer Lmain = Main Inductance RH = Hysteresis Resistance Reddy = Eddy-Current Resistance Rct = Resistance of the Secondary Winding RB = Resistance of the Burden VT = Terminal Voltage From this circuit we can look the CT from a testing perspective. In the core for the characteristics of ratio and polarity are found. In the parallel equivalent circuit, excitation characteristics are defined. And finally, the Rct is the area that defines the secondary winding resistance. CT’s can fall into two main classifications: metering and protection. A metering CT is designed to work accurately within the rated current range. In case of overcurrent, the metering CT shall become saturated (with sufficient burden), in order to protect the connected metering and measurement devices from overloading. Accurate representation of current is not a concern above saturation. A protection CT is designed to transform an ideally distortion-free signal even in the overcurrent range. This enables the connected protection relay for measuring the fault current value correctly. In a protection application the accurate representation of the high current level is of extreme importance to the correct operation of the fault clearing system. The remainder of this paper will focus on the protection CT.

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Protective Relay Vol. 2

A protection CT must exhibit the following characteristics: ●● The need to operate at high fault current with acceptable accuracy ●● Must have high excitation voltage to avoid saturation ●● Multiple ratios for different applications ●● Transient characteristic is important ●● Testing mainly concerned with saturation level ●● Burden is important In the North American market, IEEE C57.13-2008 defines the performance of CT’s and sets classes defining the performance. This standard defines three accuracy classes: C, T, and X. IEC uses a different system. The C classes of CT’s are the most common in North America. The C class of CT is defined as having a less than 3% ratio error at rated current, less than 10% ratio error at 20 times rated current, and a standard burden 200V/ (5A x 20) = 2Ω. The three numbers after the class designation means, secondary terminal voltage which the CT must maintain within the C Rating. The saturation of the CT occurs when the core has reached its maximum flux density, thereby causing a distortion of the secondary current. For C class transformers, typical excitation curves are drawn on log−log coordinate paper. The knee is defined as the point where the tangent is at 45° to the abscissa.

Fig. 3 It can be seen in the following figures the effects of saturation has on the secondary current seen by the protective relay. As the core is excited above saturation, the distortion becomes unacceptable.

Fig. 4: Non Saturated CT

Fig. 2 When trying to understand the concept of saturation, a BH curve allows us to visualize this very easily. H is the magnetic force generated by the primary current and is directly proportional to the instantaneous value of the excitation current. B is the flux density which is proportional to the time-integral of the Ve (or the area underneath the Ve sinusoid), and has the unit of Tesla. See Figure 3. Fig. 5: Saturated CT

37

Protective Relay Vol. 2 Now this leads us to the phenomena of residual magnetism. When the primary current is suddenly cut-off, H drops to zero, but B drops to a value that is positive or negative tesla. This value also known as residual magnetism and has effects on relaying applications. In the ideal CT, the magnetism should always start at the zero, zero point on the BH curve. This is not the case when there is any magnetism left in the core. Residual magnetism in CTs can be quantitatively described by the amount of flux stored in the core as shown in the following equation.

Eq. 1 Look at the following diagrams and see how the residual magnetism effects the time that a CT will saturate under fault conditions. In Figure 6, the normal primary current is flowing in the CT. Under a fault condition you have 20 times that value in reserve before you saturate the core. In Figure 7, the core has residual magnetism, so the nominal operation current is at a higher level on the Flux Density axis of the BH curve. In a fault condition, the CT will now saturate much faster due to the loss of the reserve Flux Density. See Figure 8.

Fig. 6: Normal Operation

Fig. 8: Loss of flux density reserve with residual magnetism Typical residual magnetism effects in CT cores appear after being confronted with very high transient fault currents during fault conditions. Another cause of residual magnetism is from the circuit breaker not extinguishing the electrical arc at zero crossing of the current signal. And the most common cause is the failure to demagnetize the CT after testing. The DC winding resistance measurement with magnetize the core. The demagnetization process is done by applying at least the same electrical force as that which caused the magnetization effect. To perform this process it is recommended to start with similar force as the force which drove the core into saturation than reducing step by step to demagnetize the core. In other words, apply a DC current to the core in a higher value than it would take to saturate the core. Then reverse the current with a slightly less current. Repeat this until the current used is at zero. To determine residual flux it is essential to calculate voltage and current time integrals taken over the measurement duration. If calculation of these integrals can be made real-time (i.e. simultaneously with input sampling), there is no need to store input data of current and voltage channels. Thus, even if saturation process is very long, it will still be possible to calculate residual flux, which allows applying this method to residual remanence measurement for both CTs and transformers. The residual magnetism can be determined relatively precisely using simple test apparatus. A DC source such as a car battery and a recording device that will monitor current and voltage over time is all that is needed. The test is performed in three steps: ●● Load is applied until I0 and V0 are constant. ●● This is then repeated with opposite polarity. ●● This is then repeated once more with opposite polarity.

Fig. 7: CT with residual magnetism

●● Once the measurements are performed the complicated evaluation must be done. With voltage V0 applied, the current I0 increases. The internal load of the transformer Z0 drops until V0, I0 and Z0 are constant. As the flux in the core increases, the main inductance LH of the transformer changes. At maximum flux, the unsaturated inductance LS becomes the saturated inductance LS. The reactance XLS of the saturated main induc-

38

Protective Relay Vol. 2 tance LS is several times lower than the DC internal resistance RCT of the transformer. As such, Z0 = RCT at constant current flow. If RCT is known, the voltage can be calculated via the main inductance LH. The area below the voltage VLH is the magnetic flux [Φ in Vs] in the current transformer's core. Calculation of the flux via the integral of the voltage VLH is the next step in the evaluation.

Eq. 2



This needs to be done for all three measurements. Conclusions regarding the flux of the transformer at the start of the measurement are determined by the difference between Φ3 and Φ1; this is the flux level prior to starting the measurement.

Eq. 3

"Guide for the Application of Current Transformers Used for Protective Relaying Purposes," IEEE Standard C37.110-2008. 6

"Failure diagnostic at CTs for unwanted parallel primary impedance, IMTF 2011, Florian Predl, OMICRON. 7

"Explore new paths with the CT Analyzer – Extended testing benefits for your applications," IMTF 2010, Florian Predl, OMICRON, Austria. 8

William Knapek received a BS degree in Industrial Technology from East Carolina University in 1994. He retired from the US Army as a Chief Warrant Officer after 20 years of service in 1995. During his time with the Army Corps of Engineers, he held positions as a power plant instrumentation specialist, a writer/instructor for the Army Engineer School, and a Facility Engineer for a Special Operations compound. He has been active in the electrical testing industry since retiring in 1995. He worked for NETA companies in the Nashville, TN area until joining OMICRON electronics as an application engineer in April of 2008. He is currently the Sales Manager for the Southeast Area of North America for OMICRON electronics Corp, USA. He is certified as a Senior NICET Technician and a former NETA Level IV technician. Will is a member of IEEE and vice chair of WG I23 of the PSRC

Eq. 4 As you can see this is an involved process to measure and then perform the calculations to determine the residual magnetism of a CT in the field. There is a test set that can perform this task for you.

SUMMARY Residual magnetism will affect how a CT performs during a fault. How much of an effect will be determined by how much residual magnetism is in the core. It is a recommended practice to Demag after all tests. Especially after any DC test such as a winding resistance test of a CT. It would also be recommended to Demag after faults on critical circuits.

REFERENCES 1

CT Analyzer Theoretical Background, OMICRON electronics.

2

CT Analyzer User Manual, OMICRON electronics.

"Instrument Transformers, Part 1: Current Transformers," IEC 60044-1 Edition 1.2 / 2003-02: Reference number CEI/IEC 60044-1:1996, A1:2000, A2:2002. 3

"Instrument transformers, Part 6: Requirements for protective current transformers for transient performance," IEC 60044-6 First Edition / 1992-03: Reference number CEI/IEC 44-6:1992. 4

"Standard Requirements for Instrument Transformers," IEEE Standard C57.13-2008.

5

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Protective Relay Vol. 2

HOW DISRUPTIONS IN DC POWER AND COMMUNICATIONS CIRCUITS CAN AFFECT PROTECTION PowerTest 2016 Karl Zimmerman and David Costello, Schweitzer Engineering Laboratories, Inc.

ABSTRACT Modern microprocessor-based relays are designed to provide robust and reliable protection even with disruptions in the dc supply, dc control circuits, or interconnected communications system. Noisy battery voltage supplies, interruptions in the dc supply, and communications interference are just a few of the challenges that relays encounter. This paper provides field cases that investigate protection system performance when systems are subjected to unexpected switching or interruptions in dc or communications links. The discussion emphasizes the importance of environmental and design type testing, proper dc control circuit design and application, reliable and safe operating and maintenance practices with respect to dc control circuits and power supplies, and considerations for reliable communications design, installation, and testing. Some practical recommendations are made with regard to engineering design and operations interface with equipment to improve protection reliability and reduce the possibility of undesired operations.

THE ROLE OF DC AND COMMUNICATIONS IN PROTECTION SYSTEMS Fig. 1 shows a one-line diagram of a typical two-terminal line protection system using distance relays in a communicationsassisted pilot scheme. Bus S

Bus R 52

21

52

Communications Equipment

Communications Equipment

21

Channel

125 Vdc

48 Vdc

48 Vdc

125 Vdc

Fig. 1: Two-Terminal Digital Line Pilot Protection Scheme. To successfully clear all faults on the line within a prescribed time (e.g., less than 5 cycles), all of the elements in Fig. 1—breaker, relay, dc supplies, communications, current transformers (CTs), voltage transformers (VTs), and wiring—need to perform correctly. It is not unusual for lines to have redundant and backup protection schemes, often using different operating principles, with multiple channels and/or dc supplies.

Human factors (such as design, settings, procedures, and testing) are not shown in Fig. 1 but must also perform correctly. Additionally, security is as important a consideration as dependability. All of the elements and human factors must perform correctly to ensure that the protection scheme correctly restrains for out-ofsection faults or when no fault is present.

THE EFFECT OF DC AND COMMUNICATIONS DISRUPTIONS ON OVERALL RELIABILITY Protection systems must be robust even with transients, harsh environmental conditions, and disruptions in dc supply, dc circuits, or interconnected communications. These disruptions include loss of dc power due to failure or human action, noise on the battery voltage, dc grounds, interruptions in dc supply, and subsequent restart or reboot sequences. In the case of communications, these disruptions include channel noise, channel delays, interruptions due to equipment problems or human action, unexpected channel switching, and restart or resynchronization sequences. Fault tree analysis has been beneficial in analyzing protection system reliability, comparing designs, and quantifying the effects of independent factors. For example, the rate of total observed undesired operations in numerical relays is 0.0333  percent per year (a failure rate of 333 • 10–6). By comparison, the rate of undesired operations in line current differential (87L) schemes where disturbance detection is enabled is even lower at 0.009 percent per year (a failure rate of 90 • 10–6). However, undesired operations caused by relay application and settings errors (human factors) are 0.1 percent per year (a failure rate of 1,000 • 10–6) 1. Unavailability, which is the failure rate multiplied by the mean time to repair, is another measure used to compare reliability. The unavailability of dc power systems is low at 30 • 10–6, compared with 137 • 10–6 for protective relays and 1,000 • 10–6 for human factors. These data assume a faster mean time to repair a dc power system problem (one day) compared to relays and human factors (five days). Communications component unavailability indices are similar to those of protective relays 2. The North American Electric Reliability Corporation (NERC) State of Reliability 2014 report found that from the second quarter of 2011 to the third quarter of 2013, 5 percent of misoperations involved the

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Protective Relay Vol. 2

dc system as the cause, compared with 15 percent for communications failures, 21 percent for relay failures, and 37 percent for human factors 3. From these data, we can see that dc and communications failures are a small but significant factor in reliability.

The protection system, and the entire power system, is very similar to the aviation industry. Fault trees and high-level apparent cause codes do not necessarily make these subsystem interdependencies apparent.

Fault trees allow us to see how the failure rate of one device impacts the entire system (see Fig. 2). Fault trees also allow us to evaluate how hidden failures, common-mode failures, improved commissioning tests, and peer reviews impact reliability.

For example, in December 2007, while performing maintenance testing, a technician bumped a panel and a microprocessor-based, high-impedance bus differential relay closed its trip output contact (87-Z OUT1 in Fig. 4), tripping the bus differential lockout relay (86B in Fig.  4). Fortunately, due to testing that was being performed that day, the lockout relay output contacts were isolated by open test switches that kept it from tripping any of the 230 kV circuit breakers.

1178 Note: Numbers shown are unavailabilities • 106

Protection Fails to Clear In-Section Fault in the Prescribed Time

3

589

589

Protection at S Fails

Protection at R Fails

Same as Protection at S 2

17 203

4

Common-Mode Common-Mode Hardware/ Settings/Design Firmware Errors Failures 500 5

Breaker at S Fails to Interrupt Current 80 1969

2219

Main 1 Protection at S Fails

18

204 13

TS 87-Z OUT 1 TS

Main 2 Protection at S Fails

14 1

Relay Fails 137

Relay App. or Settings Errors 1000

Breaker Trip Coil Fails 120

DC System Fails 30

CT Fails 3•9 = 27

VT Fails 3 • 15 = 45

CT Wiring Errors 50

VT Wiring Errors 50

DC Wiring Errors 50

Hidden Microwave Microwave Microwave Comm. Failures Channel Tone Transceiver DC 10 Fails Equipment Fails System 100 Fails 200 Fails 100 50

G F

Fig. 2: Dependability Fault Tree for Dual-Redundant Permissive Overreaching Transfer Trip (POTT) Scheme 2. However, fault trees do not easily identify how a failure or activity in one subsystem affects another subsystem. Inspired by Christopher Hart, acting chairman of the National Transportation Safety Board, we wanted to investigate the interaction of components, subsystems, and human factors on the reliability of the entire protection system. At the 2014 Modern Solutions Power Systems Conference, Mr. Hart spoke of the aviation industry as a complex system of coupled and interdependent subsystems that must work together successfully so that the overall system works. In aviation, a change in one subsystem likely has an effect throughout other subsystems (see Fig. 3) 4.

Fig. 3: Aviation Safety Involves Complex Interactions Between Subsystems.

86B C B

Fig. 4: DC Control Circuit Showing Bus Differential Trip Output. The bus differential relay contact closure was easily repeated by bumping the relay chassis. The simple apparent cause could have been classified as human error, product defect (failure to meet industry shock, bump, and vibration standards), or relay hardware failure. However, subsequent analysis by the relay manufacturer showed momentary low resistance across the normally open contact when the chassis was bumped. Additionally, visual inspection noted evidence of overheating in the contact area (the outside of the plastic case was slightly dimpled). The contact part was x-rayed while it was still mounted on the main printed circuit board. The adjacent, presumed-healthy contact was x-rayed for comparison. The x-ray images are shown in Fig. 5, with the adjacent, healthy Form-C contact on the left and the damaged Form-C contact on the right. In each contact, there is a stationary normally open contact surface (top), a moving contact surface (center), and a stationary normally closed contact surface (bottom). Note the difference in contact surfaces and spacing. The relay manufacturer estimated that the output contact was likely not defective but rather had been damaged due to interrupting current in excess of the contact’s interruption rating.

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It is important at this point to persist in analysis and examine testing mandates, procedures, and work steps to find root cause. In this case, commissioning testing, represented as one human factor subsystem in the fault tree (relay application), performed to improve reliability was flawed in such a way that the protective relay hardware was damaged and induced a failure in that subsystem. In addition, maintenance testing, mandated by NERC and intended to improve reliability, was flawed in such a way that the relay was damaged and could have potentially caused a misoperation.

Fig. 5: X-Ray Images of the Healthy, Adjacent Contact (Left) and Damaged Contact (Right). The output contact manufacturer further inspected the output contact part. The output relay cover was removed and the inside of the part was observed and photographed (see Fig.  6). The plastic components were melted, the spring of the contact point was discolored and deformed by heat, and the contact surfaces were deformed, rough, and discolored. The root cause of the contact damage was confirmed: at some point prior to the misoperation, the interrupting current was in excess of the contact’s interruption rating.

In this example, the failure mode was a relay contact closing when the relay chassis was bumped. According to NERC data, 60 percent of rootcause analyses stop at determining the mode 5. True root-cause analysis requires us to dig deeper to understand the failure mechanism or process that led to the failure. Then, we can educate others and ensure that improvements prevent the problem from reoccurring. In NERC contributing and root-cause vernacular, this incident would be due to a defective relay (A2B6C01) caused by an incorrect test procedure (A5B2C07) caused by a failure to ensure a quality test procedure (A4B2C06). An important theme in the case studies that follow is how an action or failure in one subsystem affects other subsystems and overall reliability.

TRADITIONAL DC PROBLEMS The dc control circuits used in protection systems have always been complex. Problems that need to be mitigated include circuit transients, sneak or unintended paths, stored capacitance, letthrough and leakage currents, and more 6. For example, electromechanical auxiliary relays were once commonly used for local annunciation, targeting, or contact multiplication. Some of these relays were high speed and quite sensitive. Care was taken to ensure that let-through currents from connected output contacts did not inadvertently cause these auxiliary relays to pick up. Especially when used with transformer sudden pressure relays with poor dielectric withstand capability, extra security measures were taken to prevent auxiliary relays from operating in case a voltage surge caused a flashover in the normally open contacts of the pressure relay. In Fig. 7, the normally closed contact from the sudden pressure relay (63) shunts the auxiliary relay operating coil (94) so that if the normally open contact flashes during a voltage transient, the auxiliary relay will not operate 7. (+) 63

63

94

94

94

86

Fig. 6: Pictures From Contact Manufacturer Confirming Heat Damage From Exceeding Current Interruption Rating.

(–)

Fig. 7: Typical Security Precaution for Dielectric Strength Failure of a Sudden Pressure Relay Contact.

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Protective Relay Vol. 2

Precautions must be taken to avoid these same dc circuit anomalies as we transition to new technology platforms and design standards. As auxiliary relays are replaced by microprocessor-based relays, pick-up time delays are required on relay inputs that are used to directly monitor these same sudden pressure relay normally open contacts to maintain security 8.

TRADITIONAL COMMUNICATIONS PROBLEMS Communications that are used for protection systems perform well but are not perfect. One well-known communications component problem involves the application of power line carrier for transmission line protection schemes. In directional comparison blocking (DCB) schemes, high-frequency transients can produce an undesired momentary block signal during an internal fault. Fig. 8 shows one such incident. Engineers must adjust frequency bandwidths, add contact recognition delay, or tolerate the possibility of a slight delay in tripping for internal faults. Conversely, if an external fault occurs, the momentary dropout of the carrier blocking signal, referred to as a “carrier hole,” can produce an undesired trip, as shown in Fig. 9. These dropouts are often attributed to a flashover of the carrier tuner spark gap and can be avoided by improved maintenance of the carrier equipment or can be dealt with by adding a dropout delay on the received block input.

Protection system communications options today include many media in addition to power line carrier, such as microwave, spread-spectrum radio, direct fiber, multiplexed fiber networks, Ethernet networks, and more. Each medium has its own set of potential problems, such as channel noise, fault-induced transients, channel delays, dropouts, asymmetry, security, buffers and retry, interruptions due to equipment problems or human action, unexpected channel switching, and restart or resynchronization sequences. The trends in our industry include communicating more, exploring new and creative applications for communications, and replacing intrastation copper wiring with microprocessor-based devices and communications networks. As more and more communications and programmable logic are used, it is critical to analyze, design, and test for potential communications problems.

TRADITIONAL PROCEDURE PROBLEMS The sequence in which work tasks are performed is important. A familiar example will highlight this concept. A primary microprocessor-based line relay had been taken out of service for routine maintenance testing. Trip and breaker failure initiate output contacts, as well as voltage and current circuit inputs, had been isolated by opening test switches. After successful secondary-injection testing, the relay tripped the circuit breaker during the process of putting the protection system back into service 9. Event data showed only one current (A-phase) at the time of trip. This indicated that the technician had reinstalled the trip circuit first by closing the trip output test switch. Next, a single current was reinstalled by closing its test switch. Because there was load flowing through the in-service breaker and CTs, the relay, at this step in the sequence of events, measured A-phase current and calculated 3I0 current and no voltages. It issued a trip.

Momentary Carrier Block

Fig. 8: Momentary Carrier Block Input Produced by FaultInduced Transient.

This was a valuable lesson for this utility in the early adoption phase of these relays and led to a specific procedure and sequence that is used when returning a relay to service. The sequence of steps used to restore the system to service is the reverse of that used to remove the system from service and is as follows. 1. Place all three voltage circuits back into service (i.e., close the voltage test switches). 2. Place all three current circuits back into service. 3. Use meter commands or event data to verify the proper phase rotation, magnitude, and polarity of the analog measurements. 4. Reinstall the dc control inputs.

Carrier Holes

Fig. 9: Carrier Holes in a DCB Scheme.

5. Use target commands or event data to verify the statuses of control inputs. 6. Reset relay targets and verify that trip and breaker failure outputs are reset. 7. Place the trip and breaker failure output circuits back into service.

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Protective Relay Vol. 2 Similarly, when disrupting communications circuits or dc power, we must thoughtfully consider what parts of the protection system should be isolated and the careful order of steps to take in the process of returning the system to service. Analysis, design, and testing should be devoted to this, considering our increased dependence on interdevice communications and programmable logic. The following section highlights some interesting system events where disruptions in dc and/or communications directly affected protection.

PROTECTION SYSTEM EVENTS CAUSED BY DC OR COMMUNICATIONS SYSTEM DISRUPTIONS Case Study 1: Breaker Flashover Trip After Relay Restart Fig.  10 shows the simplified one-line diagram of a 161  kV substation for an event in which a breaker failure flashover logic scheme operated after a relay restart (i.e., dc power supply to the relay was cycled off and on), causing a substation bus lockout. Remote I/O Module

The user applied the I/O module to eliminate extra wiring and inherent noise and hazards associated with long (i.e., several hundred feet) runs of copper wire. Also, the fiber connection was continuously monitored. The monitored communications link can be set to default to a safe state, as specified by the engineer. In this case, if communications were lost (e.g., fiber was disconnected or damaged or there was an I/O module failure), the breaker status would default to its last known state before the communications interruption. The breaker failure flashover logic is shown in Fig. 12. It detects conditions where current (50FO) flows through an open breaker (NOT 52a). When a breaker trips or closes, the logic is blocked with a 6‑cycle dropout delay. The user can define a time delay for breaker failure to be declared. In this case, it was 9 cycles. 50FO 52a Trip or Close

Dropout Delay 0

S

Q

6

Breaker Failure Flashover Timer 9 0

Breaker Failure Flashover

Communications Link

R 21, 67, etc. 50BF With Breaker Flashover Logic

161 kV

12.47 kV Lockout Relay

Fig. 12: Breaker Failure Flashover Logic. The event data in Fig. 13 show the status of the relay elements immediately after the power cycle. Current is already present, but the breaker status (52AC1) is a logical 0 (not asserted). Thus, the breaker failure flashover element (FOBF1) asserts and produces the breaker failure output (BFTRIP1), which subsequently operates the substation lockout relay.

Fig. 10: Case Study 1 System One-Line Diagram Uses Remote I/O Module for Breaker Interface. In this system, the breaker status auxiliary contacts (52a and 52b) and other monitored breaker elements are connected to a remote I/O module. The I/O module converts hard-wired inputs and outputs to a single fiber link from the module at the breaker to the relay located in a remote control house (see Fig. 11). 52 Trip 1 52 Trip 2 52 Close Communications Link

52 Low Gas Alarm 52 Low Gas Trip I/O Module Alarm

Remote I/O Module

Relay

52 Spring Charge Alarm 52 Trip Coil Monitor 1 52 Trip Coil Monitor 2 52a 52b

Fig. 11: Monitored Points From the 161 kV Circuit Breaker Using a Remote I/O Module and Fiber Interface to the Relay.

Fig. 13: Breaker Failure Flashover Logic Asserts Due to Current Measured While Breaker is Sensed Open. The undesired trip occurred because the breaker failure flashover logic began processing before the communications link between the I/O module and the relay was reestablished. We can see the communications link status between the relay and the I/O module (ROKB) asserted about 14 cycles later.

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Protective Relay Vol. 2

The event report does not show much about what happened before the trip during the relay restart process. However, from an internal sequential event record, we were able to assemble the timeline, as shown in Fig. 14. Pre-Event Report Relay Restart

dc power to the relay was switched off and on, the lockout logic output asserted, causing a substation trip and loss of supply to several customers.

Event Report 9 Cycles

22 Cycles

87 S

Line Switch (89)

R

86

9b

8

Q FOBF1

1/4 Cycle

BFTRIP1

T

52AC1

Alternate Source

ROKB

Communications Link Reestablished

Fig. 14: Event Timeline Shows Relay Restart and Arming of Flashover Logic Before Breaker Status Is Recognized. The relay restart sets the latch (Q) and starts the 9‑cycle breaker failure flashover timer. At 9 cycles, FOBF1 asserted. By the time the communications link was established (at 22  cycles), the trip had already occurred. Important lessons were learned in this case study. Relays and I/O modules might reboot, operators may cycle power to relays when looking for dc grounds or performing other troubleshooting, relays may employ diagnostic self-test restarts, and so on. There is no default state for most logic during a relay restart. In a relay restart, all of the logic resets and begins processing from an initial de-energized state, as is the case when a relay is powered up and commissioned for the first time. In this case, designers considered a loss of communications but did not consider how a loss of dc supply or relay power cycle would affect the communications status and the logic processing order during a start-up sequence. In the breaker failure flashover logic, the breaker status is used directly in a trip decision. We should supervise the breaker failure flashover logic with the monitored communications bit (i.e., FOBF1 AND ROKB) to prevent the flashover logic from being active until communication is established. To further avoid such undesired operations, commissioning tests should include power cycles to test for secure power-up sequences in logic processing.

Case Study 2: Protective Relay Applied as a Lockout Relay Operates Due to a Power Cycle In Case Study 2, a microprocessor-based transformer differential relay was applied as a lockout relay, as shown in Fig. 15. When

Fig. 15: One-Line Diagram of Relay Applied as a Transformer Differential Relay and Lockout Relay Together. Discrete lockout and auxiliary relays are widely used in protection systems. Why not use a discrete lockout relay here instead of building these functions inside the microprocessor-based relay? The decision to do this was driven by several factors. One factor was reduced cost—fewer relays and less panel space and wiring. In addition, periodic maintenance testing was reduced by having fewer devices and by extending the maintenance intervals due to the inherent self-monitoring capability of the microprocessor-based relay versus the electromechanical lockout relay. Additionally, some system events have also led engineers away from using discrete auxiliary and lockout relays. One infamous event that is often cited for this change in design was initiated by a failed auxiliary relay at Westwing substation 10. The internal relay lockout logic for Case Study 2 is shown in Fig. 16. External Trip

LT1 S R

Q

LT2 87T Trip

S R

Q

86 (Lockout)

LT3 63 Trip

S R

Manual Reset

Q

89b (Line Switch Open)

0.5 0.5 Debounce Timer

Fig. 16: Internal Lockout Logic.

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Protective Relay Vol. 2 The “latch” functions (LT1, LT2, and LT3) are all retained in nonvolatile memory. That is, even if the relay loses control power, it retains the status of the latch functions. In this case, an actual internal transformer fault occurred. The transformer protection (87T) and internal lockout function (86LO) operated to clear the fault. Dispatchers were able to switch load to an alternate source. All operations were correct up to this point. The timeline in Fig. 17 shows the sequence.

DC Off

External Trip

S R

Q

LT2 87T Trip

S R

86 (Lockout)

Q

LT3 63 Trip

S R

86 Lockout Reset Pushbutton

Dispatchers Close Breaker T Initial Fault and Trip

Relay Enabled

LT1

Q

DC On

87T Trip

89b (Line Switch Open)

LT2 (Latch) 89b Asserted (When Line Switch Open) 86LO

0

0 0

Debounce Timer

12 Dropout Delay

Fig. 18: Modified Lockout Function Logic.

DC Supply Relay Enabled 86 Lockout Reset Pushbutton

Fig. 17: Event Timeline Shows 86LO Trips for DC Off and On. When the maintenance crew arrived at the station, the correct procedure was to reset the lockout using a pushbutton on the relay. Instead, as stated earlier, the dc supply was switched off and on. The 86LO function asserted incorrectly when dc was switched off and asserted incorrectly again when dc was switched on. On power down, the relay stayed enabled for several cycles after the point at which logical inputs deasserted. Thus, the 89b input was sensed as deasserted (line switch closed) before the relay was disabled, producing the 86 lockout. On power up, the relay enabled before the 89b input was sensed, thus producing the 86 lockout again. The first and most obvious lesson learned in this case study is that, as technology changes, engineers and operators must strictly adhere to updated operating procedures for resetting lockout functions. Well-understood interfaces, such as physical lockout relays, are being mimicked or replaced, and it is important to document and train field personnel. Another lesson learned is to test the impact of cycling dc power off and on. Protection systems should be robust, relays and I/O modules might reboot, and operators may cycle power to relays when looking for dc grounds or performing other troubleshooting. In this case, designers did not consider how a loss of dc supply or relay power cycle would affect the programmable logic processing order during a power-down or power-up sequence. The user has since added logic so that the lockout function is supervised by a healthy relay (Relay Enabled). In addition, the line switch status is now supervised by a dropout delay that is longer than the relay power-down enable time (see Fig. 18).

Case Study 3: Direct Transfer Trip Due to a Noisy Channel Fig. 19 shows the protection one-line diagram for a 138 kV system with two-ended transmission. The line is protected by distance and directional elements in a permissive overreaching transfer trip (POTT) scheme, along with a direct transfer trip (DTT) scheme if either end trips. T M2

M1

POTT and DTT A

21/67

Relay-to-Relay Digital Communications Link Multiplexer

Multiplexer

21/67

Network

Fig. 19: One-Line Diagram of a 138 kV Transmission Line. In this case, the communications channel is a multiplexed digital network. The channel was abnormally noisy, with about 10 channel dropouts per minute and an overall channel unavailability around 0.5 percent. One of the noise bursts and associated channel dropouts resulted in a momentary assertion of the DTT input (see Fig. 20). Note that the protection system also experienced an unrelated breaker failure. Significant efforts are made to secure protective relays that use channels; these efforts include data integrity checks, debounce delays, disturbance detectors, watchdog counters, and more. In this case, even with a 50 percent bit error rate, the probability of a bad message getting through the relay data integrity checks was one in

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Protective Relay Vol. 2

49 million 11. Although the probability was low, it was not zero, and if enough bad messages were sent, it was still possible for one to get through the integrity check, as in this case. In this example, we see how monitoring a noisy channel may provide a leading indicator for detecting problems. Also, regardless of media and integrity checks, it is prudent to add security on schemes that use direct transfer tripping. In this case, requiring two consecutive messages (an 8‑millisecond delay) instead of one (a 4-millisecond delay) improved security by an additional 104 factor.

Important lessons were learned in this case study. Channel performance must be monitored, and alarms, reports, and other notifications of noise and channel dropouts must be acted on with urgency. In modern 87L relays, regardless of data integrity checks, disturbance detection should be applied to supervise tripping. If disturbance detection had been enabled in this case, the 87L element would have been secure and the undesired operation would have been avoided.

Case Study 5: Relay Trips During Power Cycle While Performing Commissioning An older microprocessor-based relay was being commissioned. During testing, the dc control power was cycled and the relay tripped by directional ground overcurrent. The problem was repeatable.

Communications Drop Out

DTT BFI

Fig. 20: Channel Noise Results in a Momentary DTT Assertion.

Case Study 4: Communications Channel Problem on 87L Another two-terminal transmission line was protected by an 87L scheme. In the event data shown in Fig. 21, the system experienced a degradation of one of the optical fiber transmitters used in the 87L scheme. This failing component injected continuous noise into the channel and its connected equipment.

The relay power supply produces two low-voltage rails from its nominal input voltage for use by various hardware components. A 5 V rail, in this case, was used by the analog-to-digital (A2D) converter, and a 3.3 V rail was used by the microcontroller (µP) and digital signal processor (DSP). Protective circuits reset components when their respective supply voltages drop below acceptable operating limits. Recall from a previous case study that, due to ride-through capacitance, the power supply stays active for several cycles after input power is removed. Fig. 22 provides a graphical representation of how the power supply rails decay at a certain ramp rate, rather than an instantaneous step change, after power is turned off at time T1. Supply Voltage Nominal

5.0 V 3.3 V

T1

�t

Time

Fig. 22: DC Supply Voltage Ramp Down to 0 V After a Power Cycle at Time T1.

Fig. 21: 87L Produced Undesired Trip Due to Communications Failure With Disturbance Detection Not Enabled. In Fig. 21, we can observe the channel status (ROKX) chattering—it should be solidly asserted. Eventually, bad data, in this case erroneous remote terminal current (IBX), made it through data integrity checks and caused an undesired 87L operation. Disturbance detection was not enabled.

The root cause for this case study was a hardware design that allowed the µP and the DSP to remain enabled for several milliseconds after A2D disabled. As A2D disabled, it sent erroneous data to the µP and the DSP, which appeared as a false 3I0 current pulse, which caused the trip. Fortunately, this design issue was found during commissioning tests instead of much later when pulling relay dc power (with trips enabled) to find a dc ground.

47

Protective Relay Vol. 2 Important lessons were learned in this case study. Cycling control power, while replicating as accurately as possible in service conditions, is invaluable and as important as industry standard environmental tests. In this case, the criticality of the power-down sequence of components common to one piece of hardware was revealed.

tions link statuses. Logic should be forced to a secure state during communications interruptions. Status dropout delays should be included as a necessity for security margin. DTT signals should be supervised with debounce delays. Received analog values should be supervised with disturbance detectors.

Consider that the North American Northeast Blackout of 2003 was aggravated by a lack of up‑to-date information from the supervisory control and data acquisition (SCADA) system. A remote terminal unit (RTU) was disabled after both redundant power supplies failed due to not meeting industry dielectric strength specifications. Independent testing (simple high-potential isolation testing) had not detected this product weakness. Self-test monitoring did not alert the operators that the RTU was dead. Fail-safe design practices, such as reporting full-scale or zero values for all data fields during loss of communications or for watchdog timer failures, were not in place. Redundant power supplies, installed to improve the availability of the system, did not overcome these larger handicaps 2 12. These problems are not “hidden failures” just because we do not test or check for them.

Include the ability to isolate trip circuits and devices, whether by physical test links or virtual links for communicated signals. Especially when implementing new technology platforms, strive to make the operator interface familiar and ensure that operating procedures are clear, documented, and proven.

As the industry moves toward more complicated and interdependent Ethernet IEC 61850-9-2 systems, power cycling tests become even more critical. Such systems may employ a data acquisition and merging unit built by one manufacturer, a subscribing protective relay built by a second manufacturer, and an Ethernet network built by a third manufacturer. What if the data acquisition shuts down at 5 V and outputs erroneous data to the rest of the components that remain active for a few cycles more?

CONCLUSION Protection systems and the power industry have much in common with the aviation industry. Both are complex systems of coupled and interdependent subsystems that must work together successfully so that the overall system works. We must continue to understand root cause and that changes in one subsystem have an effect throughout other subsystems. DC control circuits and communications channels have always had complexity and problems to overcome. Our work instructions and procedures have always had to be carefully considered. However, as we transition to new technology platforms and design standards, special precautions must be taken to avoid the types of pitfalls discussed in this paper. When disrupting dc control circuits or communications channels, we must thoughtfully consider what parts of the protection system should be isolated from trip circuits. Isolate trip circuits before indiscriminately cycling power in relay panels when, for example, troubleshooting dc grounds. Analysis, design, and testing should be devoted to understanding what happens when power is cycled on systems and subsystems, especially considering our increased dependence on interdevice communications and programmable logic. Critical communicated logic inputs should be supervised with device and communica-

Test, test, test; avoid undesired operations by including power cycle and logic processing sequence checks in design and commissioning tests.

REFERENCES 1

K. Zimmerman and D. Costello, “A Practical Approach to Line Current Differential Testing,” proceedings of the 66th Annual Conference for Protective Relay Engineers, College Station, TX, April 2013. 2

E. O. Schweitzer, III, D. Whitehead, H. J. Altuve Ferrer, D. A. Tziouvaras, D. A. Costello, and D. Sánchez Escobedo, “Line Protection: Redundancy, Reliability, and Affordability,” proceedings of the 37th Annual Western Protective Relay Conference, Spokane, WA, October 2010. 3

North American Electric Reliability Corporation, State of Reliability 2014, May 2014. Available: http://www.nerc.com/pa/ rapa/pa/performance analysis dl/2014_sor_final.pdf.

4

D. Costello (ed.), “Reinventing the Relationship Between Operators and Regulators,” proceedings of the 41st Annual Western Protective Relay Conference, Spokane, WA, October 2014.

5

B. McMillan, J. Merlo, and R. Bauer, “Cause Analysis: Methods and Tools,” North American Electric Reliability Corporation, January 2014.

6

T. Lee and E. O. Schweitzer, III, “Measuring and Improving the Switching Capacity of Metallic Contacts,” proceedings of the 53rd Annual Conference for Protective Relay Engineers, College Station, TX, April 2000. 7

GE Multilin, HAA Auxiliary or Annunciator Instruction Leaflet. Available: https://www.GEindustrial.com/Multilin.

8

D. Costello, “Using SELogic® Control Equations to Replace a Sudden Pressure Auxiliary Relay,” SEL Application Guide (AG97-06), 1997. Available: https://www.selinc.com.

9

D. Costello, “Lessons Learned by Analyzing Event Reports From Relays,” proceedings of the 49th Annual Conference for Protective Relay Engineers, College Station, TX, April 1996.

10

North American Electric Reliability Corporation, “Transmission System Phase Backup Protection,” Reliability Guideline, June 2011. Available: http://www.nerc.com.

48 11

"Teleprotection Equipment of Power Systems – Performance and Testing – Part 1: Command Systems," IEC 60834-1, 1999.

12

IEEE Power System Relaying Committee, Working Group I 19, “Redundancy Considerations for Protective Relaying Systems,” 2010. Available: http://www.pes-psrc.org. Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying. David Costello graduated from Texas A&M University in 1991 with a B.S. in Electrical Engineering. He worked as a system protection engineer at Central Power and Light and Central and Southwest Services in Texas and Oklahoma and served on the System Protection Task Force for ERCOT. In 1996, David joined Schweitzer Engineering Laboratories, Inc. as a field application engineer and later served as a regional service manager and senior application engineer. He presently holds the title of technical support director and works in Fair Oaks Ranch, Texas. David has authored more than 30 technical papers and 25 application guides and was honored to receive the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference. He is a senior member of IEEE, a registered professional engineer in Texas, and a member of the planning committees for the Conference for Protective Relay Engineers at Texas A&M University, the Modern Solutions Power Systems Conference, and the I-44 Relay Conference.

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ENERGY-BASED TRIPPING AND ITS EFFECTS ON SELECTIVE COORDINATION NETA World, Fall 2013 Issue John Carlin, Schneider Electric Engineering Services

INTRODUCTION

COMPARISON OF TIME-CURRENT CURVES

Changes to the 2005 and 2008 National Electric Code (NEC) forced more careful examination of overcurrent protective device (OCPD) selective coordination, particularly at high-fault current levels approaching system maximum bolted three-phase values. This paper examines selective coordination methods for circuit breakers, beyond the traditional plotting of time-current curves (TCCs) alone, for high-fault currents. Specifically, an energy-based circuit breaker tripping system, which can provide improved selectivity, series rated combinations, and favorable arcflash performance, is presented and examined.

Time-current curves for OCPDs show how long it will take the device to operate under overcurrent conditions. These curves are typically developed by conducting interruption tests on sample devices at various overcurrent levels – overload and fault currents. The device curves account for manufacturing tolerances and are plotted under specific conditions – standalone operation and at a given ambient temperature. Typical circuit breaker time-current curves can be divided into two distinct protection zones – overload and fault current as shown in Figure 1. (This protection zone concept is not common in North America; however, it helps to clarify the remaining discussion.) Circuit breakers respond to overcurrents differently in the two protection zones. In the overload protection zone, the circuit breaker has an inverse-time operating characteristic, indicating the circuit breaker trip time decreases as the overload current increases. In the fault protection zone, the circuit breaker operates with no intentional delay in the case of thermal-magnetic trip circuit breakers or with well-defined short-time segment delays in the case of electronic circuit breaker trip units as shown Figure 2.

BACKGROUND AND HISTORY The 2011 NEC includes six references to selective coordination, which have driven more rigorous examination of OCPD performance and interaction – Articles 100, 517, 620, 700, 701, and 708 all mention “coordination” or “selective coordination.” The general definition in Article 100 defines selective coordination as, “Localization of an overcurrent condition to restrict outages to the circuit or equipment affected, accomplished by the choice of overcurrent protective devices and their ratings or settings”. Articles 700, 701, and 708 further emphasize the requirements for selective coordination for particular systems when fed by an alternative source or sources. Article 517, for Health Care Facilities, extends the requirements of Article 700 to apply to the Health Care Facility essential electrical systems (life safety, critical care, and equipment branches). Article 620 requires selective coordination for elevators, dumbwaiters, escalators, moving walks, wheelchair lifts, and stairway chair lifts “where more than one driving machine disconnecting means is supplied by a single feeder.” While the rationale for selective coordination is self-evident – clearing and isolating faults as quickly as possible without disturbing the unaffected portions of the system – the methods for determining OCPD to OCPD selectivity are not as apparent. Industry standards which define device-to device selectivity for their full operating ranges do not exist and no consensus has been developed among protection engineers or inspecting authorities for device-to-device selectivity thresholds. Discussions continue over the “practicable” selectivity criteria – years of engineers overlaying time-current characteristics of OCPDs to determine selectivity complicated by examining the current-limiting interactions of OCPDs at maximum available fault currents – it is against this background that various alternative selective coordination criteria have been introduced.

Fig 1: Circuit Breaker Time-Current Curve Operating Zones Comparing time-current characteristics of two or more OCPDs on a single graph is the traditional method for determining selective coordination. The relative position of individual device toler-

50 ance bands on a TCC can illustrate the degree of coordination and it is common for the instantaneous trip characteristics to overlap one another. Visually an engineer may conclude that these circuit breakers do not selectively coordinate up to the maximum available fault current when in fact they do, given more precise examination of circuit breaker operation. While TCCs are required to verify the coordination of circuit breaker tolerance bands in the overload protection zone, new examination methods will be presented to verify total selectivity in the fault protection zone even though on a TCC they do not appear to selectively coordinate.

TOTAL SELECTIVE COORDINATION

Protective Relay Vol. 2 range of the OCPDs up to the maximum fault current. While TCCs are excellent analytical tools for determining selectivity among devices in the long-time and short-time regions of the circuit breaker operating characteristics, additional methods are required to determine total selectivity. Selective coordination may be required in a variety of systems which are discussed in NEC Articles 517, 620, 700, 701, & 708. Various adoptions, clarifications, and enforcement practices exist in the US; as such, interpretation of the NEC is out of the scope of this paper. Only circuits that have already been determined to require total selective coordination shall be discussed.

Total selective coordination can be defined by modifying 2011 NEC Article 100 language to include the entire operating ranges of the OCPDs up to the maximum available fault currents. In the system shown in Figure 3, only the loads affected by fault (If) shall be taken out of service by CB4, the circuit breaker directly upstream of the fault. All other line-side circuit breakers shall remain closed. This prevents the interruption of power to all equipment where no fault occurred.

Fig 3: CB4 Operate to Clear Fault without Disturbing the Rest of the System Up to the Maximum Available Fault Current (Total Selectivity)

CONSIDERATIONS OUTSIDE OF SCOPE OF PAPER

Fig 2: Short-Time Delays for Solid-State Trip Circuit Breakers Common definitions of selective coordination have been interpreted as either 0.1 seconds, involving comparing time-current curves, or total selectivity, which includes time-current curves but also requires comparing OCPD behaviors and interaction for fault currents or short-circuit currents. There are variations on how total selectivity is described [e.g., 0.01 seconds], but the intent is selectivity for the entire operating

Ground Faults Certain instances of the NEC, Article 517.17(B) for example, require multiple levels of ground fault protection in health care facility installations. While coordination among ground fault devices is desirable, only the overload and fault protection zones of phase overcurrent devices is considered to be in the scope of this paper. Fault conditions other than overloads and short-circuits were not considered. Arcing faults Arc-flash analysis and mitigation are not considered in this paper. If the duration of an arc-flash event is limited, then the amount of incident energy produced by the event will also be reduced. Protective devices should be set as low as possible to limit incident energy to a minimum level while still providing selective coordination. While circuit breaker settings can be intentionally set to mitigate incident energy levels, which results in a system that is not coordinated, selective coordination for the system was determined to be of paramount importance for the purposes of this paper, given that the NEC does not allow for any circumstances to sacrifice coordination. The energy-based method described can provide high levels of selectivity while lowering incident energy levels.

Protective Relay Vol. 2 NEW EXAMINATION METHODS FOR DETERMINING SELECTIVITY CONSIDERATION OF LOAD-SIDE OCPD LET-THROUGH AND DYNAMIC IMPEDANCE In order to understand the new examination methods, a mastery of interpreting TCCs is first required. Once TCC fundamentals have been mastered, further exploration of the TCC will reveal limitations in determining selective coordination. A more precise examination of circuit breaker operation is required to properly apply the new selective coordination examination methods.

REVIEW OF TIME-CURRENT CURVES AND METHODOLOGY FOR PLOTTING TCCs show how a circuit breaker will respond to I2t in the overload region and to peak current in the fault current regions, on a log-log graph. Ideally an OCPD could be set precisely to trip at an exact value; however, due to various limitations for OCPD’s, tolerance bands must be plotted instead of lines to show the values at which a device could possibly trip. These values are conservative and can have a broad range of trip times for various current levels for different types of circuit breakers. Historically, electronic trip circuit breakers have been shown to have smaller tolerances than thermal-magnetic trip circuit breakers as shown in Figure 4; CB1 and CB2 are electronic trip circuit breakers while CB3 and CB4 are thermal-magnetic circuit breakers.

51 and in the fault current zone. The curves plotted by the software do not account for the current-limiting capabilities that may be available in some circuit breaker trip units. An engineer could conclude that two circuit breakers do not coordinate in the fault current zone, albeit based on limited information contained in time-current curves, when in fact they do. The current-limiting effects of circuit breakers can play a large role in the response of other OCPDs to fault currents throughout an electrical system. For the purposes of this discussion, only the current-limiting effects of two circuit breakers and their interaction with each other will be considered. Referring again to the system in Figure 3, we will only consider CB3 and CB4. When the downstream circuit breaker, CB4, operates an arc will form which introduces an element of impedance to the system that did not previously exist. The amount of this impedance is based on environmental, mechanical and electrical conditions, and can vary for different circuit breakers. This is referred to as dynamic impedance. Dynamic impedance can greatly reduce the amount of fault current detected by the upstream circuit breaker, CB3. The time is also increased to trip for the amount of current that is let-through by the downstream circuit breaker. The current detected by CB3, for a fault on the load-side of CB4, is referred to as let-through current. This current-limiting behavior is advantageous when determining total selective coordination; it is a more accurate description of circuit breaker interactions operating on fault level currents in their instantaneous trip region. It is important to differentiate and not confuse this dynamic impedance current-limitation from UL-defined current-limitation, which is limiting I2t let-through to less than ½-cycle wave of the maximum prospective fault current. Overload trip times can range from seconds to hours but typical device TCC characteristics are cut off at 1000 seconds. TCCs provide a visual indication that coordination has been achieved for three-phase faults and though these circuit breakers are subject to the same dynamic impedance discussed earlier, for practical purposes the devices are said to coordinate if it can be visually verified on a TCC. Because time differences in the overload zone are seconds, not cycles, establishing overload zone coordination with TCCs is not nearly as difficult.

Fig 4: Solid-State (CB1 & CB2) and Thermal-Magnetic (CB3 & CB4) Trip Characteristics The device curves shown on TCCs, produced by power system analysis software, are taken from manufacturer published curves developed from lab tests that show the tolerance bands of trip values when exposed to three-phase bus faults in the overload zone

Some circuit breakers can be equipped with trip units that have an intentional time delay, when a fault is detected, to allow the downstream circuit breaker to interrupt a fault. When these shorttime functions are used, it can be easily observed from a TCC that coordination has been achieved when there is no overlap in the device bands for the short-time region of the devices. Compare CB1 and CB2 in Figure 2. The instantaneous regions of the device bands tend to show an overlap on a TCC for many circuit breakers because the curves have been based on the standalone characteristics for maximum three-phase bus fault values. If dynamic impedance is considered for this region, then the fault current observed at the upstream cir-

52 cuit breaker may not be high enough to cause a trip before the downstream circuit breaker reaches its maximum trip time for the manufacturer’s tolerances for instantaneous faults. Different combinations of circuit breakers can be evaluated to show coordination at or below certain fault values even though the TCC device bands overlap each other in the instantaneous region.

PEAK CURRENT LET-THROUGH CONSIDERATIONS TCC curves cannot accurately account for dynamic system impedance, so another method will need to be used to determine if two circuit breakers coordinate. As long as the let-through current of the downstream circuit breaker is less than the minimum value at which the upstream circuit breaker may trip the two circuit breakers selectively coordinate. Two methods of calculating the level of selective coordination between a pair of circuit breakers are discussed further. These methods are: (1) the peak current point method and (2) the peak let-through curve method. Some assumptions must be made in order to use these methods. If the upstream circuit breaker has an adjustable instantaneous setting, it is assumed that it is set at its highest value. If an electronic trip circuit breaker is used, then it is assumed the long and short time functions being used are set to coordinate throughout the long and short time region of both devices. Given some circuit breakers are equipped with an instantaneous override, which must also be taken into account. Lastly, the load-side circuit breaker current let-through values, for circuit breakers not UL-defined as current-limiting, are not typically published; instead circuit breaker manufacturers instead publish tables listing line- and load-side circuit breaker combinations, and the maximum fault current level to which those combinations are selective.

Protective Relay Vol. 2 If the peak let-through current of the downstream circuit breaker is less than the peak minimum instantaneous trip level of the upstream circuit breaker, then the selective coordination level is the lesser of the upstream and downstream circuit breaker interrupting ratings (in RMS). If the peak let-through current of the downstream circuit breaker is greater than the peak minimum instantaneous trip level of the upstream circuit breaker, then the selective coordination level is the minimum instantaneous trip level of the upstream circuit breaker (in RMS). This method uses data readily available to circuit breaker manufacturers (and, for UL-classified current-limiting circuit breakers, the data is published), but it yields conservatively low selectivity results.

PEAK LET-THROUGH CURVE METHOD The other peak current comparison method is the peak letthrough curve method, which also involves converting the minimum instantaneous trip level of the upstream circuit breaker from RMS to peak current, as described in the peak current point method. The value can be plotted as a horizontal line on the same graph as the peak let-through curve of the downstream circuit breaker which can be obtained from data test points. The intersection point of these two lines indicates the level of selective coordination.

PEAK CURRENT POINT METHOD The peak current point method calculations are based on peak currents so the minimum instantaneous trip level of the upstream circuit breaker must be calculated for peak fault conditions. Many instantaneous trip settings are based on RMS values; therefore, the continuous rating must be increased by a factor of 1.4142. For example, a thermal-magnetic circuit breaker rated at 250A may have a maximum setting of 10 times the continuous current rating of the circuit breaker. UL 489 requires a minimum tolerance for this circuit breaker of 80%. The peak minimum instantaneous trip for this circuit breaker would be: 250A x 10 x 0.8 x 1.4142 = 2,828A Other considerations and adjustments must be taken into account for more complex circuit breaker functions and testing conditions such as power factor and X/R ratio. This information can be obtained from UL 489 interrupting tests.

Fig 5: Peak Let-Through Current Curve Selectivity for a LineSide Circuit Breaker with a 20 kA Instantaneous Override As shown on the peak let-through curve of the particular circuit breaker in Figure 5 the actual selective coordination level is much higher than it would have been assumed to be when a non-current-limiting circuit breaker would have been used. The dynamic impedance introduced by the current-limiting circuit breaker forces the fault current to be greater than 40kA to allow the let-through current to reach the minimum instantaneous trip of the upstream circuit breaker at 20kA.

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Protective Relay Vol. 2 ENERGY-BASED TRIP SYSTEM An energy-based tripping system, while it relies on load-side circuit breaker current limitation, is able to discriminate between load-side faults and loadside let-throughs of other circuit breakers. This method employs two trip systems working in conjunction – a conventional circuit breaker trip and a specially designed primary trip system. The primary trip system will not trip during the first half-cycle of a fault regardless of the fault current level. This delay is accomplished by using various methods. One method uses a weight and spring system to block the electro-magnetic forces that would otherwise be used to immediately trip the circuit breaker. Another uses an electronic unit to determine the duration of the fault and then trips accordingly if the fault has existed too long. The delay allows the power contacts to “pop”, or open, due to magnetic repulsion and then reclose. This develops impedance which limits the peak let-through current and energy to line-side OCPDs. In typical trip units, this reclosing action is prevented, because it can erode the circuit breaker power contacts over time. For this reason a supplemental trip system is used to monitor the energy let-through and trip the circuit breaker if necessary. Tripping due to let-through energy is called REFLEX tripping because the circuit breaker is protecting itself by reacting to energy levels that can damage it. Two different methods can be used to measure I2t values. One method uses a pressure trip system that is connected to the arc chamber through exhaust valves shown in Figure 6. When the contacts pop, the arc created generates heat as the current passes through the air. The heat erodes the ablative material inside the arc chamber in a controlled manner, which releases gases and creates pressure. The pressure trip system detects an increase in pressure and can be calibrated to trip at certain pressure levels, which can be correlated to I2t. Another method to measure the energy letthrough is by electronic means, by which the sensor continually monitors the level of energy let-through during a fault. If a certain level of energy is exceeded, the trip unit is activated to prevent the contacts from reclosing.

Fig 6: Mechanical Pressure Trip System

Fig 7: Energy-Based Selective Coordination Diagram Figure 7 shows how energy-based selectivity works. A fault on a branch circuit (A) will eventually rise to a level that will pop the contacts of the branch and main circuit breaker. Due to the relative sizes and designs of the circuit breakers, the branch circuit breaker contacts will separate more than those of the main. The greater the distance the arc must travel, the more impedance it introduces into the system, which in turn also generates more heat. When enough heat and pressure is built up, the supplemental trip system in the branch circuit breaker is activated. For electronic versions of these trip units, the total energy reaches a certain level and the trip system is activated. Once the trip system is activated the branch circuit breaker contact is open and prevented from reclosing, clearing the fault. The main circuit breaker did not reach a sufficient level of energy to trip and remains closed; however, the contact separation in the main provides additional impedance that reduces stresses in other parts of the electrical system and allows an upstream circuit breaker to assist in clearing a fault downstream and remain closed, providing continuous service to other branch circuits. Because both circuit breakers are working together to clear the fault a series rating can also be achieved for circuit breakers with a supplemental trip unit. The energy that these circuit breakers will let-through during interruption is typically more consistent than standard circuit breakers, because the actual trip is activated by a more consistent and measureable quantity – the loadside energy, rather than a peak current. Since the energy let-through is more predictable, coordinating these circuit breakers with others that trip based on the same principle is easier. The energy-based tripping circuit breakers can also selectively coordinate to higher fault current levels with load-side standard circuit breakers, due to the current-limiting capabilities of standard circuit breakers discussed earlier. The energy-based method with its load-side energy consistency, allows the line-side circuit breaker to effectively distinguish between load-side faults and let-throughs of load-side breakers operating on faults further downstream. The intentional delay

54 that allows the reflex tripping to see loadside energy does not reduce overall clearing time, resulting in higher levels of selective coordination without necessarily unleashing higher levels of fault energy, including arc flash incident energy. As a rule of thumb, line-side breakers should be selected that are 2 times the current rating of the downstream device to achieve coordination. If fault coordination can be verified using one of the methods discussed in this paper and overload coordination can be visually confirmed by a TCC, then the devices will achieve total selectivity. This simple rule and the use of the supplemental trip units discussed not only greatly simplifies coordination studies and system design, but also reduces the stress and possible damage experienced during a fault in the system. These benefits can be cascaded over several levels of a power system to provide even greater protection and coordination.

SUMMARY To achieve total selective coordination, as required by some authorities having jurisdiction enforcing the specific NEC articles, additional criteria beyond traditional circuit breaker time-current curves must be applied. This paper discussed methods used to accomplish total selectivity at high-fault current levels - methods that recognize circuit breaker current-limiting capabilities, even for circuit breakers not defined as current-limiting by UL. Most importantly, an energy-based tripping method was described, which provides consistency by using load-side energy and achieves high levels of fault selectivity. In addition, energy-based tripping is easy to apply (the results are compiled in look-up tables and on-line tools) and does not introduce additional fault clearing times or increase system arc flash incident energy levels.

REFERENCES Short-Circuit Selective Coordination by Gavin Button and Mike Tobin, Schneider Electric internal, September 24, 2008 A New Approach to Low-Voltage Circuit Breaker Short-Circuit Selective Coordination by Ed Larsen, IEEE ICPS08XP21 Energy-based discrimination for LV protective devices by Marc Serpinet and Robert Morel, Schneider Electric Cahier Technique ECT167

John Carlin, PE, is an Engineering Supervisor with Schneider Electric Engineering Services Central Studies group in Lexington, Kentucky. He received a BS degree in electrical engineering from University of Arkansas in 1987. John’s experience includes 19 years with the Central Studies group performing medium- and low-voltage power system studies for commercial, industrial, and institutional projects, both new construction and existing facilities. Analysis types performed include fault, coordination, arc flash, load flow, harmonics and dynamic motor starting. Facilities

Protective Relay Vol. 2 analyzed include automotive manufacturing, automotive testing, oil refineries, utility power stations, military weapon destruction plant, water/wastewater treatment plants, and other commercial and institutional projects. Reprinted with permission of Square D by Schneider Electric; copyright 2013. All rights reserved.

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MICROPROCESSOR-BASED RELAYS: OUT WITH THE OLD, IN WITH THE NEW NETA World, Spring 2014 Issue Dennis Moon, AVO Training Institute The question is often asked by both technicians and engineers, “Why are we replacing perfectly good electromechanical protective relays with microprocessor-based devices?” The answer is both multifaceted and interesting. It can be easily shown that electromechanical relays operate as fast as, and in some cases faster than, microprocessor-based relays. Electromechanical relays can detect complex system abnormalities and take sophisticated actions. Electromechanical relays have been in service at every level of power generation and delivery for many years, so why replace them? Here are some of the reasons that electromechanical and electronic relays are going away and why microprocessor-based relays are being specified as replacements and in new builds.

cility and allows scarce money to be spent on other needs. The maintenance needs of microprocessor based relays are also substantially less than their electromechanical counterparts, and the maintenance period can be extended thus reducing the man hours needed to test, calibrate, and maintain the relay. The FERC and NERC standard for microprocessor-based relay testing requires only tests of the metering functions, inputs and outputs, and a check of the settings.

First and foremost is the vast amount of data that can be retrieved from microprocessor-based relays that can be used to determine what prefault, fault, and postfault conditions exist at a specific relay and how those conditions affect larger system operating parameters. As system reliability becomes more and more important (think Smart Grid), more and more data is necessary to ensure constant and reliable power delivery. We can now retrieve fault data not only in numeric form, but also in sinusoidal and phasor formats. In most cases, the relay is capable of determining where system faults occurred and how far from the relay the fault was located. Highly accurate timing data can be measured because the relay can be connected to a system time clock that provides synchronization to other system devices. In this way, breaker operations, breaker reclosing, communications signals, and other timing information is correct and in proper sequence. Other information that can be gleaned from microprocessor-based relays is real time quantities such as complete system voltage, amperage, frequency, associated angles, watts, vars, power, and breaker status. This data can be sent to dispatch centers in real time to be used for load calculations, power flow, and other desired uses. Multiple events can be stored, recalled, and even replayed on modern test equipment. Relay data is now the king of system protection.

As grid stability becomes more and more important, the versatility of microprocessor-based relays becomes increasingly more vital. The availability of multiple settings groups, the precise and accurate measurement of system quantities, and the ability of the relay to communicate data between stations and control centers makes the microprocessor-based relay the best option for system protection and control.

Next is the economic impact of microprocessor-based relays. For the cost of a single mechanical impedance relay, a microprocessor-based relay can be specified which will replace a complete panel of line protection at one fifth the cost or less. Five microprocessor-based relays mounted in a single nineteen-inch rack mount panel replace as many as ten full panels in a typical substation. This significantly reduces the per foot cost of a fa-

Microprocessor relays can play a vital role in arc-flash hazard mitigation as well. These relays may implement a change in device settings via front panel push buttons so that, when technicians are working on a protected bus, arc-flash incident energy can be reduced.

In summary, microprocessor-based relays are the absolute present and future of system protection and reliability. Accurate and plentiful data, significant cost savings, arc-flash protection, and versatility are just a few of the reasons that combine to make these relays the choice of protection for engineers and technicians. We will see more and more of these relays as older relays become obsolete and are retired. Equipment specifications will nearly always be designed for microprocessor-based devices so new installation will be almost one hundred percent digital. Dennis Moon has over 32 years experience in the Electrical Industry. His varied areas of expertise includes positions such as Electronic Instrument Repair Technician, Maintenance Electrician, Senior Relay Technician and Senior Training Specialist. Additional areas of expertise includes the repair and calibration of oscilloscopes, ammeters, frequency generators, voltmeters, ohmmeters, and flatwave meters; the development and implementation of computerized relay testing programs to fit testing and calibration needs, and development, marketing, and presentation of AVO Training Institute’s specialized courses.

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EVOLUTION OF POWER SYSTEM PROTECTION TESTING NETA World, Fall 2015 Issue Ed Khan, Doble Engineering Company

In any electrical system, protection plays a very important role in ensuring reliability and continuity of power to the end user. Improper operation or non-operation of protective relays or other elements of the protection system can cause havoc in any electrical distribution system. Hence, the relays must be selected, set, and maintained in strict compliance with specific rules and standards. There is no room for slack or error. In years past, it was not uncommon to see cascading failures that started with misoperation of relays within a grid at a specific location and soon engulfed a large portion of the electrical system. Widespread blackouts were the result. Figure 1 below shows the impact of various blackouts in terms of affected customers.

Fig. 2: Progression of Relay Technology Over Time Hand-in-hand with the progression of relay technology is a similar progression of relay test sets. Refer to Figure 3.

Fig. 3: Progression of Relay Test Sets Over Time

Fig. 1: Impact of Blackouts in Terms of Affected Customers Although, not all blackouts can be attributed to misoperation of the protection system, the latter does contribute its share toward cascading events. Maintenance of protective relays has evolved from what used to be a simple task to what is often a relatively complex procedure. Relay maintenance has kept pace with technological advancements, new automation standards, and to some extent, government regulations in the United States and Europe. The first electromechanical induction disk relay was introduced around 1910. That was followed by the introduction of solid-state (static) relays around 1955. Early digital relays were introduced in 1982, and since that time have continued to advance tremendously in features and capabilities.

Assuring correct operation of protective relays is often difficult because under normal operating conditions, the protection provides little or no indication of its operational status. Relays that are not operational or set incorrectly may not prevent a system from operating. For example, if all settings on the relays are set too high, the system will operate correctly until a fault occurs, effectively defeating the protection. Furthermore, protective systems can be very complex and require careful attention to achieve meaningful testing. Protective relay and system testing can be divided into three main types, with a fourth added in some cases: 1. 2. 3. 4.

Factory Tests Commissioning Tests Pre-Commissioning (in some instances) Periodic Maintenance Tests

Each of these can utilize different tools, procedures, and methods of testing.

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Protective Relay Vol. 2 FACTORY TESTS Factory tests are divided into two parts. The first part consists of tests in which the operating parameters of the relay are simulated. A good setup to perform these types of tests uses real-time simulations.

Fig. 4: Test Setup Using Real-Time Digital Simulators Figure 4 shows the test setup using real-time simulators. These simulators provide accurate simulation of power system conditions and enable relay testing under a wide range of system conditions. The real-time simulators simulate real systems in digital form, with actual voltage and current output in the form of analog signals. Because these simulators provide a low signal level, amplifiers are needed to bring the signals to levels suitable for relays. Relay response is fed back to the simulator; the simulator accounts for this status change and modifies the calculation. This process continues in a loop, and hence, is called a closed-loop process. Real-time simulators are used extensively at large relay manufacturing facilities to perform real-time transient testing and simulation for their products. Manufacturers also use conventional test sets when required as part of overall factory testing. The second part of the factory tests addresses a devices capability to withstand vibration, stress due to temperature, electromagnetic compatibility, and impact. Many of these relay factory tests are also termed type testing since they are performed on one relay which represents a specific product line.

COMMISSIONING TESTS Commissioning tests are performed to achieve the following: ●● Ensure that equipment has not been damaged in transit and is in acceptable condition to be placed in service ●● Confirm that equipment is installed correctly and as per specifications ●● Verify the settings are installed correctly and the relay/protection system operates as intended ●● Document all drawings, references, and settings for future use

Fig. 5: Panel Wiring Testing methods can involve steady-state, dynamic, or transient tests. One item that differentiates commissioning tests from factory and preventative maintenance is the scope of work. Commissioning tests deal with not only the protective relays and associated controls, auxiliary relays, but also with the related primary equipment such as breakers, CTs, and VTs. In commissioning tests, all wiring must be ringed, or traced out, to verify conformity with applicable drawings. Figure 5 shows a typical installation that requires such verification.

PRE-COMMISSIONING TESTS For some large and critical projects such as 500 kV to 1000 kV transmission lines or lines that have series compensation, another level of tests is frequently utilized. These tests are performed using real-time simulations with actual relays wired to a simulator. These tests can include several simulations involving different types of faults at different locations under different system and fault configurations. Pre-commissioning tests makes commissioning tests easier and can save time during that stage. Various bugs related to items such as settings, relay design, and application. can be identified and resolved during pre-commissioning tests.

PERIODIC MAINTENANCE TESTS This type of maintenance is very important and has gained significant attention due to preventable blackouts that have taken out large areas of transmission systems. Protection is a very sensitive component in any power system. On an installed cost basis, a substation’s protection is a small expense compared to the cost

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of other system components, such as transformers, breakers, etc. However, from the impact point of view, the protection can have very significant importance. Statistics show that protective relay misoperations are often attributed to the following: ●● Limitations in the design of protective scheme ●● Faulty relays ●● Defects in the secondary wiring ●● Incorrect connections ●● Incorrect settings ●● Known application shortcomings accepted as improbable ●● Faulty pilot wires due to previous damage of which the maintenance staff was unaware ●● Various other causes of misoperation, such as switching errors, testing errors, and the operation of relays from mechanical shock Periodic maintenance testing is conducted using three methods: 1. Steady-State Testing 2. Dynamic Testing 3. Transient Testing

Fig. 6: Test Set with Front-Panel Controls As technology progressed, newer test sets appeared. These had either a more sophisticated front panel located on the instrument itself, a separate hand-held controller, or operational control via a computer. In a test set controlled by computer, a control panel program normally provides a virtual screen. This screen has all the looks of the controls available on held-held devices or mimics the controls available on the instrument itself. Figure 7 shows a test set controlled by a computer program that emulates all the controls.

Steady-state testing is the simplest and was performed by early generation test sets. As newer and more complex relays entered the market, test sets and testing methods progressed into dynamic and transient testing. Even though advanced test sets are readily available, not all utilities perform dynamic and transient testing. The size of the utility, the sophistication of the testing staff, and funds available determine the type of periodic testing selected.

STEADY-STATE TESTING A steady-state test is defined as applying phasors to confirm relay settings and correct operation by varying relay inputs. This testing method often involves a relay being placed on a test bench, then subjected to sinusoidal currents and/or voltages. Depending on the relay type, the operating quantity is ramped up or ramped down until the relay operates. There are several ways in which these quantities are varied. The variable(s) can be one or a combination of the following: voltage, current, frequency, or phase angle depending on the relay or element under test. In the early days, before sophisticated relay test sets were marketed, the steady-state test was conducted with manually operated instruments. The test sets had all controls on the front panel with few limited display screens. For example, the control was done via control knobs, thumbwheels, toggle switches. Figure 6 shows one such test.

Fig. 7: Controlling Test Set via Computer Steady-state testing is not automated. Measured variables such as current are manually ramped up or down; when the contact status changes, an audio or visual indication is provided. Once the contact transitions, the current or voltage injection is usually terminated. Some test sets are provided with an enhanced front panel that is part of the test set or a separate hand-held device employed by various manufacturers. Touch screen options may also be available. During the last 20 years, various manufacturers have enhanced steady-state testing by providing software that performs all the manual steps in a batch-mode form, which makes the test automated. The user has to define several variables, and then the program performs all the required steps without any manual intervention. Figure 8 shows an automated test to determine the pickup of an overcurrent element.

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Protective Relay Vol. 2 The user enters the following values: ●● Expected pickup ●● Tolerance ●● Offset Current ●● Offset Duration ●● Delta current ●● Delta Time ●● Current limit

Basically, the entire testing cycle is divided into three states: pre-fault, fault, and post-fault. All three can be imported into the dynamic program. The test set runs the three fault states, and relay response is recorded. This type of testing is implemented by various manufacturers under different names. The transition from one state to the other can be based on a maximum time allowed to run that state or conditioned upon transition of a contact. For example, in the case of three states, the prefault could be allowed to run for a period of several cycles or seconds. The fault state could be allowed to run until relay contact operation is sensed by the test set. The software receives this information on contact transition and operation and changes to the next state. The final state, post fault, can run for several cycles or be terminated by some specified contact transition. While this dynamic test description is a very simple example, the testing could expand to more states, allowing for simulation of a variety of sequential system events. One example of a type of testing is to simulate the multiple operations of a recloser. Figure 9 shows a three-state test setup.

Fig. 8: Screen Capture of an Automated Test to Determine Relay Pickup The first entry needed is a definition of the expected pickup, and this is directly obtained from the relay setting. A setting of five ampere pickup means the expected pickup is five amperes, and the tolerance can be defined as plus or minus five percent. The tolerance is obtained from the relay instruction manual or from a specific industry standard. The offset setting is needed to start the test at some point close to the expected pickup; in a manual test, the same approach is employed. Current injection is not started at one ampere if the expected pickup is five amperes; a starting point close to the expected pickup is selected. In this case, four amperes is selected as the starting point, and the test set will run at four amperes for some time (offset duration). As in the manual test, the value of current injection is increased by increments. In the automated test, this is defined as delta current; the time at each level of current is the delta time. The last entry is the current limit, which is the point at which the test is terminated if the relay does not pick up. This entire process is automated. The same types of macros or batch mode commands are built for other types of tests. As stated earlier, these tests are steady-state. The relay is not subjected to actual system conditions that could appear during a fault.

DYNAMIC TESTING In dynamic testing, the intent is to come closer to actual system conditions while using sinusoidal quantities at normal system frequency. Typically, a steady-state, short-circuit program output related to a specific fault can be obtained and mated with a dynamic testing program.

Fig. 9: Dynamic Tests Using States

TRANSIENT TESTING Transient testing is the most realistic testing type and can be used for an entire protection system as well as individual microprocessor or electro-mechanical relays. The main advantage of transient testing is that it comes closest to simulating exact system conditions and does not have the inherent limitations of the more commonly used steady-state waveforms. However, transient testing can be expensive since it can be elaborate and requires careful planning and analysis. The first step in conducting a transient relay test is to model the system under study in a transient relay testing software program. Once the system is modeled, various faults are simulated on the line or lines under study. The system could involve two, three, or four terminals. Results of the fault analysis are saved in COMTRADE or PL4 format. The behavior of the relays applied at the terminals of the lines under study is of most interest. Thus, the values of the voltages, currents, and phase angles at the terminals are determined as the system moves from a pre-

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fault state to a fault state and then to a post-fault state. The relevant information is captured in a COMTRADE format file used by the transient program of a relay test set manufacturer. The file can be viewed as a waveform, and Figure 10 shows a waveform as viewed by one such program. The next step is to modify the file in terms of assignment of sources, logic inputs, outputs, etc. After preparing this file, it is saved and downloaded to the test set. The test set starts putting out voltages and currents with correct phase angles in accordance with what is contained in the software. Figure 10 shows the waveform obtained by one relay test set manufacturer’s program. Fig. 11: End-to-End Testing End-to-end testing can be expensive since it involves a significant amount of preparation time; the time to conduct the test can also be considerable. However, this type of test has many advantages, and can be a valuable tool when performing periodic maintenance testing as well as during acceptance and commissioning of equipment and systems. End-to-end testing can verify that: Fig. 10: Transient Testing Using COMTRADE Files This type of transient testing can be used for testing each element of a microprocessor relay or a specific electromechanical relay. However, it is more typically used for conducting end-to-end testing as described in the next section.

●● The protection scheme is working correctly and as designed ●● Communication signals are sent and received correctly ●● Protection operates correctly for faults in all parts of the line ●● The entire scheme is functional at the component level as well as a system

END-TO-END TESTING

SUMMARY

End-to-end testing is a very sophisticated type of protective device testing used as a commissioning test or a routine test to ensure the integrity and design compliance of a communication-assisted protection scheme, also referred to as teleprotection. The test is conducted using dynamic tests that use sinusoidal waveforms with pre-fault, fault, and post-fault states, or using COMTRADE files under the transient test.

In summary, the industry has seen significant changes and advances in testing regimens for protection assets over the last 30 years. Changes were driven by advances in relay technology and new testing requirements such as dynamic and transient testing. Testing and maintenance of protection assets is a very robust and every developing field. There are significant changes to the execution and methodology of relay protection, and these changes are occurring both now and most likely in the not-so-distant future. Some of the changes occurring and those that are expected to occur over a period of time are being driven by the following:

Figure 11 illustrates the setup required to conduct an end-to-end test. As shown, a test set with the appropriate files is downloaded to the relays at each end. The two test sets are synchronized via global positioning satellite inputs. The test sets start at the same time to simulate a specific fault along the line, and the behavior of each relay is recorded; the test either passes or fails depending on the performance of the relays at each end.

●● Government regulations. NERC (North American Electric Reliability Corporation) is mandating testing procedures and maximum maintenance intervals for protection assets. Audits verify that utilities are following the mandate. This is forcing utilities to create centralized databases for all of their protection assets. Testing is no longer a standalone function. Test results and related data must be controlled and consolidated. Hence, testing now involves strict database management in addition to the technical aspects.

Protective Relay Vol. 2 ●● New substation automation standard. One communication/ substation automation standard that is expanding at varying rates in the U.S., Canada, and rest of the world is IEC 61850. Relays complying with this standard have very different testing procedures from those associated with conventional relays. Relays complying with IEC 61850 do not have hardwired contacts, and they accept digitized voltage and current signals instead of conventional analog voltage and current. There are test sets available to test these relays associated with what is called a digital substation. ●● Rapid replacement of electromechanical relays with microprocessor relays. On average, the current U.S. utility has approximately 60% electromechanical relays. This percentage is expected to drop significantly in coming years with corresponding increase in microprocessor relays. Testing microprocessor relays is best done using dynamic and transient testing. This will result in increased use of dynamic and transient testing. Going forward, we are sure to see many more changes and advances that will require testing procedures to be more integrated with the communication aspects of a power system. Also, as part of smart grid initiatives, we are seeing integration of microgrids and distributed power systems tied through communication links. This will lead to a new area of testing - testing components as an entire system, a system in which circuit protection will be an important part. Ed Khan has been with Doble Engineering Company for 10 years working in various capacities including Product Manager for protection test related instruments. Currently, he is the Director of Protection R&D and Training. Prior to Doble, Ed worked for GE, ABB, SEL, KEMA, and others in various capacities. He has 36 years of experience in system studies, protection applications, relay design, power plant design, teaching, and product management. He has a thorough knowledge about product development, protection, harmonic analysis, harmonic filter design, stability studies, real-time digital simulations, generator protection, and more. He has presented courses on behalf of GE and Doble in the U.S., Southeast Asia, the Middle East, Mexico, India, and China, and has taught the GE protection course on a few occasions. Ed is a CIGRE member, is currently a member of CIGRE Working Group B5.56 (Optimization of Protection, Automation and Controls), and has written and presented papers and articles on protection and testing related topics. Ed holds an MS in Electrical Engineering from Texas A&M University.

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MODERN ADVANCES IN TESTING MULTIFUNCTION NUMERICAL TRANSFORMER PROTECTION RELAYS NETA World, Winter 2015 Issue Steve Turner, Beckwith Electric Company, Inc.

This article demonstrates different techniques to test multifunction numerical transformer protection relays, so that these techniques can easily be incorporated into automated test software. The Common Format for Transient Data Exchange (COMTRADE) for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays because it can replay actual operating conditions or simulate a very complex event such as transformer energization when there is remnant flux on the core of a winding. The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using the Electromagnetic Transient Program (EMTP). Lastly, automated testing of the boundary of the phase differential operating characteristic is illustrated to properly test the relay settings.

COMTRADE SIMULATION – 2ND HARMONIC RESTRAINT ON INRUSH COMTRADE records captured by numerical relays and digital fault records from actual system events are of particular interest since these provide the ability to test protection for critical faults or disturbances that are difficult to create using off-the-shelf, test-set software. Utilities consultants and equipment manufacturers can build a library of test cases.

Fig. 1: Auto Transformer High Side Energization This is an excellent case to use the COMTRADE record captured by the relay since you can test transformer differential protection to ensure it does not operate during inrush for many applications —that is, most two-winding transformers and auto banks with five-amp, secondary-rated CTs on the high side. Figure 2 shows very little restraint current and high magnitude differential current in B Phase during the transformer energization. The trip occurred when the ratio of B Phase 2nd harmonic to fundamental current dropped too low.

The first example is the case of transformer differential protection operating during energization due to low 2nd harmonic current content in the inrush current. This event was recorded by the numerical relay protecting a 400 MVA 230/115 kV auto-transformer that was energized from the high side while the low side was open (Figure 1). The auto-transformer is connected to a 230 kV straight bus through a motorized disconnect switch. The CTs are wye-connected on both sides. The 230 kV CTs are on the transformer bushings connected with the full ratio (1200:5). Fig. 2: High Side CT Secondary Fundamental Versus 2nd Harmonic Current

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Protective Relay Vol. 2 The relevant current phasors measured by the relay at the time of the trip along with the 2nd harmonic contents are listed in Figure 3.

Fig. 4: Current 2nd Harmonic Restraint Logic

Fig. 3: Current Phasors Measured at the Relay with 2nd Harmonic Current The numerical transformer differential relay that tripped uses internal zero-sequence current compensation to prevent unwanted operations during external ground faults since the current transformers are wye-connected, and the transformer is an auto bank. Calculating the phase-to-phase current automatically eliminates zero-sequence current as follows: Ia = I1 + I2 + I0 Ib = a2 I1 + a I2 + I0 Ic = a I1 + a2 I2 + I0 Iab = Ia – Ib = I1 (1 – a ) + I2 (1 – a) 2

Ibc = Ib – Ic = I1 (a2 – a) + I2 (a – a2) Ica = Ic – Ia = I1 (a – 1) + I2 (a2 – 1) If the transformer differential relay uses phase-to-phase current to eliminate zero-sequence current, then Ibc is the most depleted of 2nd harmonic content and also corresponds to the phase that actually tripped (B-Phase). Figure 4 illustrates the following signals:

Fig. 5: Current Phasors Measured at the Relay with 2nd and 4th Harmonic Current

TEST REQUIREMENTS You will need a three-phase test set that can playback COMTRADE records. Three current channels are required. Connect the three-phase test set to the relay as shown in Figure 6A.

●● Ibc ●● Fundamental component ●● 2nd harmonic component ●● Ratio of 2nd harmonic to fundamental The ratio decreases in magnitude over the first two cycles following energization. The relay tripped at the point when the ratio dropped to 14%. Note that transformer differential relays are typically set to restrain at 15%. Figure 4 illustrates how the phase differential protection is restrained using 2nd harmonic current.

Fig. 6A: Test Connections

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Figure 6B shows off-the-shelf software available to play back this particular COMTRADE record through the test set to the relay.

1. Isolate the fundamental component and 2nd harmonic component in B-Phase current (IB). 2. Multiply the 2nd harmonic content by a factor to reduce its magnitude to the pickup level selected for the 2nd harmonic restraint. For this particular case, the minimum pickup is 10% 10%. Therefore, the multiplication factor is 0.7 (i.e., 14% ). 3. Re-assemble the B-Phase current by adding the fundamental and 2nd harmonic back together (depleted IB in the case of Figure 8). 4. Inject the adjusted current into the relay.

Fig. 6B: Test Software

TEST PROCEDURE 1. Play back the inrush case to the relay with harmonic restraint disabled. 2. The relay should trip when harmonic restraint is disabled. 3. If the relay trips, then play back the inrush case again with harmonic restraint enabled. 4. The relay should not trip when harmonic restraint is enabled. Figure 7 shows the corresponding flowchart.

Fig. 8: Adjusted Inrush Current

EVEN HARMONIC RESTRAINT DURING TRANSFORMER INRUSH

Fig. 7: Transformer Inrush Test Procedure Flowchart

ADVANCED TEST—ADJUSTING THE LEVEL OF 2ND HARMONIC CONTENT It is possible to reduce the amount of 2nd harmonic content present in the inrush current during the injection test. You can reduce the level of 2nd harmonic current until the restraint no longer blocks the differential protection. For example, 10% is typically the minimum level acceptable to set the 2nd harmonic restraint; if it were set lower, tripping might be significantly delayed for heavy internal faults due to harmonics generated by CT saturation. The software shown in Figure 8 illustrates this process:

Events such as transformer energization can be captured by utilities using digital fault recorders or numerical relays and then later played back via COMTRADE to observe relay performance. Some customers have access to software such as the Alternative Transients Program (ATP) and can build their own transformer models to simulate inrush. This is a practical method to check that the relay is properly set. One example of playback is to evaluate the performance of the restrained differential protection for transformer inrush with varying levels of harmonic content in the current waveforms. Transformer differential protection has historically used the 2nd harmonic content of the differential current to prevent unwanted operation during transformer inrush. It is advantageous to use both the 2nd and 4th harmonic content of the differential current. The relay can internally calculate the total harmonic current per phase as follows: I2-4 =

I 22 + I 42

The sum of the two even harmonics per phase helps to prevent the need to lower the value of restraint, which could cause a delayed operation if an internal fault were to occur during transformer energization.

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Protective Relay Vol. 2 Cross-phase averaging also helps prevent unwanted operation during transformer inrush. Cross-phase averaging averages the even harmonics of all three phases to provide overall restraint. The cross-phase averaged harmonic restraint can be internally calculated by the relay as follows:

FIRST CASE — BALANCED INRUSH Energized Line with Bank from Single End (No residual flux)

The transformer relay with even harmonic restraint and crossphase averaging tested for the following cases did not malfunction. The inrush currents presented here were created using EMTP and have a very slow rate of decay. Figure 9 is a one-line diagram illustrating the 600 MVA auto-transformer.

Fig. 10A: Total Phase Currents for Balanced Inrush

Fig. 9: 600 MVA Auto-Transformer Single-Line Diagram (Delta Winding DAC)

87T RELAY SETTINGS The auto-transformer differential protection settings are as follows:

Fig.10B: 2nd Harmonic Component Currents for Balanced Inrush

Fig. 10C: 4th Harmonic Component Currents for Balanced Inrush

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SECOND CASE — BALANCED INRUSH

THIRD CASE — UNBALANCED INRUSH

Energized Bank from Winding Two with Winding One Open (No residual flux)

Energized Line with Bank from Single End (Severe A-phase residual flux)

Fig. 11A: Total Phase Currents for Balanced Inrush

Fig. 12A: : Total Phase Currents for Unbalanced Inrush

Fig. 11B: 2nd Harmonic Component Currents for Balanced Inrush

Fig. 11C: 4th Harmonic Component Currents for Balanced Inrush

Fig. 12B: 2nd Harmonic Component Currents for Unbalanced Inrush

Fig. 12C: 4th Harmonic Component Currents for Unbalanced Inrush

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FOURTH CASE — BALANCED INRUSH Energized Bank from Winding Two with Winding One Open (Severe A-phase residual flux)

Fig. 13A: Total Phase Currents for Unbalanced Inrush

TRANSFORMER DIFFERENTIAL CHARACTERISTIC BOUNDARY TEST A simple procedure can automate testing the phase differential operating characteristic. A common practice for commissioning distance protection is to test along the boundary of the operating characteristic — for example, circles, lenses or quadrilaterals. This practice can also be applied to transformer differential protection. Consider the simple example of a two-winding transformer with both sets of windings wye-connected. To keep the example simple, also assume both sets of CTs are wye-connected and have the same CT ratios — that is, both windings are at the same potential. If you connect the current leads from the test set such that the test currents I1 and I2 are flowing through the transformer windings, then the perphase differential and restraint currents can be expressed as follows:

Where I1 =

Winding 1 per unit current (A, B, or C-phase)

I2 =

Winding 2 per unit current (A, B, or C-phase)

Express equations 1 and 2 using matrices as follows:

Where

Fig. 13B: 2nd Harmonic Component Currents for Unbalanced Inrush

Invert the matrix M in equation 3 to determine the two equations for the test currents:

Calculate the test currents based on an operating point on the differential characteristic as follows:

Note: This test simulates through current, so the second test current should actually be represented as follows when injecting current: Fig. 13C: 4th Harmonic Component Currents for Unbalanced Inrush

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First Example: Consider a transformer differential characteristic for the two-winding transformer described earlier with the following settings: Pickup =

0.2 per unit

Slope =

28.6%

9

10

10

11

11

12

Where IA1, IB1, IC1, IA2, IB2 and IC2 are the CT currents. Use the following equations to test the A-Phase differential element at point ② of the characteristic shown in Figure 14:

Fig. 14: Phase Current Differential Characteristic for Two-Winding Transformer Table 1 lists the four operating points on the characteristic along with the corresponding test currents. All values are in per unit.

➀ ➁ ➂ ➃

Id

Ir

I1

I2

0.2

0.3

0.4

-0.2

0.2

0.7

0.8

-0.6

0.4

1.4

1.6

-1.2

0.6

2.0

2.3

-1.7

Table 1: Test Currents for Transformer Differential Characteristic Boundary Remember that the test currents are connected at 180 degrees out of phase (i.e., through current). Second Example: Now consider a transformer differential characteristic for a two-winding transformer connected delta (DAB) — wye with wye connected CTs on both sides. A numerical transformer differential relay internally compensates the CT currents as follows:

CONCLUSION This article demonstrates different techniques to test the multifunction numerical transformer protection relays and shows how to incorporate them using automated test software. COMTRADE for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays since it can be used to replay actual operating conditions or simulate very complex events, such as transformer energization when there is remnant flux on the core of a winding. The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using EMTP. The first case can be used to test harmonic restraint for any transformer differential protection relay that has phase current inputs rated 5 amps 60 Hz; therefore, it is a universal test. The second case shows that by using the RMS value of both the 2nd and 4th harmonic current, it is possible to have proper restraint for a difficult case of transformer energization where the core has significant remnant flux. Finally, it is shown how to automate testing the boundary of the phase differential operating characteristic to properly test the relay settings; at least four points are tested, which verifies the minimum pickup, break point, and both slopes.

Protective Relay Vol. 2 Steve Turner is a Senior Application Engineer at Beckwith Electric Company, Inc. He has more than 30 years of experience, including working as an application engineer with GEC Alstom for five years, primarily focusing on transmission line protection across the United States. He was an application engineer in the international market for SEL, Inc., again focusing on transmission line protection applications including single pole tripping and series compensation around the world. Steve wrote the protection-related sections of the instruction manual for SEL line protection relays, as well as many application guides on various topics such as transformer differential protection, out-of-step blocking during power swings, and properly setting ground distance protection to account for mutual coupling. Steve also worked for Duke Energy (formerly Progress Energy) in North Carolina, where he developed a patent for double-ended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Texas A&M Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and serves in the IEEE PSRC.

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MOVING FROM ELEMENT TESTING TO PROTECTION SYSTEM TESTING NETA World, Spring 2016 Issue Christopher Pritchard, OMICRON electronics Corp. USA

When it comes to commissioning and testing the protection system, many testing tools, methods, and approaches are available to meet every goal. To make an informed decision on the best testing strategy to apply, organizations must define and constantly review their goals. Inherently, every engineer and technician tries to do a good job. Therefore, the goal is to minimize misoperations of the protection system so that equipment is protected and power system stability is maintained. To effectively minimize misoperations, recognize their causes. Why? Because when typical causes are identified, the testing effort can be efficiently focused. As with all complex systems, the cause of every misoperation cannot be predicted, but organizations should learn from detail misoperation studies of the past. The NERC "Misoperations Report" can serve as such a reference. This article will briefly discuss the misoperation causes identified by the report and discuss how different test approaches will uncover them. Also, a novel test approach is introduced to identify major misoperation causes.

NERC REPORT OVERVIEW The NERC report on misoperations gives an overview of misoperations by cause code (Figure 1) and holds two major findings: ●● A misoperation can be caused by literally every component that is part of the protection system and is categorized by relays, communications, ac systems, and dc systems failure. While each component is often tested in isolation, it’s time to move forward toward a protection system testing approach. ●● Incorrect settings and logic and design errors are the biggest causes for misoperations. This is not likely to decrease by itself, as growing demands on cost and automation forces engineers to use more functions and logic inside modern microprocessor protection relays. The challenge lies in the fact that technicians have not had sufficient information to uncover errors in the design, since it is part of a different process step. To move forward in protection testing system design — in addition to testing components — a holistic view of the process is needed. Here is a closer look at these findings.

Fig. 1: NERC Wide Misoperations by Cause Code from 2011-2013

MOVING FORWARD TO SYSTEM TESTING Making sure the complete protection system is tested is not a new concept, and it has been highlighted in several papers and standards over the past years. NERC Standard PRC-005-2 provides detailed tables for testing protection components. Other examples as described in K. Zimmerman’s “Advanced Event Analysis Tutorial Part 2: Answer Key” show that although components are tested individually, severe issues in the interfacing between components are not uncovered. A simple example to illustrate: A current transformer (CT) has been tested, and its grounding has been verified according to the scheme drawing. Also, during commissioning, the relay has been tested with the CT polarity settings of the relay. Both components passed their test, but the CT polarity settings of the relay can still be wrong. The scope of protection system testing includes testing interfaces of multiple components of the system, as shown in Figure 2. In this case, a primary injection of the CT with a primary test set — while simultaneously comparing the injected current to measured values of the relay — would have uncovered issues with polarity, ratio, and the CT wiring.

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While relays contain multiple elements, modern protection systems contain multiple relays communicating with each other to build a larger, distributed logic scheme. Again, focusing just on the individual relays would not uncover any miscoordination of the bigger protection system. But testing a system of relays, like an end-to-end test, can be a complex and time-consuming task. Therefore, here are some improvements that together build a novel testing tool.

Power System Simulation Instead of SteadyState Sequences

Fig 2: Different Tests Types of One or More Components The same pattern applies to relay testing where pure element testing is still a common approach. As the name already suggests, the objective of element testing is to prove that an element inside the relay is working correctly. The origin of element testing comes from testing and calibrating electromechanical relays containing only one or two elements — still viable for these relay types. Presently, microprocessor relays contain multiple elements that are combined with logic and may reach up to 1,000 single settings or more. During an element test, each element of a relay is routed to a test contact to test for its threshold values and time delays. As shown in Figure 3, this bypasses the internal logic, ignoring the NERC misoperation study’s finding that logic errors are a major cause of misoperation.

The most common method for testing a relay protection system is to create one steady-state sequence for each relay and test set, which are then synchronously executed. One sequence contains a minimum of two states — a pre-fault state and a fault state — but can also contain more steps such as when reclosing or restoration are tested. These states have to be calculated for each end, and most likely, for different fault positions and loops. This is a labor-intensive and error-prone task. By using a power system simulation instead, this effort is reduced to a minimum. The simulation takes care of the signal calculation, with the effort being independent from the number of relays or elements involved. Defining a test case is as easy as placing a fault in the model’s topology. Another downside of steady-state signals is that the waveform detection in modern protection relays might drive a relay to lockout on signals that have unrealistic signal shapes. Because a transient power system model can simulate realistic signals, it does not have this issue.

Power System Simulation Onsite Instead of COMTRADE Replay Another common approach for end-to-end tests is to hand over transient recordings (e.g. COMTRADE) to the technician for a synchronized injection. It is advisable to go a step further and provide the system parameters with fault and non-fault test cases to run the simulation onsite for the following reasons:

Fig. 3: Element Testing Bypassing — Not Testing — the Relay Logic An element that is missing in the trip logic could still pass its test. Also, there is a risk of making setting changes to the relay under test, which can actually cause misoperations when they are not reverted. As electromechanical relays are steadily replaced by microprocessor relays, using testing methods designed for electromechanical relays to test their microprocessor replacements is rather questionable.

●● A fault scenario communicates the intention and empowers the technician to review the test cases beyond the thoughts of the protection design engineer. This follows the four-eye (peer review) principle. ●● In case of failed tests, the technician can alter test settings to determine the sensitivity of the failed test. This is common when working close to the tolerance band. ●● It provides the ability to tune the test setup to the latest data on site with measured line impedances, measured CT parameters, transformer data from the nameplate, CT, and PT ratios as installed, etc.

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Central Point of Control Instead of Verbal Coordination Most end-to-end tests are executed by handing over test files for each location of a test set or relay to a technician. They start the execution by coordinating via phone and agree on the next possible timeslot to start. An overall assessment is only possible after the test results have been returned to the engineer. An easier method is to control multiple test sets from software on one PC. Preferably, this master PC communicates to the test sets via a direct network connection, e.g. a substation-to-substation network. If this is not available, all test sets still can be controlled from one master PC while other PCs act as a proxy (Figure 4). The proxy PCs hand over control of their test sets to the master PC.

simulation, which adapts the current and voltage signals according to the new state. As a hard, real-time simulation cannot run on distributed test sets, a step-wise approach where the software learns the sequence from the relay’s reactions is a clever alternative. This is called an iterative closed-loop test., and its advantages include: ●● Simple test definition by just placing a fault independent from the complexity of the protection system. ●● False-coordination is visualized, which otherwise would be overlooked in a predefined steady-state sequence. Also, one can assess the severity of an error as it displays the misbehavior from a power system point of view.

SETTINGS, LOGIC, AND DESIGN ERRORS General protection element-setting errors, improper timing coordination, and zone overreaching are the main cause inside the setting-error cause code. While improper coordination timing and zone overreaches can be reduced by thorough system studies, the vast amount of relay functions and settings and their effect on the system protection is extremely challenging. Quality assurance often falls to the system design process, as an element test at best is able to test that a wrong setting is transferred to the relay. To avoid the error propagation from the design step to the commissioning step, apply protection system testing. Extend the concept of covering multiple components, their interfaces, and interactions to covering multiple process steps and their data exchanges. This is extremely important, especially if one or more steps in the process are outsourced to a service company, as this makes a good data exchange between the steps more demanding. A protection system test should be an important step in a final field acceptance test by the operator. The same tool capabilities as described previously are key to this approach.

Fig. 4: Test Setup for a Three-Terminal Line Protection In addition to not starting the test verbally, this has the added advantage of results presented immediately after execution. Paired with a power system simulation, the user can easily adapt the test cases at site for all locations with almost no effort. For troubleshooting reasons, making changes to a setup that is not centralized can be extremely difficult.

Protection system design is based on power system simulations of fault and non-fault scenarios. By using the same power system data for the model used inside the testing tool to calculate currents and voltages, protection of the power system is more easily assessed. Figure 5 shows how an application-oriented test spans across the process.

Relay in the Loop Instead of Predefined Event Sequence Very often, misoperations can be found when testing beyond the first trip command of the protection system, e.g. unequally coordinated reclosing sequences or current reversal in parallel line circuits. Both cause unwanted trips or breaker failure trips. These issues are usually classified as settings, logic, and design errors, which will be discussed in the next section. Creating a predefined sequence of states can again be very complex; therefore, use a testing tool that can react to each possible trip or close command by simulating the breaker inside the power system

Fig. 5: Uncovering Design Errors by Using ApplicationOriented Testing

Protective Relay Vol. 2 THE RIGHT TOOL AT THE RIGHT TIME From a systematic point of view, it is still important to test each component before testing larger parts of the protection system. The more relays, custom logic, or complex coordination that are required, the more focus should be on application-oriented or protection system testing. The tools for application-oriented testing are already available and have shown their usefulness, e.g. for busbar, distribution scheme, and line protection testing.

REFERENCES Protection System Misoperations Task Force, “Misoperations Report,” North American Electric Reliability Corporation (NERC), Atlanta, 2013. “Protection System Maintenance,” NERC Standard PRC-005-2, 2012. K. Zimmerman, “Advanced Event Analysis Tutorial Part 2: Answer Key,” www.selinc.com, 2013. K. Zimmerman and D. Costello, “A Practical Approach to Line Current Differential Testing,” 66th Annual Conference for Protective Relay Engineers, 2013. T. Hensler and C. Pritchard, “Test and Analysis of Protection Behavior on Parallel Lines with Mutual Coupling,” Australian Protection Symposium, Sydney, 2014. OMICRON Energy, OMICRON Electronics, April 1, 2015, www.youtube.com/watch?v=a_lRgJ9_Gcc. C. Pritchard and T. Hensler, “Test and Verification of a Busbar Protection Using a Simulation-Based Iterative ClosedLoop Approach in the Field,” Australian Protection Symposium, Sydney, 2014. D. Bowman, B. Walker, C. Wright, A. Smit, A. Stinskiy, S. Chanda, T. Houseknecht, C. Pritchard, and S. Geiger, “Distributed Synchronous Coordination Field Testing of an Actual Automated Distribution Feeder System,” PAC World US, Raleigh, 2015. Christopher Pritchard was born in Dortmund, Germany. He started his career in power as an electrical energy technician. Christopher received a diploma in Electrical Engineering at the University of Applied Science in Dortmund in 2006. He joined OMICRON electronics in 2006 where he worked in application software development in the field of testing solutions for protection and measurement systems. Christopher is now the responsible Product Manager for simulation based testing solutions.

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ELECTRICAL COMMISSIONING FOR IMPROVED AVAILABILITY, SAFETY AND COST SAVINGS NETA World, Spring 2015 Issue Michael Donato, Emerson Network Power, Electrical Reliability Services While commissioning has existed as a building construction industry discipline for nearly three decades, the commissioning industry is evolving. Commissioning activities are continually being refined and updated by practitioners and industry organizations. In fact, the American National Standards Institute (ANSI) together with the InterNational Electrical Testing Association (NETA) is currently developing the new Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems (ANSI/NETA ECS).

Additionally, it verifies that the testing organization is a well-established, full-service electrical testing business.

For critical facilities, commissioning often involves much more than just the electrical power equipment. However, the purpose of this article is to clearly define electrical system commissioning, highlight the need for this commissioning within critical facilities, and explain some of the many commissioning benefits.

While CxAs do not have any decision-making power relative to the owner, a quality CxA will offer the expertise, guidance, and direction the owner needs to make informed decisions and realize the most value from electrical system commissioning.

DEFINITION AND SCOPE The definition of commissioning varies greatly from one commissioner to the next and one building owner to the next. However, industry experts generally concur with the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE), which asserts that the focus of commissioning is “verifying and documenting that the facility and all of its systems and assemblies are planned, designed, installed, tested, operated, and maintained to meet the needs of the owner.” More specifically, the electrical system commissioning is the systematic process of documenting and placing into service newly-installed or retrofitted electrical power equipment and systems. The scope of ANSI/NETA ECS is to assure that tested electrical systems are safe, reliable, and operational; are in conformance with applicable standards and manufacturers’ tolerances; and are installed in accordance with design specifications. Additionally, the standard specifically states that “only qualified and authorized persons with adequate and relevant commissioning experience should conduct the work” described in the standard. One of the best ways for commissioners to ensure that the full scope of electrical system testing is met and that their commissioning team is meeting regulatory requirements is to work with a NETA Accredited Company. This designation confirms that technicians have the proper knowledge, training, and equipment.

Another approach that many complex, critical facilities such as data centers, use to ensure successful electrical system commissioning is to hire a Commissioning Authority (CxA) to oversee and execute the entire process. ANSI/NETA ECS outlines the responsibilities of the owner’s representative, a role that the CxA would fulfill.

Ideally, a CxA would be brought on to a project at the very beginning—during the predesign or design phase. This gives a CxA the ability to influence the details of the owner’s project requirements (OPR). The OPR becomes the keystone of the electrical system commissioning project, and the CxA makes sure that all activities align with meeting these requirements. An OPR should always be developed in order to streamline design time, establish performance targets and measure project success. One recommendation for ensuring the creation of a comprehensive, user-friendly document is to hold an OPR workshop that brainstorms project requirements and gets buy-in and involvement from all the key stakeholders. During this workshop is an opportune time to discuss the roles and responsibilities of all involved, as often commissioning is confused with other types of testing and processes. For example, some firms consider just acceptance testing and/or equipment startup to be commissioning. While those tasks are part of electrical system commissioning, much more is involved for a complete commissioning project. As stated in ANSI/NETA ECS, the commissioning standard should be used in conjunction with the most recent edition of the acceptance testing standard. Furthermore, the NETA standards should be used together with other commissioning documents to expand the scope to include all applicable systems such as mechanical instrumentation, heating and refrigeration, and building systems.

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Full System Integration

A major impetus behind commissioning electrical systems of critical facilities is the increasing complexity of the systems themselves, which presents more opportunities for problems, and the fact that there is virtually zero tolerance for unplanned downtime due to the staggering financial and reputational costs of outages.

For maximum availability, all critical systems—electrical, mechanical and controls—must function together and be a fully integrated system. Historical approaches to testing and startup verified only that each individual system’s components functioned independently. Today, a CxA employs more sophisticated processes and tests to verify that all electrical components work together to support an integrated system.

Appropriate electrical system commissioning activities can ensure uptime by identifying the causes of failures and outages. Nearly 70 percent of early equipment failures can be traced to design, installation, or startup deficiencies. Electrical system commissioning can help to detect and correct these problems before the failures or outages occur. Commissioning is also the answer to a wide variety of other owner concerns. Issues such as ensuring the operations and maintenance (O&M) staff has adequate resources, improving safety, and boosting efficiency of critical facilities can all be addressed by specifying the right commissioning activities. Therefore, the appropriate scope of commissioning relates directly to owners’ requirements for their critical facilities . It is the opinion of Electrical Reliability Services (ERS) that a comprehensive approach to commissioning—one that encompasses a wide range of building systems and spans the entire design/ build process—results in the greatest value to project owners. However, even if commissioning activities only include the electrical equipment and systems, owners can still realize many of the following benefits when critical facility commissioning best practices are incorporated.

BENEFITS Less Unplanned Downtime and Fewer Repairs Preventing or greatly reducing the possibility of unplanned downtime is perhaps the greatest value electrical system commissioning provides for critical facilities. Commissioning activities ensure that mission-critical equipment is correctly installed and that systems are fully integrated. The process checks for redundancy and single points of failure. It includes comprehensive system testing to verify availability in all operating modes. These activities help identify potential system-related problems so they can be resolved before leading to major equipment damage or disruption of service. Commissioning can also ensure a well-trained and well-equipped O&M staff that is less likely to make mistakes that lead to system failure.

Reduced Life Cycle Costs Done correctly, electrical system commissioning improves system performance throughout the facility life cycle. In addition to optimized performance, it also decreases operation and maintenance costs and cuts down on energy consumption for smaller utility bills.

Benchmarking Data Electrical system commissioning creates extensive documentation for benchmarking system changes and trends. The data can be used to identify future problems with the system, maintain optimal operations, and evaluate future maintenance decisions.

Improved Efficiency If efficiency features have been designed and built into the electrical system, commissioning activities can verify that the features function as intended. Therefore, the owner will be able to realize the resulting energy cost savings.

Enhanced Safety and Compliance The electrical system commissioning process produces a safer facility and reduces owner liability by uncovering safety problems before, during, and after energization. Commissioners can verify compliance with National Fire Protection Association’s safety-related maintenance practices (NFPA 70E). They can also ensure that owners and O&M staff have all equipment manuals and operation instructions pertaining to electrical equipment.

Return on Investment The benefits of electrical system commissioning can create a return on investment that exceeds its cost. In a recent study of commissioning projects performed by Electrical Reliability Services, the analysis revealed that the key issues discovered and corrected during the commissioning process resulted in cost savings and/or revenue earning potential for the owner that well exceeded the total cost of commissioning. Additionally, proper commissioning extends equipment life and lowers operation and maintenance costs for a lower total cost of ownership.

Speed to Deploy Under the CxA’s oversight, projects experience fewer change orders, delays, and rework, avoiding the considerable costs of late occupancy, liquidated damages, extended equipment rentals, and other costs associated with delays. Commissioned facilities are more likely to be deployed on time and on budget.

CONCLUSION Commissioning is verifiably a critical step when placing newly-installed or retrofitted electrical power equipment into service

76 within a critical facility. To realize the greatest value, owners should look for a CxA that has the knowledge and experience needed to streamline the project. Owners should also seek the electrical system testing expertise of a NETA Accredited Company to help execute the commissioning plan. When done right, commissioned electrical power equipment and systems offer a number of benefits including improved availability and safety, as well as cost savings. Ultimately, commissioning produces a higher level of owner satisfaction at the time of turnover and for many years to follow. Michael Donato has more than 24 years experience performing and managing electrical testing, maintenance and engineering services for Emerson’s Electrical Reliability Services group.In his current role and for the past 13 years, his particular expertise is in commissioning data center facilities. Michael has successfully commissioned hundreds of data centers ranging from small telecom sites to large Tier IV data centers including some LEED certified facilities. His focus has been to provide measurable value to owners at all phases of the commissioning process. Michael has earned his QCxP and LEED AP certifications and continues his education in commissioning theory and implementation through the University of Wisconsin.

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IEC 61850 —A TALE OF TWO DECADES NETA World,Winter 2016 Issue Joseph Menezes, ABB Grid Automation Products

The first version of IEC 61850 was published in 2004, though it was three years later when the final part of the standard saw print. Before the first document was approved, the Herculean work had already taken about 10 years. The final version consisted of 14 parts laying down the technical standards, and, perhaps more importantly, the semantic language for creating digital substations. The adoption of IEC 61850 has enabled a new generation of substations, more reliable and better managed, while driving suppliers to create compelling (but compatible) equipment to solve old problems in new ways. Ten years from that original publication, IEC 61850 Edition 2 is now appearing in devices, bringing another decade of accumulated experience and knowledge to the standard and broadening the reach, refining the language, and extending the functionality to reflect an industry that has changed dramatically over the last two decades. IEC 61850 was always a broad standard; it not only specified the logical architecture of a substation and the communication protocols to be used, but also the format of the messages and the functional capabilities. The standard even covers the naming conventions, the way that applications interact with devices, and how those devices are tested to ensure conformity. The major parts alone run more than a thousand pages. But the standard abstracted the content of the communications from the protocol used to convey it, allowing an evolution of networking technologies independent from the management systems. It created an object model describing what information was available and from where, as well as how devices could be configured with a standard substation configuration description language (SCL). IEC 61850 kick-started the transition to digital substations, an ongoing process that would not have come nearly this far without an internationally recognized standard behind it. Updating IEC 61850 is an epic task, but at least the standard is split into parts that can be addressed individually. Those parts are, therefore, updated separately (with one being added), and each has its own Edition 2 publication date. For basic enhancements like fixing the mistakes and ambiguities of the first version, that’s easy enough; but where new capabilities have been added, support was needed across the parts, and working groups had to cooperate to ensure interoperability was maintained. The additional breadth of the standard is obvious from the title, which has changed from Power Utility Automation to Commu-

nication Networks and Systems for Power Utilities. This reflects the use of IEC 61850 with wind and hydro power as well as distributed energy resources, where the challenges are different but the solutions may be the same. Many companies have already deployed IEC 61850 in these environments with great success, but when a system manages non-electrical quantities, then proprietary formats and language have to be used — or had to be used until Edition 2 extended the options available. Other than adding those options, the extension of the standard is just a matter of tightening up a few details and rubber-stamping the approval-for-use in these new industries. Even in traditional substations, the standard has become more broad, thanks to the increasingly complicated management systems being deployed. Modern IEDs now support several functions at once, meaning they can operate as multiple devices within a single physical enclosure. Such a device requires a hierarchical control structure, as the logical devices will share some configuration parameters and should thus be addressed as a group, while other parameters will need to be set individually and require individual referencing. Communicating new properties means extending SCL, the XML-derived language used to describe delivered parameters and reported data, which (with Edition 2) can now better support engineering processes and retrofitting, as well as provide an exchange of mandatory and optional features between IEDs and the tools that use them. IEC 61850 has become more literally broad, with the ability to communicate data between substations as well as within them. Edition 2 extends SCL so it can be used between substations creating a single management network. Initially, that will be over a low-bandwidth link; taking IEC 61850 beyond the switch yard to the point where the substation automation systems merge may take an addendum to Edition 2 — or even wait for a new edition before it is properly agreed — but Edition 2 has laid the groundwork for that to happen.

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PROTECTIVE RELAY MISOPERATIONS AND ANALYSIS NETA World, Winter 2016 Issue Steve Turner, Beckwith Electric Company, Inc. This paper provides detailed technical analysis of two relay misoperations and demonstrates how to prevent them from occurring. An unwanted breaker failure operation tripped a large generator during high load, resulting in an outage in the adjoining downtown area of a large city. A transformer differential trip protecting the generator step-up transformer at a process plant occurred due to sympathetic inrush when a large nearby GSU was energized via the interconnecting high-voltage transmission line, resulting in an extended outage.

Fig. 2: Breaker Failure Logic

Original Protection Settings Figure 3 shows the original relay settings for this breaker failure scheme.

Each individual analysis ends with a conclusion stating why the relay misoperated and providing a recommendation on the best practice for the particular application.

CASE 1: UNWANTED BREAKER FAILURE OPERATION — LARGE GENERATOR TRIPPED DURING HIGH-LOAD PERIOD Synopsis During a period of high load, a breaker failure trip occurred in a large offline generator located in the downtown area of a large city resulted in an outage. Figure 1 shows the system topology at the time of the trip. Note that the generator is connected to the transmission grid via a high-voltage breaker. The links connecting the generator to the GSU were open as well as the high-side breaker. The low-side winding of the GSU drew excitation current since it was energized via the auxiliary station service.

Fig. 3: Breaker Failure Settings

Fault Current Signals Figure 4 shows the oscillography captured by the relay at the time of the trip.

Fig. 1: System Operating Conditions

Original Breaker Failure Scheme Logic Figure 2 shows the original logic used for this breaker failure protection scheme.

Fig. 4: Fault Event Oscillography

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Fig. 7: System Operating Conditions (Arrows Indicate Direction of Inrush Current)

ORIGINAL PROTECTION SETTINGS Fig. 5: Fault Current Phasors

Figure 8 shows the original settings for the transformer differential protection.

Case 1 Conclusion The breaker failure trip occurred because IC was above the current detector pickup setting and input 4 (BFI) was asserted. The breaker failure function may be used for a unit breaker rather than a generator breaker. It is limited in that no fault detector is associated with the unit breaker. Output contact operation would occur if any of the initiate contacts close, and the 52b contact indicated a closed breaker after the set time delay. The corresponding logic is shown in Figure 6.

Fig. 8: 87T Settings

Fault Current Signals Figure 9 shows the oscillography captured by the relay at the time of the trip. Note that current input IAW1 is almost completely offset, and there is some distortion in other current inputs as well.

Fig. 6: Fault Current Phasors

CASE 2: TRANSFORMER DIFFERENTIAL TRIP DUE TO SYMPATHETIC INRUSH Synopsis The transformer differential relay protecting the step-up transformer at a processing plant tripped when a nearby large GSU at a power plant was energized from the high side. The trip was due to sympathetic inrush current flowing through the step-up transformer (Figure 7).

Fig. 9: Fault Event Oscillography (Raw Waveforms)

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Figure 10 shows the second harmonic content of the current inputs at the time of the trip.

Case 2 Conclusion For several decades, electro-mechanical relays had a fixed harmonic inhibit level of 20 percent. This worked well for a period of time until transformer manufacturers began making better transformers that used less material and were designed with smaller tolerances. Therefore, modern laminated-steel-core transformers will not reliably produce 20 percent second harmonic current during inrush. Based upon this particular event, an 11 percent setting for the second harmonic restraint would be the most reliable. Note that the multi-function numerical relay in this application actually uses the root mean square (RMS) of the second and fourth harmonic differential current, but that still was not enough to restrain the protection.

FINAL CONCLUSION

Fig.10: Fault Event Oscillography (Second Harmonic Content) The second harmonic differential current present when the trip occurred was as follows: A-Phase = 17 percent B-Phase = 13 percent C-Phase = 13 percent The ratio of harmonic to fundamental differential current used to restrain the transformer differential protection is calculated as follows (Figure 11):

Fig. 11: Even Harmonic Restraint Equation If the ratio is greater than the restraint setting, then the transformer differential protection is blocked (Figure 12).

Fig. 12: Even Harmonic Restraint Logic The original second harmonic restraint setting was 20 percent for the electro-mechanical transformer differential relay. The customer used the same setting for the multi-function numerical relay that replaced the original electro-mechanical relay. Figure 10 shows that a setting of 20 percent was not sensitive enough to detect the sympathetic inrush current flowing through the step-up transformer.

The technical analysis of these two relay misoperations, along with examples of how to use the data recorded by a relay during these types of conditions, should help you understand why each misoperation occurred and how to implement best practices for each particular application. Knowing that the first misoperation was due to an incorrect relay setting, while the second was due to an incorrect application, should clarify the need for careful attention during the design and initial work stages. Joseph Menezes is the Global Product Manager for ABB Grid Automation Products, responsible for the Relion® 670 series protection and control products. He has 25 years of experience in automation, control, and protection of power systems with a background in product development and product management.

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THE FUTURE OF INTEGRATED POWER AND PROCESS AUTOMATION NETA World, Winter 2016 Issue David C. Mazur and John A. Kay, Rockwell Automation As technology continues to drive innovations, industrial enterprises must continue to keep pace to remain competitive in an ever-changing marketplace. The technology trend is to replace yesterday’s systems with higher-performance, low-cost, option-rich devices that shorten the return on investment and offer more flexibility. As control system technology evolves, systems migrate to functions that are being increasingly distributed to smarter, more granular, control-system components capable of performing localized operations. Industrial facilities are under increasing pressure to reduce overall costs, boost productivity and quality, and improve personnel safety. One systematic approach for reaching these goals is automating and integrating facilities from the plant floor through the management of process information. Device-level integration through digital communication is the key to unlocking the full potential in the electronic controls being installed in industrial plants today. New advancements in device-level status monitoring and communications have boosted process throughput, system practicality, and affordability of complete plant-level integration. Furthermore, while the industrial automation space was being transformed by networks and communications, so, too, was the electrical infrastructure market. The challenge that remains is how to effectively integrate these two systems in an optimized, intuitive fashion. If one compares the evolution of heavier-than-air vehicles, adding more powerful engines was not a solution when there was lack of proper and efficient flight controls. Without a review of the entire system, such as with the power and process systems of a modern facility, the overall system will lack high performance.

Fig. 1: Process and Power Models Figure 2 shows that, although the process and power automation systems have been logically isolated by industry, they are closely coupled to each other. It is very difficult to logically separate power from process, as they are intermingled within each other. The figure represents the power automation network in red and the process automation network in green. The red arrow suggests the linkage needed to realize the full potential of these industrial systems.

POWER AND PROCESS TRENDS TODAY Today, many industrial processes are controlled by a combination of systems working together (hopefully, in sync) to produce a target yield or product. Examples of these systems include continuous and discreet process control systems, electrical protection, SCADA, historian for archiving, and reporting tools for data trending. Traditionally, these subsystems have been logically separated as seen in Figure 1. The red boxes in Figure 1 depict the process automation system with intelligent motor control (IMC) devices — e.g., variable frequency drives, overloads, starters, etc. — feeding a process controller. This process controller feeds data to higher level systems to archive and report on the data. The blue boxes represent the power automation system where intelligent electrical devices (IEDs) feed a power automation controller. This controller, in turn, feeds similar higher-level systems to archive and report on the data. Although these two systems are within the same facility, they are logically isolated.

Fig. 2: Power and Process Systems

THE EVOLUTION OF POWER AND PROCESS AUTOMATION Advancements in technology have created a society where companies want to collect a large amount of real-time data, sort this data — and with the advent of the discrete event data — turn this into actionable information. Today, there is a push to archive this discrete data so that it can be trended at a later time, as well as used for modeling of the overall process. From an industrial manufacturing standpoint, electrical protection and SCADA data is crucial to identify operating points, create predictive mainte-

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nance models, identify load-shedding opportunities, and manage energy consumption and root-cause analysis. As the information age has evolved, so has the technology used to transmit data from the electrical protection system to SCADA systems. Power system and industrial-based electrical protection devices have evolved over the past three decades from electromechanical to microprocessor-based relays. In parallel, the communication networks for electrical protection have also evolved. Electrical protection architectures have developed from hard-wired contacts to communication networks using serial protocols, such as Modbus. Serial communication has evolved to communication protocols over the TCP/IP stack, such as Modbus TCP and DNP3 LAN/WAN, which then allowed substation devices to communicate in a peer-to-peer manner to share data. The IEC 61850 standard has become more prevalent in recent years. These examples and applications show that an Ethernet-based standard, such as IEC 61850, can be used for protection, command and control, and SCADA gathering of data over the same redundant wire pair. As this real-time data is provided to the central controller or SCADA master in the system, graphics can be populated to alert engineers and operations to system status in a time-synchronized fashion. Additionally, this data can be used to make command-and-control decisions in an industrial application. Furthermore, leveraging power and process in a unified solution provides users many benefits while reducing the overall total cost of ownership.

A UNIFIED SOLUTION FOR POWER AND PROCESS By using data from process and power controllers, an iterative evaluation of overall system efficiency, process-stage efficiency, and product quality can be performed. The result can help eliminate process bottlenecks and inefficient process steps, and reduce energy usage while maximizing overall system or plant output performance. Installing more efficient machines in one process step may actually be detrimental to the overall system performance without the review and collaboration of data from both data sources. Furthermore, harmonizing the upper layers of visualization, archiving, reporting, and enterprise services reduces cost and overhead for industrial process owners. The value of the unified system can be realized in the visualization, archiving, and reporting systems.

VISUALIZATION Although automation control companies have developed solutions for process visualization, this solution takes process visualization one step further into the electrical distribution system. The IEC 61850 standard allows for the visual representation of reports and alarms at the process control level. With the development of more sophisticated human-machine interface (HMI) screens, global objects have been introduced into the automation graphics. The use of these global objects has allowed for the creation of faceplates, defined as reusable standard objects.

Fig. 4: Graphical Faceplates Examples of process faceplates can be seen in Figure 4. The left side of Figure 4 shows the representation of a low-voltage power circuit breaker with its command-and-control functions. The right side of Figure 4 depicts a faceplate of a low-voltage, variable-frequency drive. Each faceplate was constructed with multiple tabs to change between home, engineering, and diagnostic screens. Graphics were designed to provide a user experience similar to interacting with the physical device. The advantage of the faceplate is that it is a familiar, standard, prebuilt object that can be implemented repeatedly for similar engineering designs. The common naming convention and logical model of IEC 61850 allow for a vendor-independent implementation of electrical distribution equipment, e.g., circuit breakers, relays, power monitors, etc. This information can be simultaneously displayed with process information provided by IMC devices, e.g., drives, overloads, starters, etc. Providing a unified visualization environment allows all pertinent information to be displayed in one place where data can be effectively acted on as actionable information.

ARCHIVING

Fig. 3: Unified Visualization, Archiving, and Reporting

Time stamping of event data can be placed in a process historian, even if the act of event detection is a distributed system component. This enables reporting and key performance indicator (KPI) calculations based on energy data, as well as manufacturing processes variables. The impact of manufacturing intelligence with power systems data will yield relationships that, to date, have not been available in typical reporting environments. IEDs are critical to the management and control of industrial and commercial power systems, and can provide value in an environment with process historians.

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Protective Relay Vol. 2 Highly accurate and time-synchronized energy consumption and energy balance data can be used to determine overall process efficiencies for various production or process operations. Data from trip and alarm events can be deterministically used to establish maintenance schedules to prolong equipment life. Additionally, machine or production-flow characteristics can be refined and monitored to enhance production rates and maximize specific machine capabilities.

ASSET-BASED MODELING The Industrial Internet of Things (IIoT) has created an environment where more data from assets is available than ever before. KPIs have traditionally been used to define metrics of industrial petrochemical facilities. The IIoT can present a number of KPIs for facility assets that are not uniform across similar types of equipment. Consequently, users have been seeking consistent application of KPI solutions across their enterprise assets. The definition of an asset template allows for consistent representation of a device across the industrial enterprise. Furthermore, this allows for comparison between assets or control processes in a standard fashion, thus optimizing reporting capabilities. Asset models for equipment remove the concept of flat tags in a historian, replacing it with an object-oriented model. Tags that are monitored and archived are now associated with a physical piece of equipment or process, allowing context to be immediately applied. Furthermore, analytics can now be trended on each asset. Additionally, asset performance can now be compared at multiple levels: asset to asset, process line to process line, and facility to facility. The concept of asset modeling can be applied to power and process automation, thus providing standardization across the industrial enterprise.

Fig. 5: Asset Model Example

REPORTING The large quantity of data generated by modern automation systems makes it possible to apply a broad range of plant analytics to the automation systems and processes that make up an industrial enterprise or business. Reports, charts, and other human-readable formats are often available or may be created for plant personnel and others to monitor and review the generated data in either a real-time mode or at a later time after the data has been stored.

A report created to display the data of a given industrial automation system may find it difficult to find and display similar data of another industrial automation system. Objects and other components of the other system may be similar or even identical to the first system. However, due to even slight variations in component names (for example, during the system setup stage), a disconnect can exist between the data stored in the system and a pre-generated report designed to look for specifically named objects in the system. Thus, reports previously created may not display all the data they were designed to show. Creating new reports or even fixing pre-generated reports to show the data generated by a particular system can be a laborious and tedious manual process. This process can require setting up individual connections between system data points and the parameter value to be reported for hundreds of parameters or more. The benefit of the IEC 61850 standard is that the logical model allows for standard reporting across vendors in a specific format. This means that an IED of a specific type from Vendor A can be reported on the same way as an IED of the same type from Vendor B. IEC 61850 allows for asset-based reporting models and type-based reporting, where reporting systems have the context of devices on which they are reporting. By creating type-based reports, users can associate content in the form of trends, graphs, and analysis on a particular type of device. When it is instantiated within the enterprise system, the reports come pre-populated and wired to system tags due to the common naming convention of the standard. This provides a substantial design time savings for implementers of a unified system.

UNIFIED POWER AND PROCESS REPORTING Even more powerful reports can now be created in a unified environment. These reports may provide additional insight into cause and effect of how changes in the power automation system affect process automation and vice versa. These reports will allow process owners to provide better predictive and preventive maintenance, as well as optimize their overall process to new levels. The ability to obtain electrical information within the unified system allows for energy inputs into the facility optimization state space equation. For example, in Figure 6, a unified system, a process owner can realize instantaneous profit, as they know all of the process yields (gross profit blue line), as well as the total costs to produce (red line). The area between these two curves provides the owner the instantaneous system profit in a timely fashion. This information can feed additional control loops to take corrective action and further optimize the process. Now, electrical distribution parameters can be effectively used in process optimization schemes. Furthermore, this electrical data can now be used in overall efficiency calculations and asset liability, and can be presented in dashboard format as seen in Figure 7. This data can be used to compare not only process line data, but also can be extrapolated in a facility-to-facility comparison providing a true enterprise comparison for process owners.

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Protective Relay Vol. 2 S. H. Horowitz and A. G. Phadke, Power System Relaying: John Wiley & Sons, 2008. D. C. Mazur, R. D. Quint, and V. A. Centeno, “Time Synchronization of Automation Controllers for Power Applications,” IEEE Transactions on Industry Applications, vol. 50(1) (January 2014): 25-32.

Fig. 6: Simulated Profit of an Oil Pumping Station

D. C. Mazur, J. A. Kay, and J. H. Kreiter, “Benefits of IEC 61850 standard for power monitoring and management systems in forest products industries,” in Pulp and Paper Industry Technical Conference (PPIC), Conference Record of 2013 Annual IEEE (2013): 69-75. D. L. Ransom and C. Chelmecki, “Using GOOSE messages in a main-tie-main scheme,” in Industry Applications Society Annual Meeting (IAS), 2012 IEEE, 2012, pp. 1-8. D. Dolezilek, “IEC 61850: What You Need to Know About Functionality and Practical Implementation,” in Power Systems Conference: Advanced Metering, Protection, Control, Communication, and Distributed Resources, 2006. PS ‘06 (2006): 1-17.

Fig. 7: Process System Dashboard

CONCLUSION A common connected architecture across the process control and power control infrastructure creates a straightforward method for an organization to securely integrate and manage information flow across the entire connected enterprise. Captured enterprise-wide data — starting from the most critical assets to the smallest shop-floor sensors — can provide the most relevant working data capital needed to deliver complete plant- and enterprise-wide automation and process efficiency. The true value of this enterprise-wide data lies not in the data itself, but in which analytics can be applied to the data. In this way, the raw information reveals areas where process and control transformation can be applied to identify points where power and process optimization can be employed. This working data capital is easily displayed and analyzed by those decision makers, at many levels of the enterprise, who can put it to best use. Using the most relevant interconnected technologies enables more efficient analysis, communication, and visualization of this valuable and scalable working data capital across the entire enterprise.

REFERENCES D. C. Mazur, J. A. Kay, and K. D. Mazur, “Intelligent motor control, a definition and value add to process control,” in Industry Applications Society Annual Meeting, 2013 IEEE (2013): 1-7. D. C. Mazur, “An Electrical Mine Monitoring System Utilizing the IEC 61850 Standard,” Doctor of Philosophy, Mining and Minerals, Virginia Polytechnic Institute and State University, 2013.

V. M. Flores, D. Espinosa, J. Alzate, and D. Dolezilek, “Case Study: Design and Implementation of IEC 61850 From Multiple Vendors at CFE La Venta II,” in Protective Relay Engineers, 2007. 60th Annual Conference for Protective Relay Engineers (2007): 307-320. T. Zhao, L. Sevov, and C. Wester, “Advanced bus transfer and load shedding applications with IEC61850,” in Protective Relay Engineers, 2011 64th Annual Conference for Protective Relay Engineers, (2011): 239-245. L. Sevov, T. Zhao, and I. Voloh, “The power of IEC 61850 for bus transfer and load shedding applications,” in Petroleum and Chemical Industry Conference (PCIC), 2011, Record of Conference Papers Industry Applications Society 58th Annual IEEE (2011): 1-7. David C. Mazur is System Architect for Rockwell Automation in Milwaukee, Wisconsin, and currently focuses on SCADA communications and substation automation. David received his B.S. in Electrical Engineering from Virginia Polytechnic Institute and State University, Blacksburg, Virginia, in 2011. He graduated from Virginia Polytechnic Institute and State University with his M.S. in Electrical Engineering in 2012 for his work based on rotor angle measurement of synchronous machines. David received a Ph.D. in mining engineering from Virginia Polytechnic Institute and State University in September 2013 for his work with automation and control of the IEC 61850 standard. John A. Kay, received his degree in electrical/electronic engineering technology from Conestoga College, Kitchener, Ontario in 1977. He has authored a wide variety of award-winning technical papers and other articles and manuals related to medium-voltage electrical control and protection systems, arc-resistant equipment, and infrared technologies. John is a Fellow of IEEE and the Industry Application Society. He is also actively involved with the IEEE Pulp and Paper Industry Committee, serving on its main executive board, its conference committee, and on several subcommittees. He is a Certified Engineering Technologist in the province of Ontario.

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USING TEST PLANS AS A TOOL FOR PROTECTION TESTING SPECIFICATIONS NETA World, Summer 2016 Issue Benton Vandiver III, OMICRON electronics Corp. Over the past 30-plus years, I have had numerous conversations with technicians, engineers, and managers on how to create the best test plan for many of the relays, protection schemes, and protection-and-control (PAC) systems used in the utility industry. The discussion generally turned into a lengthy laundry list of what they actually wanted to accomplish during their test process. Some of the tasks mentioned included:

3. The user’s final configuration/settings of the Intelligent Electronic Device (IED) or system (Figure 1)

●● Proof of calibration ●● Proof of proper settings ●● Proof of the ac system components ●● Proof of the dc system components ●● Verify the interconnections ●● Verify the functions ●● Verify the scheme logic ●● Verify the overall protection system coordination For these tasks, the test plan comprised a specific list of the test methods and steps required to accomplish them. For the proofof tasks in electromechanical devices and systems, the steps were essentially specified by the manufacturer in the device instruction manual and any special publications dealing with maintenance tasks or calibration. For newer technologies, these specifications evolved to more black-box testing designed to prove the device specifications or troubleshoot the device’s components and calibration, since typically, the setting parameters were directly set or displayed physically on the device. In the newest digital technologies, this has been supplanted by software programming of the parameters and firmware updates, self-diagnostics, observational testing, logs, and reports. Most often, what was actually desired from the test plan was the least amount of work to satisfy a testing compliance requirement. In addition, they wanted an assurance that the testing performed was sufficient for the task(s) that the tester executed, and that the test procedure was correct, accurate, and repeatable. It was a bonus if the test procedure was self-instructing or automated so that training was minimized, the ultimate goal being the one-button test. In the past, a working test plan for a PAC device or system was not automatically delivered with it, nor was it made by accident. It evolved from three distinct steps driven by the utility user: 1. The test philosophy implemented by the user 2. The user’s protection philosophy and a generic test plan structure developed from it

Fig. 1: An IED-Specific Test Plan A user’s test philosophy is often based on operational history — usually scenarios of specific device misoperations from a variety of causes — as well as compliance issues, manufacturer guidelines, and industry standards. Often, the philosophy was known but not always documented effectively and was internally perpetuated through on-the-job knowledge (e.g., “We always test at 2x, 3x, 4x pickup.”). As PAC technology changed, the testing philosophy adapted slowly or not at all, resulting in unnecessary or improper testing of the new PAC device or system. This also extended to: ●● Test equipment used ●● Tolerance definitions and performance expectations ●● Test methods applied ●● Proper training (knowledge and skills) ●● Documentation of the objectives (compliance, calibration, etc.) Some examples would be using a one-phase test set on a relay using three-phase algorithms and logic; using electromechanical tolerances on a precision digital device; step-change injections expecting dynamic performance; or no PC/software user skills and expecting one-day training to master the PC-controlled test kit. The proactive user would take all these points into consideration and craft a protection system specification(s) that would clearly convey how the devices and systems should be applied, the test philosophy employed, and how it was to be achieved. It was a living document continually updated based on current PAC devices and systems in use, compliance requirements, training requirements, and performance expectations.

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When a specific protection philosophy was applied, it refined the definition of what was to be tested. Using a basic fourzone step distance scheme as an example, we could construct a generic four-zone step distance test plan of the functions (reclosing, loss of potential, etc.); protection elements (21P, 21G, 50/51, 59, etc.); interfaces (physical I/O, control, etc.); and logic (permissive overreach transfer trip {POTT} and breaker failure, etc.) that should be tested and should include the test equipment, tolerances, and test methods stated in our test specification. At this point, the test plan could be used as a functional test specification (Figure 2) for this type PAC device or system because the What, Why, and How questions should now be known.

Today, many utilities have lost expertise and cannot follow these steps; they increasingly rely on other sources to bridge these gaps. With modern software solutions, the specific IED can be data modeled and parameters imported, then recalculations made and mapped to the functional test module performing the specific defined testing task, including the required hardware interfaces (Figure 3). Additionally, modern test software can use purpose-built test modules or a power system mathematical model to relieve the task of defining individual test methods for each function, element, or logic scheme. Since the beginning of my career and regardless of the protection devices/systems and technology used, there has never been a perfect tool for creating such test plans. The fact is that it requires a deep knowledge and understanding of what it is you are testing. Whether it is an auxiliary dc relay or a modern HV digital line protection IED, or an application like a permissive overreach transfer trip scheme over fiber, understanding what it is designed to do and how it does it is necessary for organizing any of the previous testing tasks successfully.

Fig. 2: Test Specifications However, we still do not have an executable test plan because we are missing the specific manufacturer device(s) used, the specific configuration parameters, and the specific protection settings that finally dictate the exact testing to be performed. For instance, the specific line being protected may not require a fourth-zone element, so the configuration information would indicate it is not used or required. This would mean only three-zone elements need to be tested, and any scheme, function, or logic associated with only the fourth zone would be ignored. So a mechanism to get these configuration parameters/protection settings into the generic test plan was needed, as these were typically entered manually. (Today, of course, they are possibly imported electronically.) Often, the parameters used in a specific PAC device vary from manufacturer to manufacturer, even when they perform identical functionality. Further, the actual parameters used to define the test method can be a different data type or mathematical equivalent. So translation of these specific device parameters into test-method parameters was another task necessary to create the executable test plan.

Fig. 3: The Hardware Setting Parameters Some may disagree, citing that a good generic test specification can be written from a common denominator (generic) practice, an approach that in turn can generate the required test plan. But I see this as a chicken-and-the-egg discussion or Schrodinger’s cat situation: If you do not know the actual device details, how can you possibly test it? Even in the case of the simplest network model, you must understand how it works, its limitations, and the data it requires to function correctly. However, there is no argument in the industry that device technology dictates the test tools and techniques required and that the objective is the proof of the device as applied in situ. So taking the device out of its commissioned state to make functional or element tests indicates lack of good specifications and systems engineering. A properly engineered IED or PAC system will be testable with the correct tools and simulations. The fact is, there is nothing to test until there is a device or system design, and no design until there is a specification to build it a certain way. So we are back to the specification

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Protective Relay Vol. 2 again. Naturally, one would conclude that whatever this specification is, it should then be used to define the test plan. If we are talking design absolutes like the strength of an I-beam made from different materials, then yes, it could be. For instance, a 10-foot-long oak I-beam may have a design-loading factor of 100 pounds, whereas one made from cold steel might be 1,000 pounds. To prove the design, a simple test would anchor one end of the beam and apply an increasing dead load at the other end until the beam failed. This would be destructive, but necessary to prove the design and specification, and many industries perform these tests.

This methodology could be seen as backwards but for one key point: With the knowledge of the application and the specific parameters of the configured devices, we are able to define a whitebox testing environment, one in which we know the output based on the internal responses of the system based components/devices from known application-based input simulations. In other words, we have a detailed understanding of the devices and system, and therefore, can prepare a proper test plan to prove it. (Figure 5)

In PAC systems, we do not typically test them until they fail (we let Murphy take care of that), but we do need to apply best practices in verifying their design and operation prior to implementation and during service life. The other consideration for PAC systems and their devices is the variable nature of designing/applying them. Most of today’s devices are digital, use communications, and are programmable in configuration and scheme logic, making their testing dependent on their intended application and the specific parameters used (Figure 4 below). The device specification cannot be used directly for defining the test plan because there are too many variables, overlapping functions, and implementations unique to the manufacturer. Further, when we take multiple devices and use them together in PAC systems, the aggregate specifications of all those devices could create conflicting test requirements across the system and, in some cases, damage them if not properly considered. The specific settings/parameters applied based on the intended application restricts them and blends these devices to work together within the PAC system. This provides the details necessary for developing the test plan. Once the test plan is derived according to our required task list and proven against the PAC system configuration, then it can be the basis for extracting the test specification for this specific PAC system implementation.

Fig. 5: IED Test Results — Distance Zone Elements

Fig. 4: IED Test Plans Adapting to Actual Settings and Creating Specific Functional Tests

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DEVELOPMENT METHODOLOGY — TEST SPECIFICATION The multifunctional design of modern numerical protection devices usually requires different methods to test the different functions integrated in each of them. It is obvious that to define the test specification, we need to start with the type of protection being tested. As mentioned, the test specification depends on the user’s testing philosophy and the regulator’s compliance requirements. It defines what types of tests need to be performed for different types of function elements, schemes, or applications as well as any characteristics of the test method used depending on the purpose of the test: type, acceptance, commissioning, maintenance, etc. (Figure 6).

Fig. 7: Completed IED-Specific Test Plan The test specifications must define: Fig. 6: IED Zone Characteristic Test Results Based on the testing philosophy, a generic test plan can be structured that defines the required test hardware and specific implementation considerations based on the PAC device or protection IED dependent: ●● Interfaces: hardwired voltage, current, I/O or IEC 61850 GOOSE, or sampled values ●● Bay configuration (for example, breaker-and-a-half) or application configuration (two-ended line model) Once the generic test specification for a protection type is created as a generic test plan, it can be customized to meet the specific functionality of a selected manufacturer’s IED used for the protection type under consideration and represented then by an IED-specific test plan (Figure 7).

●● The functionality of the tested multifunctional protection IED represented by different protection function elements, such as distance, differential, overcurrent, etc. ●● The required test devices needed to execute the tests ●● The interfaces between the test equipment and the test object ●● The test modules (methods) to be executed as required by the testing philosophy Such an approach allows improvement of the testing process efficiency by defining the required hardware configuration only once at the beginning of the test specification. The hardware configuration represents the signal path between the testing tool and the test object and contains complete information about: ●● The assignments between the inputs and outputs of the test software and the test object terminals ●● The used test hardware as well as its configuration ●● The wiring between the test hardware and the test object terminals

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Protective Relay Vol. 2 The setting parameters of the test object are also not specified individually for each test module, but only once at the beginning of the executable test plan configuration (Figure 8). The same applies to the generation of a single test report that covers all test results. Any number and type of test modules can be combined into one central document to form a complete test plan that matches the requirements of the functions tested.

that differ only in their parameter settings (e.g. relays of the same type on different feeders) is substantially simplified since a test plan, once created, only needs minor adjustments. The fundamental difference between a test plan and a test specification is that a test plan not only tells us how to perform the test, but it also has knowledge of what the test results should be. A generalized test specification cannot contain the specific expected results, only relative parameters like tolerances. When describing to a technician, contractor, or test company via a test specification, the information must be as specific as possible and derived by extracting that specification from successful test plans. If an independent way existed to describe all the devices, interfaces, communications, logic, and settings used in PAC systems, then our industry could evolve engineering tools to define its many unique applications in a standardized way. In fact, it would be possible to not only self-describe the PAC system as designed, but also provide a mechanism to self-define its test plan based on those defined relationships. You guessed it: That’s IEC 61850. Although long-coming, IEC 61850 (Ed 2) is approaching a new level of maturity. In Part 6, the Substation Configuration Language (SCL) has grown to encompass more information on PAC devices. This substantially increases the self-description details where the key data and relationships of the configured devices from the SCL can be used. If combining application/test tool knowledge with the existing SCL data, test plans could be defined directly. Expansion of the SCL to include test devices described as logical nodes with data objects and data attributes would enable the goal of creating test plans and test specifications.

Fig. 8: IED Functional Model with Specific Configuration and Settings The test plan can be executed as an automatic sequence. When running it, the defined test functions of each selected module are executed before the program automatically switches to the next one, until all the modules have been completed. After the completion of the test, the software enters the results into the test plan document, which creates a comprehensive overall test report. The test report still contains all of the test settings (protection device parameters, test modules used, test points, etc.). Using a protection IED-specific test specification for testing several relays

A utility using the IEC 61850 data model can define the single line diagram, all functions used, and their logical nodes/data types. From this, a device-independent specification can be made using the System Specification Description (SSD) file with a top-down design that will constrain vendors and system integrators to the utility’s system specification. This means the supplier is not free to make a non-conformant, bottom-up design using their own tags and architecture. Further, with test tool/device extensions of the SCL, the utility could also include the test plan from the SSD with all test processes defined (what to test with expected values) and then easily formalize a conformant test specification from it (an annotated report).

CONCLUSIONS The ability to create a properly constrained test specification that has value has always been a challenge, but IEC 61850 is poised to deliver on a long-awaited capability — creating a test specification from the top down that includes the functional test plan, too. The best specification is one that: ●● Exists ●● Describes what, not how ●● Cites relevant industry standards

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●● Clearly defines testing tasks such as acceptance, commissioning, routine, and maintenance ●● Has only one interpretation ●● Is available to all parties ●● Is the spec agreed to by all parties involved ●● Only includes what is necessary ●● Is consistent (avoid using “it” or “which” and clearly specify “what”) ●● Defines the jargon and abbreviations common within the industry ●● Describes the test objectives so a novice can understand them ●● Is updated regularly as requirements change with maintainable title, control number, and revision history The best test plan is one that does all the above and: ●● Adapts to the device or system, using their parameters ●● Defines the test kit used and required interfaces ●● Does not compromise the device’s commissioned integrity ●● Adapts the test listed parameters

methods

based

on

the

previously

●● Defines tolerances of the object’s performance ●● Automatically assesses test results ●● Distinguishes maintenance from calibration conditions and circumstances ●● Describes test objectives so a novice can understand them ●● Executes clearly

REFERENCES Apostolov, Alexander, “Functional Testing of System Integrity Protection Schemes,” PAC World, March 2014. Bastigkeit, Boris, Thomas Schossig, and Fred Steinhauser. “Efficient Testing of Modern Protection IEDs,” PAC World, Winter 2009. Reuter, Jorg, “Device Independent Specification of a PAC System,” PAC World, December 2014. Vandiver, Benton, “Why Do We Still Test in the Digital World?” PAC World, September 2014. Benton Vandiver III received BSEE from the University of Houston in 1979. He began his career with the Substation Division of Houston Lighting & Power, in 1978 engineering relay protection systems for all levels of transmission, distribution, and generation. His main interests were in computer design automation of protection schemes and substation projects. He developed extensive knowledge in the application, setting, testing, modeling, and design of traditional and digital relaying systems used in all types of power system protection, control,

and monitoring. In 1991 he joined Multilin Corp. as a Project Manager on a team responsible for designing and developing the hardware and software for a new family of utility grade digital relays. In 1995 he joined OMICRON electronics as a Sales & Application Engineer with primary responsibilities of sale, training, and promotion of the revolutionary CMC Universal Test Set to North & South America. He is currently Technical Director for OMICRON electronics Corp. USA in Houston, TX. He is a long time member of IEEE and is Chairman of Working Group H5-C Common Data Format for IED Sampled Data. He holds a US Patent and has authored or co-authored numerous technical papers for various conferences in North America.

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UNITED STATES

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

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arizona

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

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ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

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ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

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ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

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ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

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Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

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Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

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Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

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Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

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Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

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Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

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Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

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Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

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Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

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Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

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Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

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RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

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Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

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Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

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RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

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CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

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CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

58

florida 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

missouri 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

151

152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

157

158

159

160

161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

182

183

184

185

186

187

188

189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

197

198

199

200

201

POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

206

207

208

209

210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

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CANADA

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Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

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Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

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Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

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Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

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CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

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VOLUME 1

SAFETY

SERIES III

HANDBOOK

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SAFETY VOL. 1 HANDBOOK TABLE OF CONTENTS Service Entrance Switchboards: Design Considerations to Enhance Safety and Reliability ....................................... 7 Robert P. Hansen, P.E., PhD

Electrical Safety: A New Paradigm ................................................................... 11 David I. Windley

Electrical Safety Through Design, Installation, and Maintenance ........................... 16 Dennis K. Neitzel

Electrical Safety Myths, Legends and Misconceptions .......................................... 23 James R. White

Industrial Electrical Safety Compliance Assessments ............................................ 28 Dennis Neitzel

Developing an “Electrical” Multi-Employer Worksite Protection Program ................. 34 Don Brown

Personal Protective Grounding ......................................................................... 37 Jeff Jowett

Human Error and Safety .................................................................................. 40 Paul Chamberlain

Power Transformer Hazard Awareness .............................................................. 42 Scott Blizard

Understanding and Implementing the ANSI/NETA ECS-2015 ............................... 46 Lorne Gara and Ron Widup

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InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

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Pre-Job Briefings; An Indispensable Safety Tool ................................................... 51 Paul Chamberlain

First Rule of Troubleshooting; Trust, but Verify ..................................................... 53 Don Genutis

Distracted Driving ........................................................................................... 54 Paul Chamberlain

Test Equipment: Managing the Hidden Defects ................................................... 56 Ashley Harkness

Beliefs Drive Behaviors .................................................................................... 58 Daryld Ray Crow and Danny P. Liggett

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InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

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Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

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7

Safety Vol. 1

SERVICE ENTRANCE SWITCHBOARDS DESIGN CONSIDERATIONS TO ENHANCE SAFETY AND RELIABILITY NETA World, Winter 2013 Issue Robert P. Hansen, P.E., PhD, GE Specification Engineer

INTRODUCTION Switchboards are a widely used type of equipment in low voltage electrical distribution systems. They are typically used as the service entrance equipment for a variety of facility types. While consideration of safety and reliability must be given to all parts of an electrical distribution system design, the impact of choosing the correct design options to enhance safety and reliability is magnified at a service entrance. This article will discuss simple switchboard configuration and equipment options that, when incorporated in the design phase of a project, can cost-effectively reduce arc flash incident energy or reduce worker exposure to arc flash energy without reducing reliability. The scope of NPFA 70E (reference 1) does not include design of distribution systems, but it does contain references to design practices and equipment options aimed at reducing arc flash energy or worker exposure.

Article 130 – Work Involving Electrical Hazards 130.5 Arc Flash Hazard Analysis, informational note #3: “... Equipment and design practices are available to minimize the energy levels and the number of at-risk procedures that require an employee to be exposed to high energy sources.”

Informative Annex O – Safety Related Design Requirements O.1.2 “… The facility owner or manager, or the employer, should choose design options that eliminate or reduce exposure risks and enhance the effectiveness of safety related work practices.” O.2.3 Arc Energy Reduction. “Where a circuit breaker that is rated for, or can be adjusted to, 1000 amperes or more is used, one of the following or equivalent means has proven to be effective in reducing arc flash energy:

to set the circuit breaker back to a normal setting after the potentially hazardous work is complete.” This article will describe some of the design practices and options that can be applied to commonly used non-compartmented, service entrance switchboards. The application of zone selective interlocking (ZSI), including the newer instantaneous ZSI, and maintenance switching will be among the specific strategies discussed.

BACKGROUND In the one-line below (figure 1), a utility, or end-user owned, transformer is connected to a service entrance switchboard. The switchboard has a main breaker, and any number of group or individually mounted feeder breakers. The overcurrent protective device (OCPD) that is upstream of the transformer would typically be a fused switch or a MV breaker. The protection settings (in the case of the MV breaker), or fixed time-current characteristics (in the case of the MV fuse) determine how quickly an arcing fault will be cleared on the transformer secondary side down to the LV main device terminals. For a given system, that upstream device clearing time will determine the arc flash energy on the line-side of the LV main breaker. The LV main breaker protection settings are typically chosen to protect the bus on its load side, and back-up the protection afforded by the feeder breakers to parts of the system below the switchboard. The LV main breaker settings will determine how quickly a load-side arcing fault will be cleared, which in turn influences the amount of arc flash energy on the load-side bus. In many cases, the low voltage main device line-side and load-side arc flash energies are of different values, in some cases by a large amount, with the line-side energy being the higher of the two.

● Zone-selective interlocking ● Differential relaying ● Energy-reducing maintenance switching with a local status indicator An energy-reducing maintenance switch allows a worker to set a circuit breaker trip unit to operate faster while the worker is working within an arc flash boundary, as defined in NFPA 70E, and then

Fig. 1: Typical service entrance

8 As an example, on a 480V service entrance fed by a 2000kVA transformer with standard impedance, the LV main breaker can limit incident energy to below 4 cal/cm2 when the LV main breaker is allowed to clear arcing faults using its instantaneous response1. The incident energy on the LV main breaker line-side would be over 130 cal/cm2, and have a corresponding arc flash boundary of 36 feet when the transformer primary is protected by a fuse. For non-compartmented switchboards, the highest incident energy calculated anywhere within the switchboard would typically be reflected on the arc flash labels for all sections in that continuous line-up. This can render the entire switchboard unapproachable while it is energized. A complete approach for safe design will attempt to minimize both the line-side and load-side arc flash energies. In cases where the owner of the service entrance switchboard owns the transformer and decides what primary protection to apply, protection strategies as explained in reference 2 can be used to reduce the line-side arc flash energy. In all other cases where the service entrance switchboard owner may not have authority to select the substation transformer primary protection device/settings, the strategy of placing the low voltage main section remote from the feeder sections, as discussed in the next section, can be used to reduce worker exposure to the higher line-side arc flash energy. Independent of the substation transformer primary protection ownership, the equipment options (ZSI and maintenance switching) discussed in the following section can be used to enhance safety for workers. In the case of a service entrance switchboard with no main device (a “six handle rule” service entrance per NEC Article 230.71), the distinction between line-side and load-side arc flash energy as described above is lost. The low voltage arcing fault clearing time of the protective device upstream of the transformer will determine the amount of arc flash energy for the entire service entrance bus. For service entrance switchboards without main devices, the protection techniques needed to minimize arc flash energy at the low voltage service entrance bus are beyond the scope of this article. References 2 and 3 describe some of the options that could be used. In a conventional switchboard service entrance design, the main breaker and the feeder breakers are connected by hard bus such that the main section is in a continuous line-up with the feeder section(s). While this is convenient from the perspective of installation, it does have disadvantages when the arc flash energy at the line-side of the main breaker is greater than the load-side arc flash energy. High line-side arc flash energy can increase risks to workers interacting with other parts of the switchboard that are not part of the incoming section. The arc flash boundary for sufficiently high line-side arc flash energy can easily extend past the feeder sections. Main circuit breaker trip unit settings or temporary settings, such as used by a maintenance switch, only influence the load-side. The elevated line-side energy potentially increases the frequency and duration of exposure for personnel who interact

Safety Vol. 1 only with feeder sections. In the conventional configuration there is greater impetus to employ line-side energy reduction methods. The following section will discuss some options for improving upon the conventional switchboard design.

OPTIONS FOR IMPROVING THE CONVENTIONAL DESIGN Remote Main Breaker Section Many users now recognize the simplicity and effectiveness of employing a switchboard with a remote main circuit breaker section. In this design strategy, the section that receives the incoming feed from the utility transformer contains only the main circuit breaker, and this single breaker section is cabled to a separate lineup containing the feeder breakers. The concept is to provide distance between the higher arc flash energy normally found on the line-side of the low voltage main device and the sections on the load-side. With sufficient distance between the main section and the feeder sections, the feeder breaker sections can be outside of the main section’s line-side arc flash boundary. This reduces the risk to personnel who interact with the feeder sections, when the main breaker is appropriately set to clear arcing fault currents, and allows workers within the arc flash boundary of the feeder sections to wear personal protective equipment (PPE) appropriate for the incident energy at that location. When interacting with the remote main breaker section, the appropriate PPE for the higher line-side incident energy is still required. A remote main breaker section can also be used in a retrofit situation. For an existing switchboard using a conventional layout with a main device, a new main breaker section can be inserted between the transformer secondary and the existing main. The protection settings of the new main breaker will determine the amount of arc flash energy at switchboard sections of the original conventional line-up. A service entrance with a main-lug-only switchboard (“six handle rule”) can be converted to a single disconnect service entrance by adding a remote main section. For new construction or retrofit situations, using a circuit breaker in the remote main section helps the owner to take advantage of maintenance switching and zone selective interlocking (with circuit breaker feeders). Electrical operation of the main breaker with remote control is also an option to reduce exposure of personnel to arc flash energy. Line-side arc flash energy reduction methods can be applied to the remote main section to further enhance safety for anyone interacting with the incoming section. Even if no personnel interact with the remote main section while it is energized, line-side arc flash energy reduction can be desirable to help protect the equipment.

Maintenance Switching A maintenance switch controls a temporary protection setting on a circuit breaker electronic trip unit and can provide benefits

Safety Vol. 1 for any switchboard configuration. The temporary setting can be enabled to reduce the archyphenate-flash energy of an arcing fault on the LV bus downstream of the breaker that has the maintenance switch function. A maintenance switch is typically enabled when an operator has to perform a task inside of the arc-flash boundary. When the task is complete, the switch is set back to its default position which turns off the temporary protection setting. The temporary setting is a second instantaneous pick-up setting that must be pre-selected by the user. An arc-flash study would determine the appropriate pick-up level for the maintenance setting. Because the maintenance setting should be set to a lower instantaneous pick-up relative to the normal instantaneous setting, coordination is generally reduced while the maintenance setting is enabled. The local status indicator (or optional remote status indicator) provides visual confirmation (usually in the form of a light) of the maintenance setting state. Maintenance switching can be used on the main breaker in the conventional or remote main switchboard layouts. Maintenance settings can also be used on feeder breakers to improve protection on other downstream switchboards, motor control centers, or panelboards. The switch can be provided on the face of the switchboard section, or wired to a location outside of the arc-flash boundary. On trip units that communicate with monitoring and control software, the maintenance setting may also be enabled or disabled over the network. The amount of incident energy reduction that is achieved by using a maintenance mode is dependent on the particular system and on the breaker protection settings before the maintenance mode is enabled. A maintenance switch can be provided with new equipment or retrofit to existing equipment with a trip unit upgrade.

Zone-Selective Interlocking General Zone-selective interlocking (ZSI) is available as an optional feature on selected electronic trip units in specific breakers. For arc-flash safety, the two forms of low voltage ZSI of primary interest are short-time ZSI and instantaneous ZSI. Each form may be used individually, or concurrently with each other. Both forms of ZSI are a specialized protection scheme between two breakers in series, such as a main and a feeder. Multiple feeders may be in a ZSI scheme with one main. The ZSI scheme may also be extended to main-tie-main configurations. Similar to the maintenance switch, ZSI can be provided in new equipment or in a retrofit to existing equipment. The safety benefit of a ZSI scheme is its potential to reduce arc flash energy on the system between the upstream and downstream breakers in the scheme. An arc flash study is needed to determine the appropriate protection settings to achieve the maximum benefit from the scheme. While maintenance switching is designed as a temporary arc flash energy reduction method (applied at specific times when operators interact with the equipment), ZSI is intended

9 to be active continuously. The details of any ZSI implementation will be specific to the particular vendor and the particular generation of equipment. In the context of a switchboard, a ZSI scheme created between the main breaker and feeder breakers will allow lower pick-ups (and delays in the case of short-time ZSI) to be set on the main breaker without loss of selectivity. If the feeder breaker senses a fault within the pick-up range of the ZSI scheme, a signal informs the main breaker and it will adjust its protection response, allowing the downstream breaker to clear the fault first and preserve selective coordination in the range of fault current where the ZSI is employed. The arc flash energy reduction potential of ZSI is derived from the lower settings (relative to traditional nesting techniques) that can be used on the main breaker. These lower settings allow for the main breaker to respond quicker to arcing faults on the switchboard bus. Short-time ZSI While the NFPA-70E reference to ZSI does not differentiate between short-time and instantaneous ZSI, there are important differences. A trip unit on the upstream breaker with short-time ZSI will use two short-time delay bands that are set by the user. One of these bands is the normal short-time delay band called the unrestrained position. The second short-time band, called the restrained position, is a longer delay band that does not overlap the unrestrained band. If the downstream breaker senses a fault within the range of the short-time pick-up, it sends a signal that switches the short-time delay band of the upstream breaker to the restrained position. When applied to a main and a feeder, this allows the main breaker unrestrained short-time delay to be set at a low band without loss of coordination. This can facilitate a lower arc flash energy for arcing faults on the switchboard bus, compared to using coordinated short-time settings without ZSI. The amount of arc flash energy reduction possible is, in part, limited by the intentional time delay in the unrestrained short-time delay band. While the short-time ZSI can enhance protection without affecting the short-time coordination, it has no effect on any lack of selective coordination that may exist in the instantaneous range. Disabling the instantaneous response of the main breaker is not an option for switchboards that do not have a 30-cycle withstand rating. Thus, using short-time ZSI by itself in a typical switchboard still leaves the designer with the issue of how to coordinate the main and feeder breakers in the instantaneous region. Instantaneous ZSI Instantaneous ZSI coordinates the instantaneous response of the breakers in the ZSI scheme. The upstream breaker in an instantaneous ZSI scheme uses its normal (unrestrained) instantaneous protection setting (without intentional delay) when there are no faults on the system or a fault occurs in the zone between the breakers in the ZSI scheme. The upstream breaker response moves from instantaneous to a fixed short-time delay band (restrained position) only if the downstream breaker senses a fault in the instantaneous range of pick-up. The restrained position of

10 the upstream breaker gives the downstream breaker time to clear a fault before the upstream breaker commits to tripping. In this way, instantaneous ZSI provides for improved safety by helping the main breaker to clear a fault on the main bus at its instantaneous clearing speed, while improving instantaneous coordination with feeder breakers by shifting the main breaker response if the fault is below the feeder. As described above, a ZSI scheme manages the delays used by the upstream breaker. In the case of instantaneous ZSI, the instantaneous response of the upstream breaker moves from no delay to a delay when the downstream breaker also senses the fault. In the case of short-time ZSI, the upstream breaker response moves from one delay band to a longer delay band when the downstream breaker also senses the fault. In the traditional implementation of ZSI, the instantaneous and short-time pick-ups of the upstream breaker would normally be set above the corresponding pick-ups of the downstream breakers in the scheme to maintain selectivity (the pick-ups would be nested). This nesting of pick-ups forces the upstream breaker to be less sensitive to dangerous arcing currents. A recent new development in ZSI permits the nominal pickup settings of the upstream breaker to be set to the same value as the downstream breaker without loss of selectivity (reference 4). In the context of a service entrance switchboard, this means the pick-ups (short-time, instantaneous, or both) of the main breaker can overlap the corresponding pick-ups of the downstream breaker where ZSI is enabled. In most systems, this will help the main breaker instantaneous to be set low enough to clear load-side arcing faults predicted by an arc flash study in the shortest amount of time possible for that main breaker. For a given system, clearing an arcing fault on instantaneous results in lower arc flash energy compared to clearing using short-time. The most comprehensive application of ZSI would use short-time and instantaneous ZSI simultaneously. Additional information about instantaneous ZSI, including application examples, may be found in references 4 and 5.

SUMMARY Each of the design options discussed can be considered as a discrete layer of improvement to the conventional switchboard design. The options can be applied individually or combined in various ways to best meet the needs of a particular situation. This article has elaborated on just a few of the design choices and equipment options that can be used to enhance the safety and reliability of service entrance switchboards. Options such as drawout mounting with remote racking, remote breaker operation, and remote monitoring should also be considered. While service entrance switchboards have been the focus of the article, the strategies discussed here can also be applied to non-service entrance switchboards to improve safety and reliability.

Safety Vol. 1 REFERENCES 1. National Fire Protection Association, NFPA-70E, Standard for Electrical Safety in the Workplace, 2012 Edition. 2. Maurice D’Mello, “Arc Flash Hazard Reduction on Incoming Terminals of LV Equipment”, IEEE PCIC 2014, San Francisco, CA, to be published September 2014. 3. Clapper, M., “GE Arc Vault Protection System”, GE White Paper, http://www.geindustrial.com/publibrary/checkout/ArcAbsorber?TNR=White%20Papers|ArcAbsorber|generic. 4. Valdes, M., Dougherty, J., “Advances in Protective Device Iterlocking for Improved Protection and Selectivity”, IEEE PCIC 2013-30, September 2013. 5. Wright, B., D’Mello, M., Cuculic, R., “Zone Selective Interlocking On Instantaneous (I-ZSI) and Waveform Recognition (WFR)”, GE White Paper, http://www.geindustrial.com/ publibrary/checkout/IZSI-WFR?TNR=White%20Papers|IZSI-WFR|generic Robert Hansen is a Specification Engineer for GE’s Industrial Solutions business, working in Overland Park, Kan. He has been in this role since 2007 and provides application and technical support for engineers designing commercial and industrial power distribution systems throughout his area of responsibility which includes Kansas, Missouri, Oklahoma, and parts of Arkansas and Illinois. Robert has more than 30 years of design experience and 26 years active military service which includes teaching undergraduate engineering for six years at the United States Military Academy. Robert graduated from the United States Military Academy, West Point, N.Y. in 1981 with a Bachelor of Science degree, and also graduated from the Pennsylvania State University with an Master of Science degree in aerospace engineering (1992) and a PhD in mechanical engineering (2001). His academic work was heavily focused on numerical simulation using high performance computers. He is an IEEE member and a licensed professional engineer (P.E.).

11

Safety Vol. 1

ELECTRICAL SAFETY: A NEW PARADIGM PowerTest 2013 David I. Windley, P.Eng., WINTEK Engineering Limited

ABSTRACT This paper will briefly cover the state of the industry with regard to electrical safety practices from design to testing, maintenance, and operations and demonstrate that out thinking needs to be changed and directed toward new ways of addressing traditional electrical safety challenges. A new paradigm is required in the best practices of electrical power and control system design, commissioning, maintenance, operation, and management so that work on energized equipment can be eliminated or reduced to a level where exposure is minimised. Faced with the fact that this work is sometimes necessary, new methods, equipment, and procedures need to be developed and put in place to enable those doing the work to proceed confidently and safely. This paper will endeavour to outline the opportunities and potential strategies to evolving to a new paradigm.

DEFINITION: par·a·digm /ˈparəˌdīm/ Noun: A typical example or pattern of something; a model. A worldview underlying the theories and methodology of a particular scientific subject.

Introduction Testing, troubleshooting, and commissioning activities provide the highest risk for workers as these tasks imply partially complete or non-functioning systems. These conditions require exposure to elevated voltages and high energy equipment which could result in electrocution or serious life threatening burn injuries. Everyone is encouraged to work safely when it comes to energized electrics but sometimes it is not possible to perform the required tasks without exposure. However, we need to innovate and establish a new paradigm of design which will minimise exposure and to develop new testing and troubleshooting techniques which will minimise injury should an unexpected event were to occur. There needs to be a “discovery” of the real issues affecting worker safety and a paradigm shift in attitude and due diligence to embrace safer design and methods of working.

General State of the Industry So what are we talking about? The business of design, operation, and maintenance of power and control systems has been with us a long time. Not much has changed. Organizations like NEC, NFPA, and IEEE among others have developed numerous

standards, codes, and guidelines to enable us to produce optimum designs incorporating best practices for safe and reliable power systems. Primarily, this has been to protect equipment and systems from being damaged and causing fires, explosions, and other catastrophes which could directly or indirectly injure people or destroy property. We have taken comfort in the fact that our electrical systems are enclosed in boxes or fences to keep unauthorized people out and away from electrical shock or blast. We have also assumed that people will not purposely expose themselves to live voltages and that the equipment will function and can be operated and maintained without any live interaction. The fallacy of this, of course, is that the equipment doesn’t always work the way it was intended and that some level of intimacy with live conductors and parts is required to effect troubleshooting and in some cases on-line repairs. It also doesn’t consider the fact the equipment will be incomplete during construction and that all the designed safety provisions may not be in place. It is not fair or practical to say that equipment shall not be energized on entry unless special provisions have been made to perform the required duties in some other way. Organizations like NETA have given us ways and means to test and evaluate electrical systems. Again, the focus of this is to keep our power systems healthy and functional. Manufacturers are continually developing new and more intuitive methods and test devices to quantitatively determine the state of the electrical equipment. Safety is a factor in the design as it is necessary in almost every case to be intimate with the equipment during this testing. But the ultimate responsibility is with the user and it is imperative that a trained individual is performing the testing and that all procedures and necessary isolations are in force. So given all this, we have systems out there which have followed the best of design intentions at the time, but when we take a closer look, fall short when applied to the potential hazards. We also have systems which are in a poor state of maintenance and have been subjected to operating conditions which will eventually lead to failure. We are also the victims of traps set by poor design and inexperienced designers. A 10 year study by the Electrical Safety Authority in Ontario (2009 Ontario Electrical Safety Report by ESA) has concluded that almost 75% of the fatalities due to electrocution were primarily due to failure to follow procedures and to human error. This shows we have some work to do in developing procedures that can and will be followed and also ensuring that workers are trained and alert when approaching live work.

12 Design Considerations The design of power systems has been studied, analyzed, and practiced for many years. We have always had sense of electrical safety but we generally felt that those doing the work would do it in a safe fashion. Today, even following the best design practices and all the rules we find that unsafe situations evolve and continue to be created. So what has changed? As seasoned architects of electrical power systems and equipment, we still hold the values and beliefs of bygone days. However, as the gauntlet is passed, there is more emphasis on reducing cost and shortening schedules than solid design practices and avoiding serious mistakes. The younger engineers aren’t held in the same high regard as the old experts and they are challenged to do things faster, cheaper, and with fewer adherences to recognized standards. You can see the degradation everywhere you look. The theory at educational institutions doesn’t replace the years of hands-on experience and the advice and guidance of valued mentors. We have evolved to an “electronics and computers can do everything” attitude and now with a smaller number of talented power engineers, the design of power systems is not treated in the same regard as before. Chances are taken and injuries occur. On a positive note, we have got smarter and more risk-avoidant these days with the adoption of new design practices which consider equipment access under live conditions. We are starting to better understand the risks taken by those who work on the equipment. We need to make sure the word is spread regarding the new approach to electrical safety. I have outlined some of the opportunities for design excellence. ● Arc Flash – This new consideration of a well-known hazard will have profound effects on design. There is very little in the Codes and Standards which relate to this potential danger. The reason for this is that it doesn’t relate so much to the equipment and installation, but more to maintenance and operation. Hence, a perfectly acceptable power design may be deficient with respect to arc flash exposure and incident energy levels. As electrical equipment is designed for three phase bolted fault levels, and that the arc flash current is rarely of the same magnitude, we can be fairly confident that an arc fault will not be an issue with equipment damage. However, knowing there may be access required under energized conditions in order to troubleshoot or repair, we cannot ignore the potential energy levels and the injuries that could occur. It is therefore necessary that design engineers consider access and incident energy levels in their design and adjust if appropriate. ● Protective Coordination – Traditional protective coordination sets the power system protection to act in a predictable and logical way to isolate a system fault quickly but to minimise the effect to other areas of the facility. This may cause upstream devices to allow a high level of incident ener-

Safety Vol. 1 gy which increases the arc flash hazard at this location. This can force a contradiction between protective coordination and worker safety and therefore requires an experienced power engineer to analyze and choose the correct settings for the particular installation. Sometimes optical devices responding to “flash” can speed response time or “maintenance” selections programmed into protective devices. ● Transformer Secondary Protection – It has been accepted by most codes that a secondary protective device is not required as long as the primary device provides the necessary protection. Most experienced power engineers will design the power system with this protection anyway because it allows a convenient isolation point for maintenance and helps avoid operating a primary device which may be more difficult to get at. However, cost is many times the factor in not installing these secondary devices. The end result of this is, that almost always, the transformer secondary and associated switchgear is a high arc flash hazard because the primary device is too slow in interrupting the arc flash current. ● Switchgear Design – Over the years we have evolved from metal enclosed technologies to relatively open design and buses. Now we are forced to consider live access to the line side of protective devices forcing us to re-consider the more robust designs which have been long since abandoned. Service entrance type equipment effectively barriers off the line side of the protective device on switchgear and effectively isolates it. Using this same philosophy, it allows safer access to feeder breakers in all areas of the plant. Another consideration is testing. Can I test the cable in a redundant system safely while it is running? If I can’t, then what is the point? Is there a possibility of test voltages flashing to live equipment? ● Arc Resistant Switchgear – Switchgear is designed to handle the large forces which occur in a three-phase bolted fault. However, directing the blast away from the front of the switchgear where someone would be standing is an effective way to prevent injury in the unlikely event a fault will occur and compromise the enclosure. There are still many facilities, mostly industrial, where the main distribution boards are out in the open. The new way will insist on large and medium sized distribution boards in controlled access rooms. ● Instrumentation – Very few switchboards are installed today which allow the plant electrician to verify voltage, current, power flow, and other variables which aid in the maintenance and troubleshooting of the power system. To perform these duties requires expensive portable equipment and connection to live circuits. New switchboards should be designed with the ability to perform load monitoring voltage detection, power quality and harmonics studies without exposure. This equipment is much easier to implement and is cost-effective at the design stage.

Safety Vol. 1 ● New Installations and Control of Change – There are many times when a new line or distribution panel is installed and because it is a simple change, a qualified design engineer is not consulted. With the more complex arc flash design criteria, it is easy to install a trap for an unwitting operator or plant electrician. These traps are caused by poor design or by inexperienced designers or contractors not knowing all the design considerations. A review of all power system changes must be undertaken by competent designer engineers to ensure that all relevant factors are considered in the change. ● Fuses vs. Circuit Breakers – The choice of the most appropriate protective device for an application isn’t quite as simple as it used to be. Proponents of either side will argue the advantages and disadvantages of each. The point is, speed is important when it comes to incident energy and arc flash potential. Sometimes a fuse will respond faster than a circuit breaker, sometimes not. It takes an evaluation by an engineer to determine the appropriate device for the specific application. The openness of a fusible disconnect during fuse checking and replacing can also expose personnel to line side energies of a magnitude much higher than with resetting a circuit breaker where the bus is effectively isolated. ● Isolation of Controls – We have come full circle. Many original designs would separate high voltage from lower voltage controls. With the popularity of PLC and computer based control systems, more access is required for programming and troubleshooting. Yet, many controls are now installed within inches of high voltage motor starters or wiring. Many multi-starter panels are being built which don’t allow the isolation afforded by modular motor control centres. The design engineer must be thinking about what access is required after the fact. For instance; ○ How do I check for voltage? ○ How do I isolate a motor? ○ How do I reset an overload? ○ How do I check or change a fuse or reset a circuit breaker? ○ How do I read diagnostic information? ○ How do I program or configure a drive? ○ How do I diagnose or make changes to a PLC program? There are many options for dealing with the above to remove the need for opening the cabinet. Some of these include: ○ Complete isolation of controls from power (separate cabinets). ○ HMIs, indicators, or instruments for diagnostics. ○ A PLC connection port is a means for accessing the controls. ○ Plunger type or electronic overload resets.

13 In any case, care must be taken, safe procedures developed, and qualified individuals assigned to these tasks to reduce the risk.

Equipment Testing and Commissioning Considerations Electrical testing and commissioning is a high hazard task and not well understood by anyone not associated with the industry. It is easy to discount the necessary requirements to do the job safely. Although unpopular, maybe de-energizing to perform testing or commissioning is the best option. ● Test Equipment – As with any other high hazard task, it is imperative to have the right equipment and trained individuals that know how to use it safely. The manufacturers have developed more sophisticated and intuitive equipment over the years to be able to give the service professional the best window on electrical equipment condition as possible so that a proactive repair can be achieved prior to system failure and facility outage or damage. Equipment must be designed and rated for the task at hand. Use of inappropriate or underrated equipment has and will cause injuries and death. ● Qualifications – Because there are very few ways to accomplish this testing without some risk, it is absolutely necessary that the testing professional is well versed in the safe operation of the test equipment and that there will be procedures plus facility and equipment specific rules to control the hazard. An inexperienced operator may second guess his results or the way to operate the instrument resulting in more time in the energized equipment or perhaps having to do it all over again. This increases exposure and likelihood of injury. ● Barriers and Isolation – Barriers to keep unauthorized personnel away from energized equipment during testing and commissioning is absolutely necessary. The area must be completely secured so that no one goes inside. Coordination with Utility or other parts of a large system can create confusion. Any out-ofsequence or omitted step can result in death or serious injury. It is so easy to jump ahead or ignore the procedures under emergency or production loss conditions. It may be necessary for additional isolation of the equipment under test to avoid flashovers or dangerous conditions in other parts of the facility. Temporary grounding may be appropriate to ensure the workers safety. ● Instrumentation – Sometimes it is necessary to troubleshoot system for power quality or harmonics. Voltage levels, load levels or power factor may need to be measured to assess system performance and to justify system improvements or investigate energy savings. Installing permanent monitoring will allow these types of studies to be performed on an ongoing basis with exposure and for a fraction of the cost. ● Protective Device Testing – Of paramount importance is the setting and maintenance of protective devices and systems. In an aggressive preventative maintenance program in a large chemical facility, we found that 50% of the equipment that we opened had either a faulty condition or inaccurate wiring such

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Safety Vol. 1 that a significant failure or misoperation could be expected with a year. This underlines the need for complete verification and testing of protective device settings and operation on a regular basis. It also emphasizes the importance of control of change.

Operational and Maintenance Considerations In addition to the factors involved in design and testing, the way se operate, troubleshoot, and maintain electrical equipment affects the safety of our people and processes. We must be diligent in ensuring that any new installation is designed and performed with a new vision. However, there are still many existing installations that don’t stand up to present standards or are poorly maintained. Operating and maintenance procedures may or not be in place and they may not be appropriate for the hazards as we know them today. Plant management must be committed to an entirely new of looking at electrical safety. ● Environment – When we walk around a facility, the environment we are in is most obvious. It can be hot, cold, wet, dry, dusty, or clean and pleasant. We can also see where the electrical equipment sits and what conditions it must operate under. It doesn’t take a wise man to know that electrical equipment will not function reliably for very long in adverse conditions. Failure will cause plant outages and production losses which will likely require someone to repair or replace equipment or components under the gun. If the equipment was clean and looked after access to the equipment would be minimised and therefore the exposure significantly reduced. ● Integrity of Equipment – Cabinets with doors open or loose can mean only one thing. This cabinet requires frequent access due to some operational problem or difficulty. So, the very features of design which protect us from an explosion are compromised or are completely bypassed. So what is the solution? Go find the problem! Fix it, and then shut the door and re-install the fasteners to reinstate the original enclosure integrity. If fixing the problem is not possible or not economically feasible, find a way to avoid leaving the cabinet integrity compromised. Holes in equipment, frayed cords, missing pushbuttons, or damaged connectors seem pretty innocuous, but these are the seeds to a poorly maintained system. Not addressing these issues condones this and de-sensitizes workers to these hazards. It is also a signal that maintenance and testing is not being done. Cleaning and dusting is crucial. Moisture and animal ingression to equipment must be prevented. ● HVAC – What, for the equipment? Yes and no. What a better way to keep the equipment dry and clean than to dehumidify the air and keep a reasonable temperature in the switchroom. Getting rid of wide temperature changes avoids condensation planting itself on electrical equipment. But another factor affects the worker. When we force an electrician to work on a piece of equipment, whether simply PM or not, in adverse conditions, the quality of the work reduces and the chance for mistakes increase. We don’t have to make it cozy, but it needs

to consider the comfort of the worker with the PPE he will have to wear. ● Switching Operation – Switching, racking, drawing out electrical equipment performed with doors closed and latched puts an additional barrier between the arc energy and the equipment operator. Still, the enclosure may not contain the tremendous energy that is released on a fault within the equipment. Switching any equipment with an open door is hazardous and foolish. Switching – Is there a safe way to do this? Absolutely. ○ Once appropriate PPE is worn. Always use dry gloves and basic PPE. Establish a corporate procedure for the level of PPE to be used. ○ The first step is to evaluate the equipment. Does it look safe to operate? If not, de-energize and clean or dry or repair it so that it can operated in a safe fashion. ○ Ensure the load is minimised though the switch. It will be less likely to draw an arc. ○ Close and latch the equipment door. Use the designed handle and do not use a wrench or other contrivance to operate it with the door open. ○ Step to the side and, with non-working hand, operate the switch. If it is difficult to operate or won’t go, stop. Do not force a switch or circuit breaker. De-energize and repair. ○ Never try to stop part way though. Go all the way. Too Much PPE? - How can this be? We have taken great pains in the last ten years to identify the location and extent of the hazards. And in addition the manufacturers have joined in the fight by bringing to market many varieties of PPE and tools and other contrivances to deal with the high hazard areas. However, the worker is not always considered, even though he or she is the one who has to wear the PPE and use the tools when very little thought is made to actually changing the conditions or the way in which the task is completed in order to minimize exposure. ● Procedures – An interesting fact (2009 Ontario Electrical Safety Report by ESA) is that almost 75% of the causes of electrocutions can be attributed to not following procedures or human error. Equally interesting was the fact that most of the trades involved were not electricians. So does this let us off the hook? Can we just blame the victim for their own misfortune? Not really, if we look at why these occurred. So why does this happen? Perhaps policies and rules that were in place were neither feasible nor practical. Perhaps the pressure was intense to get the equipment back in production. Perhaps there was nobody else there to do the work and they were pressed into service even though unqualified. Documents like NFPA70E go a long way to describe many of the factors that need to be considered in the maintenance and operation of electrical equipment in any facility. Strict adoption of the relevant guideline will ensure that safety is preserved. Use of

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Safety Vol. 1 Energized Electric Permits and the development and use of Electrical Safety Procedures is paramount to any electrical safety program. Strict adherence to procedures must be mandatory for live work. No exceptions. The idea is not to have to work on energized equipment. Find a way not to. ● Attitudes – Some attitudes need to change. Production is not more important than someone’s safety. Scheduled outages are necessary for all equipment. Live work should only be carried out when absolutely necessary and only by qualified professionals using the right tools and following well thought out procedures. If you can’t find a way to justify working on equipment live, find another way of performing the task. It’s not worth it. The electrical industry is no place for cowboys. It is not cool to work live. You may get away with it but the young apprentice watching in earnest and awe may not be so lucky when he or she tries it. ● Electrician Survey – An excerpt from the 2009 Ontario Electrical Safety Report by ESA summarized the results from a survey of 1200 IBEW electricians carried out in 2008. The purpose of the survey was to obtain a baseline measure of the electrical trades’ safety awareness when working with 347V. Some of the more interesting responses: ○ 42% of respondents associated a high risk with working on energized circuits. ○ 57% indicated that they almost always take precautions concerning electrical safety (such as using personal protective equipment). ○ 83% indicated that they almost always test with meters before working on electrical systems. ○ 64% of those who worked energized did so to test. ○ 36% of those who worked energized did so because they; – believe that they can manage the risk – want to save time – are asked to do so ○ 88% indicated they have been educated to minimize the risk of working energized. ○ 49% indicated they are requested to work outside established safe work practices. ○ 89% indicated that information on electrical safety requirements would have an average to high impact on improving safety on the job. ○ 92% indicated more information and effort is required to support worker safety.

CONCLUSIONS We have reached a point in the workplace that electrical safety has become high profile and we will force workers to comply with the rules. This is excellent, but little thought has been spent on how

the work is going to get done without violating the rules. Chances will be taken because the work “has to be done.” The power systems engineers must begin by taking a new look at how system are designed and installed. Our engineers need to become aware of the “new” right way to do things. They must now consider how the equipment will be tested and commissioned. The will also need to consider how the equipment will be accessed and maintained and “design-in” innovative ways to remove the need for live work. We need to spend the money and time to do it right the first time. Design is not where to save money. Spend the time. Do it right. Downtime, repairs, equipment damage, quality issues and injuries and deaths are expensive. Testing and commissioning personnel need to understand that their trade is very specialized, and the nature of the work is hazardous at all times. Strict adherence to procedures and using the correct equipment will go a long way to ensuring the safety of all involved. Operations and maintenance personnel need to analyze and determine the need for accessing equipment under energized conditions. If equipment needs constant attention, replace or re-design it so it doesn’t. Don’t abuse equipment so that it is guaranteed to fail. Create innovative ways to perform the task that was traditionally performed live. In cases where live work is necessary, develop procedures which are practical and can be followed without breaking the rules. Once the rules are in place, enforcement is a critical final step. All the stakeholders from engineer, commissioner, trouble-shooter, and to management must step back and re-evaluate the whole process and develop workable and safe solutions to everyday electrical challenges. They need to adopt a new way of thinking, being proactive and not reactionary to electrical safety issues. Cost-effective and practical solutions must be embraced by management; not rigid and unthinking ones forced on those doing the work. Money and time needs to be spent up front to avoid “built-in” mistakes which can create traps down the road. Let’s “think outside the box” and visualize a new paradigm in which we will perform in a way that will allow people to work safely without hazards. After the fact is not good enough—it’s too late.

REFERENCES 2009 Ontario Electrical Safety Report – Electrical Safety Authority, Ontario, Canada

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Safety Vol. 1

ELECTRICAL SAFETY THROUGH DESIGN, INSTALLATION, AND MAINTENANCE PowerTest 2013 By Dennis K. Neitzel, C.P.E., AVO Training Institute, Inc.

INTRODUCTION

ELECTRICAL HAZARDS

Owners, operators, installers, and maintainers of commercial and industrial electric power systems and equipment, along with design consultants and manufacturers, should be concerned with the electrical safety aspects associated with these systems and equipment. Electrical safety must be an integral part of all electrical equipment and systems design and installations. An in-depth knowledge and understanding of all applicable codes, standards, and regulations is a must for electrical safety in design. Safety professionals and officers, knowledgeable in electrical equipment and systems as well as electrical safety, must be included in the planning and design phases of all projects to ensure that safety is discussed and included in the design.

In order to fully understand the electrical safety issues associated with design, installation, and maintenance, there must be an understanding of the hazards of electricity, identified through completing the electrical hazard analysis required by OSHA 1910.132(d) (1) and NFPA 70E Section 130.3(B)(1), specifically 130.4 Shock Hazard Analysis and 130.5 Arc Flash Hazard Analysis. One very important point to make here is that the physics of electricity are the same for everyone who has any kind of interaction with electricity or electrical equipment, even something as simple as plugging in an electrical appliance or portable tool; the physics are the same and do not change from the installer to the maintenance employee, or for that matter anyone else.

Electrical safety in the design, installation, and maintenance or electrical equipment and systems is critical because statistics reveal that there are approximately 400 electrocutions each year in industry with more than half of them occurring at less than 600 volts. There are also more than 2000 people admitted to burn centers each year from arc flash related burns. Additionally, over 800 people die annually due to fires caused by electrical faults, mainly due to faulty design, installation, or maintenance of the electrical equipment and/ or systems. Each year, electrical mishaps account for thousands of people sustaining shock and burn injuries. Electrical failures also result in billions of dollars in property damage each year; the vast majority of these incidents could have been prevented by applying electrical safety in the design, installation and maintenance of the electrical equipment and systems.

The three main hazards of electricity; electrical shock, electrical arc flash, and electrical arc blast, along with the physiological effects on the human body, must be understood by everyone who designs, installs, maintains, or works on, near, or interacts with, electrical circuits and equipment. These hazards must be understood by designers to help them better understand what needs to be done and why, when it comes to designing hazards out and safety in.

Current standards and regulations place minimum requirements on electrical system designers, installers, and manufacturers, which yields functional, reasonably safe electrical installations. Knowledge of the electrical hazards will assist in going beyond the minimum requirements and providing a safe and reliable electrical power system. Effective electrical preventive maintenance begins with good design. When designing a new facility, a conscious effort should be made to ensure optimum maintainability of the installed system and equipment. Design and installation of dual or redundant circuits, tie circuits, auxiliary power sources, and drawout protective devices make it easier to schedule maintenance activities and to perform the required maintenance work, with minimum interruption of production. Other effective design techniques that should be considered include, but are not limited to, equipment rooms to provide environmental protection, grouping of equipment for more convenience and accessibility, and standardization of equipment and components.

Designing and installing electrical equipment and systems in accordance with applicable standards, such as the National Equipment Manufacturer’s Association (NEMA), the National Electrical Code (NEC), the National Electrical Safety Code (NESC), the IEEE Color Book series for industrial and commercial power systems, and where applicable the Canadian Standards Association (CSA), the International Electrotechnical Commission (IEC), or the UK Electrical Industry British Standards (BS) (including the City and Guilds electrical standards) for design, manufacture, and installation of the electrical equipment and systems, will provide the minimum requirements for safety by design. Complying with these standards for design and installation, along with properly maintaining electrical equipment in its original condition can dramatically reduce the risk of the electrical shock and/or arc flash hazards. Adhering to safe work practices for personnel, along with complying with the maintenance recommendations for electrical equipment, provided by the Occupational Safety and Health Administration (OSHA), the National Fire Protection Association (NFPA; using NFPA 70E, Standard for Electrical Safety in the Workplace and NFPA 70B, Recommended Practice for Electrical Equipment Maintenance), the InterNational Electrical Testing Association (NETA) Standard for Maintenance Testing Specifications for Electric Power Distribution Equipment and Systems

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Safety Vol. 1 (MTS), and the NESC, along with the manufacturer’s instructions, can significantly reduce the risk of a person making contact with energized conductors or circuit parts and can reduce the risk of an arc flash event occurring, as well as significantly increasing the reliability of the electrical equipment and system.

Electrical Shock Electrical shock occurs when a person’s body completes the current path between two energized conductors of a circuit or between an energized conductor and a grounded surface or object. Essentially, when there is a difference in potential (voltage) from one part of the body to another, current will flow. The effects of an electrical shock on the human body can vary from a slight tingle to immediate cardiac arrest. The severity depends on several factors: ● Body resistance (wet or dry skin are major factors of resistance) ● Circuit voltage (50 volts to ground or more is considered by OSHA, IEEE, and NFPA as being hazardous voltage) ● Amount of current flowing through the body [determined by the circuit voltage divided by the body resistance I (current) = E (voltage) / R (resistance) or I = E/R] ● Current path through the body (if it passes through an vital organ it can be fatal) ● Area of contact ● Duration of contact The “Shock Hazard Analysis” required by NFPA 70E Section 130.4 provides the guidance needed to determine the level of shock hazard (voltage). This analysis also determines the shock protection boundaries, as well as the approach limits for qualified and unqualified employees, along with the required shock protection PPE, i.e., rubber insulating gloves with leather protectors, rubber insulating sleeves, rubber insulating blankets, etc.

Electrical Arc Flash An electrical arc flash is the rapid release of energy due to an arcing fault of either phase-to-phase, phase-to-neutral, or phaseto-ground. Typically when one of these three conditions is initiated it will end up with all three occurring because the air becomes a conductor due to ionization, along with the plasma created from the vaporized metals, particularly copper. Simply put, an arc flash is a phenomenon where a flashover of electric current leaves its intended path and travels through the air from one conductor to another, or to ground. The results are often violent and when a person is in close proximity to the arc flash, serious injury and even death can occur. Because of the violent nature of an arc flash exposure, when an employee is injured, the injury is serious – even resulting in death. It’s not uncommon for an injured employee to never regain their past quality of life. There are various studies on the causes of electrical injuries that show that a large number these injuries involve burns from elec-

trical arcs. There are actually three different issues with the arc flash hazard; 1) the arc temperature; 2) the incident energy; and 3) the pressure developed by the arc. The main concern with the arc temperature, which can be as high as 36,000ºF, is the flash flame and ignition of clothing. At approximately 203ºF (96ºC) for one-tenth of a second (6 cycles), the skin is rendered incurable or in other words a third-degree burn, and at approximately 172ºF (78ºC) for one-tenth of a second (6 cycles) a person could receive a second degree burn. The incident energy threshold for the onset of a third-degree burn is approximately 10.7 cal/cm2 and the incident energy threshold for a second-degree burn is approximately 1.2 cal/cm2. As can be seen by this, it does not take a very high temperature or very much incident energy to cause severe injury, which can result in extreme pain and discomfort or even death to the worker. The “Arc Flash Hazard Analysis” required by NFPA 70E Section 130.5 is used to determine the incident energy of an electrical arc, establish the Arc Flash Boundary, and for determining the level of arc-rated clothing and PPE required for protecting employees.

Electrical Arc Blast Another major hazard of electricity is the rapid expansion of the air caused by an electrical arc. This occurrence is referred to as an electrical arc blast or in other words an explosion. According to studies on the subject, the pressures from an electric arc are developed from two sources; the expansion of the metal in boiling and vaporizing, and the heating of the air by passage of the arc through it. Copper, when vaporized, expands by a factor of approximately 67,000 times; therefore, one inch3 of copper converts to 1.44 yards3 of vapor instantly, which causes this rapid expansion and the resulting blast or explosion. The arc flash coupled with the arc blast presents a very serious and dangerous situation for anyone working on or near, or otherwise interacting with the electrical equipment. While there is PPE for protecting employees from the shock and arc flash hazards, there is no PPE for the arc blast hazard. The best practice for protection from the arc blast is to incorporate safe work practices that include correct body positioning when operating or otherwise interacting with the electrical equipment. A good practice is to never stand where the body would be in the direct “line-of-fire” should an arc flash/blast occur. Ralph Lee’s paper, entitled “Pressures Developed by Arcs” (IEEE 1987), discusses methods that can be used to determine the amount of damage that a short circuit can cause in switchgear and the buildings where the switchgear is located.

ELECTRICAL SAFETY DESIGN CONSIDERATIONS With the above information, concerning the hazards of electricity, the electrical equipment and systems engineers and designers are better equipped to design out the electrical hazards and design

18 in electrical safety. There has been an increased effort over the last few decades to design electrical equipment with greater emphasis on safety, not only for the equipment and installation, but also for the personnel who operate and maintain, or otherwise interact with the equipment. Another consideration would be to include the maintenance supervisor and plant or facility engineer, along with the facility safety professional, in the design of electrical systems and equipment. These individuals are generally not considered or included in the design, when they should have an open line of communication with design engineering and supervision. Frequently, an unsafe installation or one that requires excessive maintenance can be traced to improper design or construction methods or misapplication of hardware and equipment. Everyone who can be affected by the design and installation of electrical equipment and systems should be consulted early in the design, preferably starting with the conceptual design phase of the project. Although electrical systems are typically designed and installed according to the NEC, and other applicable standards, the real safety emphasis was placed on the design and installation of electrical equipment and systems when OSHA issued the Final Rule of 29 CFR 1910 Subpart S, Electrical Standards, 1910.302-.308, Design Safety Standards for Electric Utilization Systems, on January 16, 1981. This regulation was recently revised and updated on February 14, 2007. This provided a Federal mandate on design and installation issues that related to the safety of employees working on, near, or with the electrical systems and equipment. This emphasis increased for electrical equipment when OSHA published the Final Rule of 29 CFR 1910.147, The Control of Hazardous Energy (lockout/tagout) on September 1, 1989, which required that machines and equipment be manufactured with energy isolating devices (lockout/tagout). Effective energy isolation is a key to electrical safety because it provides a means to deenergize the equipment so that it can be worked on in an electrically safe working condition. This regulatory requirement is quoted below: OSHA 29 CFR 1910.147(c)(2)(iii) requires all electrical equipment be capable of being locked out. OSHA states: “After January 2, 1990, whenever replacement or major repair, renovation or modification of a machine or equipment is performed, and whenever new machines or equipment are installed, energy isolating devices for such machine or equipment shall be designed to accept a lockout device.” Additional emphasis, placed on electrical safety, that would have a dramatic influence on the design, manufacturing, and installation of electrical equipment and systems, was increased with the publication of OSHA 29 CFR 1910.331-.335, Electrical Safety-Related Work Practices on August 6, 1990; OSHA 29 CFR 1910.269, Electric Power Generation, Transmission, and Distribution on January 31, 1994 (OSHA Proposed Revision June 15, 2005); and the revisions of NFPA 70E, Standard for Electrical Safety in the Workplace over the past twenty years, that includes the 1995, 2000,

Safety Vol. 1 2004, 2009, and 2012, as well as recent revisions to the ANSI/ IEEE C2, National Electrical Safety Code, all of which are dedicated to electrical safety. NFPA 70E-2012, Informative Annex O, titled Safety-Related Design Requirements, provides some general design considerations for electrical systems that include: ● Owners, managers, and employers are responsible for performing an electrical hazard analysis during the design of electrical systems and installations in order to more effectively choose design options that would reduce or eliminate employee exposure to hazard risks and to enhance the effectiveness of electrical safety. ● Factors that have an impact on safety-related work practices to protect employees must be considered. ● The NFPA 70E, 130.3(B)(1), Electrical hazard Analysis results, should be used to compare design options and choices to facilitate decisions in the design of the electrical equipment and systems, and serve to: ○ Eliminate electrical hazards risk ○ Reduce frequency of exposure to electrical hazards ○ Reduce the magnitude and severity of hazard exposure ○ Enable the ability to achieve an electrically safe work condition as noted in the requirements of OSHA 29 CFR 1910.147, stated above. Also to enable the use of the electrical energy control requirements of NFPA 70E Article 120, Establishing an Electrically Safe Work Condition and OSHA 29 CFR 1910.333(b), Working on or near exposed deenergized parts for performing an electrical lockout/ tagout. ○ Enhance the effectiveness of the electrical safety-related work practices ● Arc energy reduction is another consideration through the use of: ○ Zone-selective interlocking ○ Differential relaying ○ Energy-reducing maintenance switching with local status indicator – This feature sets the circuit breaker trip unit to a faster operating time, which will reduce the incident energy if an arc flash were to occur while the worker is working within the arc flash boundary. ● High speed microprocessor based protective relaying ● High speed optic sensors Always keep in mind that no matter how fast the sensors or relaying are, the end device is still an electro-mechanical circuit breaker that can fail to open in the time specified. Mechanical devices, such as circuit breakers, must be maintained in accordance

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Safety Vol. 1 with the manufacturer’s specifications. Even this is not a 100% guarantee, but it is the best we can do to minimize the risk of an unintentional time delay or total failure of the device. There is more information on this in the section titled Electrical Equipment Maintenance. There is a new IEEE Std 1814 Recommended Practice for Electrical System Design Techniques to Improve Electrical Safety being developed that will address some of the common concerns related to safety by design. The following information is provided in order to provide a better understanding of this new standard; the Scope, Purpose, Need for the Project, and Stakeholders for the Standard is provided below: ● Scope: This recommended practice addresses system and equipment design techniques and equipment selection that will improve electrical safety. The techniques in this Practice are intended to supplement the minimum requirements of installation codes and equipment standards. It does not include communications, programming, or life safety systems such as fire alarm and security. ● Purpose: This Recommended Practice provides a “tool kit” of techniques to enable the system designer to specify equipment features, apply protective schemes, and make informed system installation design choices. ● Need for the Project: There is currently no publication by an accepted standards entity that effectively communicates “electrical safety by design” concepts and their benefits. Current standards place only minimum requirements on electrical system designers and manufacturers that yield functional, reasonably safe electrical installations. There is a need to capture, in one location, the wealth of “electrical safety by design” concepts that have been published in recent IEEE papers and in other industry sources. ● Stakeholders for the Standard: Owners, operators, installers and maintainers of industrial, commercial, power generation facilities, design consultants, and manufacturers. The standard will address the following topics: ○ System Design – General ○ System Design – Operations & Maintenance ○ System and Equipment Grounding and Bonding ○ Power System Protection ○ Electrical Equipment ○ Environment (under consideration) ○ Heat Tracing (under consideration) ○ Labeling & Signage ○ Lighting Electrical equipment and systems must be designed such that there are no exposed energized conductors or circuit parts when

they are under normal operating conditions. When energized parts are exposed for maintenance purposes, they must be suitably guarded to prevent contact by personnel who are in the vicinity of the equipment or system. A short-circuit current study must be performed in order to ensure that electrical equipment and systems have a sufficient interrupting rating for the available short-circuit current. This study should be evaluated at least every five years or after any system or equipment modifications to ensure that nothing has changed that would cause an increase in the available short-circuit current. High impedance devices such as current-limiting reactors can be installed in an electrical system to reduce the available short-circuit current. If these devices are installed, the coordination of the circuit protective devices must be verified and adjusted in order to prevent longer clearing times that may increase the available incident energy of an arc flash. Installing current-limiting devices requires a complete electrical equipment and system coordination study to ensure that all components work together to decrease electrical hazards, especially the arc flash hazard. Manufacturers have designed electrical equipment, particularly metal-clad switchgear, to be “arc safe” or “arc resistant” in order to protect workers or operators when interfacing with the equipment (opening or closing the device). This type of equipment is designed with enclosure doors and latching mechanisms that are much more substantial than older equipment and are intended to help ensure that the door remains closed during an arc flash event. These enclosures also have a pressure relief venting mechanism on the top of the equipment that will open and vent the arc flash pressures and vapors up and through a duct system to a location outside of the electrical equipment room. This is a significant improvement for designing in electrical safety in the equipment. This section of the paper has emphasized equipment and systems design used to minimize the electrical hazards to personnel. There is another major design issue that is all too often overlooked and that is the working space around electrical equipment. This working space includes the spaces required by OSHA 1910.303(g) and NEC Article 110, Part II for 600 volts or less and OSHA 1910.303(h) and NEC Article 110, Part III for over 600 volts. This work space must be designed into a facility in order to provide a safe working space for electrical workers who are required to maintain the equipment and operators who are required to operate (open or close) switches, circuit breakers, or otherwise interface with the equipment. This space must not be confused with the required electrical shock or arc flash boundaries, which must also be considered.

ELECTRICAL EQUIPMENT MAINTENANCE Maintenance, lubrication and testing are essential to ensure proper protection of equipment and personnel. NFPA 70E Section 205.1 requires all persons who maintain electrical equipment to be a qualified person and Section 205.3 requires electrical equipment

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to be maintained according to the manufacturer’s instructions or industry consensus standards such as NFPA 70B, Recommended Practice for Electrical Equipment Maintenance and the InterNational Electrical Testing Association (ANSI/NETA) Standard for Maintenance Testing Specifications for Electric Power Distribution Equipment and Systems (MTS). Section 205.4 of NFPA 70E also requires that the maintenance, tests, and inspections be documented. With regard to personnel protection, NFPA 70E requires that a shock hazard analysis and an arc flash hazard analysis be performed before anyone approaches exposed electrical conductors or circuit parts that have not been placed in an electrically safe work condition. In addition it requires shock protection boundaries and an arc flash boundary to be established. All arc flash hazard analysis calculations, for determining the incident energy of an arc, and for establishing an arc flash boundary, require the arc clearing time, available short-circuit current, and the distance from the potential arc to the worker. The clearing time is derived from the engineering protective device coordination study which is based on what the protective devices are supposed to do. If, for example, a low-voltage power circuit breaker had not been operated or maintained for several years and the lubrication had become sticky or hardened, the circuit breaker could take several additional cycles, seconds, minutes, or longer to clear a fault condition. The following is a specific example: Two Arc Flash Hazard Analyses will be performed using a 20,000-amp short-circuit with the worker 18 inches from the arc: ● Based on what the system is supposed to do: ○ 0.083 second (5 cycles) ● Due to a sticky mechanism the breaker now has an unintentional time delay: ○ 0.5 second (30 cycles) Example #1: EMB = maximum 20 in. cubic box incident energy, cal/cm2 DB = distance from arc electrodes, inches (for distances 18 in. and greater) tA = arc duration, seconds F = short circuit current, kA (for the range of 16 kA to 50 kA) (1) DA = 18 in. (2) tA = 0.083 second (5 cycles) (3) F = 20kA EMB = 1038.7DB-1.4738 tA [0.0093F2 - 0.3453F + 5.9675] = 1038 x 0.0141 x 0.083[0.0093 x 400 - 0.3453 x 20 + 5.9675] = 1.4636 x [2.7815] = 3.5 cal/cm2 NFPA 70E, 130.5(B)(1) requires arc-rated clothing and other PPE are to be selected based on this incident energy level exposure. Therefore, the arc-rated clothing and PPE must have an arc rating of at least 3.5 cal/cm2.

Example #2: EMB = maximum 20 in. cubic box incident energy, cal/cm2 DB = distance from arc electrodes, inches (for distances 18 in. and greater) tA = arc duration, seconds F = short circuit current, kA (for the range of 16 kA to 50 kA) (1) DA = 18 in. (2) tA = 0.5 second (30 cycles) (3) F = 20kA EMB = 1038.7DB-1.4738 tA [0.0093F2 - 0.3453F + 5.9675] = 1038 x 0.0141 x 0.5[0.0093 x 400 - 0.3453 x 20 + 5.9675] = 7.3179 x [2.7815] = 20.4 cal/cm2 NFPA 70E, 130.5(B)(1) requires arc-rated clothing and other PPE to be selected based on this incident energy level exposure. Therefore, the arc-rated clothing and PPE must have an arc rating of at least 20.4 cal/cm2. If the worker is protected based on what the system is supposed to do, in this case 0.083 second or 5 cycles, and an unintentional time delay occurs, and the time is increased to 0.5 second or 30 cycles, the worker could be seriously injured or killed because he/ she was under protected. As can be seen, maintenance is extremely important to an electrical safety program. Maintenance must be performed according to the manufacturer’s instructions in order to minimize the risk of having an unintentional time delay, or complete failure, of the operation of the circuit overcurrent protective device(s). Maintenance is more than just performing the required preventive or predictive maintenance that is recommended by the manufacture. Other maintenance practices related to electrical safety include, but are not limited to: ● Effectively closing unused openings in electrical equipment and devices, such as: ○ When conduit is removed from an enclosure, plug the hole with an approved plug ○ When a molded case circuit breaker is removed from a panelboard, the opening must be closed using a panel compatible snap in device ○ When a low-voltage power circuit breaker is removed from the enclosure, the opening in the door must be effectively closed ● All electrical panels (includes power and control panels), receptacles, light switches, junction boxes, conduit bodies, etc. must have the covers securely and properly installed (all screws or bolts installed and/or all latches securely fastened) ● All electrical panels must have danger signs installed and maintained, as identified below:

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Safety Vol. 1 ○ 600 volts or less OSHA and NFPA requires: “Entrances to rooms and other guarded locations containing exposed live parts shall be marked with conspicuous warning signs forbidding unqualified persons to enter.” This would require a sign that states: “Warning–Hazardous Voltage–Unqualified PersonNEL Keep Out” or similar.

immediately prior to placing the equipment back in service. When equipment is taken out of service for maintenance, performance of both an as-found and an as-left test is highly recommended. The as-found tests will show any deterioration or defects in the equipment since the last maintenance period and, in addition, will indicate whether corrective maintenance or special procedures should be taken during the maintenance process. The as-left tests will indicate the degree of improvement in the equipment during the maintenance process and will also serve as a benchmark for comparison with the as-found tests during the next maintenance cycle.

SUMMARY ○ Over 600 volts OSHA and NFPA requires: “The entrances shall be kept locked unless they are under the observation of a qualified person at all times; and permanent and conspicuous warning signs shall be provided, reading substantially as follows: “DANGER–HIGH VOLTAGE–KEEP OUT”

The work space around electrical equipment must be maintained clear as required by OSHA and NFPA: “Working space required by this subpart may not be used for storage. When normally enclosed live parts are exposed for inspection or servicing, the working space, if in a passageway or general open space, shall be suitably guarded.” Many of the electrical equipment maintenance tasks require the equipment to be placed in an electrically safe work condition for effective safety prior to working on it. There are other maintenance tasks that might specifically require or permit equipment to be energized and in service while the tasks are being performed. Examples include taking voltage or current readings, troubleshooting, taking an oil sample from a transformer or oil circuit breaker for analysis, observing and recording operating characteristics such as temperatures, load conditions, corona, noise, or performing thermographic surveys while the equipment is under normal load and operating conditions. Coordinating maintenance and inspection with planned or scheduled production outages can provide an added safety environment for employees and may also provide a means to avoid major disruptions of operations. When performing the required maintenance and testing of electrical equipment there are two sets of values or readings that must be recorded, namely the “as-found” and “as-left” values. The asfound tests are tests performed on equipment when initially installed and before being energized or after it has been taken out of service for maintenance but before any maintenance work is performed. The as-left tests are tests performed on equipment after preventive or corrective maintenance has been completed and

Each of the three hazards of electricity (electrical shock, electrical arc-flash and electrical arc-blast) has its own unique characteristics that require special attention to hazard assessments, electrical safety programs and procedures, personal protective equipment, and the design, installation, and maintenance of electrical equipment and systems. Personnel safety should be a primary consideration in electrical systems design and in establishing safety-related work practices when performing preventative maintenance for electrical systems and equipment. Maintenance must be performed only by qualified persons trained in safe maintenance practices and the special considerations necessary to maintain electrical equipment. Safe work practices must be instituted and followed to prevent injury or death to those who are performing tasks, as well as others who might be exposed to the hazards. Among the hazards associated with working on energized electrical conductors or circuit parts are hazards of electricity, any of which may result in severe injury or death to the employee(s). Preventive maintenance should be performed only when equipment is in an electrically safe work condition. Equipment should always be deenergized for all inspections, tests, repairs, and other servicing. Where maintenance tasks must be performed when the equipment is energized, provisions are to be made to allow maintenance to be performed safely as required by NFPA 70E, Standard for Electrical Safety in the Workplace. For the purposes of this paper, deenergized means the equipment has been placed in an electrically safe work condition in accordance with NFPA 70E, Article 120, OSHA 1910.147, and 1910.333(b) requirements. The best way to avoid exposure to electrical hazards is to keep as far away as possible from electrical equipment and systems that have exposed energized parts or where the electrical equipment is being operated or maintained.

REFERENCES Ralph H. Lee, “Electrical Safety in Industrial Plants,” IEEE Transactions on Industry and General Applications, Vol. IGA-7, p. 10-16, Jan. /Feb. 1971. Ralph H. Lee, “The Other Electrical Hazard; Electric Arc Blast

22 Burns”, IEEE Transactions on Industry Applications, Vol. IA18, No. 3, May/June 1982. Ralph H. Lee, “Pressures Developed by Arcs”, IEEE Transactions on Industry Applications, Vol. IA-23, No. 4, p. 760, July/ Aug. 1987. National Fire Protection Association, NFPA 70E, Standard for Electrical Safety in the Workplace, 2012 Edition. National Fire Protection Association, NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, 2010 Edition. Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910, Subpart S, “Electrical Standards”, Friday, February 14, 2007. Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.331-.335, Electrical Safety-Related Work Practices, August 6, 1990. Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.147, “Control of Hazardous Energy Source (Lockout/Tagout)”, September 1, 1989. Dennis K. Neitzel, CPE, Director Emeritus of AVO Training Institute, Inc., Dallas, Texas, has over 45 years experience in Electrical Utility, Industrial facility, and shipyard/shipboard electrical equipment and systems maintenance and testing experience, with an extensive background in electrical safety and power systems analysis. He is an active member of IEEE, ASSE, AFE, IAEI, and NFPA. He is a Certified Plant Engineer (CPE) and a Certified Electrical Inspector-General. Mr. Neitzel earned his Bachelor’s degree in Electrical Engineering Management and his Master’s degree in Electrical Engineering Applied Sciences. He is a Principle Committee Member and Special Expert for the NFPA 70E, Standard for Electrical Safety in the Workplace; member of the Defense Safety Oversight Council, Electrical Safety Working Group – DoD Electrical Safety Special Interest Initiative; Working Group Chairman of IEEE 3007.1-2010 Recommended Practice for the Operation and Management of Industrial and Commercial Power Systems, 3007.2-2010 Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, & 3007.3-2012 Recommended Practice for Electrical Safety of Industrial and Commercial Power Systems; Working Group Chairman of IEEE P45.5 Recommended Practice for Electrical Installations on Shipboard - Safety Considerations; and co-author of the Electrical Safety Handbook, McGraw-Hill Publishers. Mr. Neitzel has also authored, published, and presented numerous technical papers and magazine articles on electrical safety, maintenance, and training. For more information, contact Mr. Neitzel by e-mail at [email protected].

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ELECTRICAL SAFETY MYTHS, LEGENDS AND MISCONCEPTIONS PowerTest 2013 James R. White, Shermco Industries, Inc.

INTRODUCTION It’s amazing how many field-trained electrical workers believe common electrical safety misconceptions and myths. These have to be smart people, or they wouldn’t last long in a trade like electrical testing and maintenance, but many still cling to their “tribal knowledge” and put themselves and those they work with at risk. This paper reviews some of the more common myths and misconceptions electrical workers may have concerning electricity and electrical safety. Readers are encouraged to use all or parts of the presentation as considered necessary to enlighten field workers and possibly prevent accidents that may be caused by them.

I ONLY NEED CHAPTER 1 IN NFPA 70E I agree that most of the electrical safety work practices are in Chapter 1, but the other chapters also contain information that is important to working safely. For example, NFPA 70E Chapter 2, “Safety-Related Maintenance Requirements” (2) contains a wealth of information required to keep an electrical power system safe to maintain. What these same people don’t seem to realize is that Chapter 1 is of no value without the Chapter 2 requirements being met. Electrical system equipment must be properly engineered, properly installed and properly maintained in order for the requirements in Chapter 1 to be met. Chapter 2 provides the bare minimum requirements. How can the incident energy of a system or circuit be estimated if the overcurrent protective device does not respond to a fault in accordance with the manufacturer’s specifications? It’s simply not possible. Throw away your fancy and expensive incident energy analysis, toss the tables and forget choosing PPE that will effectively protect workers from the arc flash hazard. Everything goes out the door! Chapter 2, Section 205 has many important requirements as: “205.2 Single-Line Diagram. A single-line diagram, where provided for the electrical system, shall be maintained in a legible condition and shall be kept current. 205.3 General Maintenance Requirements. Electrical equipment shall be maintained in accordance with manufacturers’ instructions or industry consensus standards to reduce the risk of failure and the subsequent exposure of employees to electrical hazards. 205.4 Overcurrent Protective Devices. Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards. Maintenance, tests, and inspections shall be documented.”

Don’t forget to study the annexes. Even though they are not mandatory, they provide additional information on the reasoning behind some of the more difficult sections in NFPA 70E and much more detail.

ELECTRICAL EQUIPMENT IS UNSAFE TO WALK BY, MUCH LESS WORK ON One statement I often hear is, “You need arc flash PPE to just walk through a room with operating electrical equipment.” I think it’s amazing how many people think this way. I received several phone calls arguing that I don’t care about electrical safety because I don’t think it’s necessary to wear arc-rated PPE whenever a worker is near energized equipment. Is there a possibility that the equipment could fail? Yes, there is always that possibility. The risk, however, is very small and, even though it should not be ignored, it does not create the need for arc-rated PPE, unless you are interacting with the equipment in a manner that could cause failure. The definition of an arc flash hazard in Article 100 of NFPA 70E states, “Arc Flash Hazard. A dangerous condition associated with the possible release of energy caused by an electric arc. Informational Note No. 1: An arc flash hazard may exist when energized electrical conductors or circuit parts are exposed or when they are within equipment in a guarded or enclosed condition, provided a person is interacting with the equipment in such a manner that could cause an electric arc. Under normal operating conditions, enclosed energized equipment that has been properly installed and maintained is not likely to pose an arc flash hazard.” There are a couple of things that stand out in this definition: ● An arc flash hazard may exist even if the equipment is in a guarded condition. This would apply when the work is interacting with the equipment in a manner that could cause failure. Racking circuit breakers, inserting or removing MCC buckets are two tasks that would apply. ● Normally operating equipment (properly installed and maintained) does not present an increased risk of an arc flash. The 2015 edition of NFPA 70E will reinforce this informational note both in the text and the manner in which the new task tables (130.7(C)(15) are structured. Also, reference NFPA 70E Section 130.7, Informational Note No. 2, “It is the collective experience of the Technical Committee on Electrical Safety in the Workplace that normal operation of enclosed electrical equipment, operating at 600 volts or less, that has been properly installed and maintained by qualified persons is not likely to expose the employee to an electrical hazard.”

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I’M GRANDFATHERED “We are exempt from 70E because we were built before the standard was written” or “We follow the 2004 (or some earlier) edition of NFPA 70E”. Really? Are you exempt from reality? Do the physical laws of nature really flow around you without touching you? I’m sure that’s the case on Mt. Olympia, but for the rest of us stuck on terra firma, we have no such exemption. NFPA 70E is revised every three years to keep pace with new findings and improve its language so it is more usable and easily understood. Because it is a safe work practice, when a new edition is released, prior editions are no longer valid for use in the field. Reference NFPA 70E page 1, where NFPA states, “….It was issued by the Standards Council on August 11, 2011, with an effective date of August 31, 2011, and supersedes all previous editions.” Once the revised edition of NFPA 70E is issued, previous editions are no longer effective. The NEC contains the same language, but has a different meaning. With the NEC, since it is a code that is enforceable, it supersedes the previous edition, but is not retroactive. It is one of the differences between a code and a safe work practice.

I’M A (MASTER ELECTRICIAN, JOURNEYMAN, ENGINEER, CERTIFIED FINANCIAL PLANNER) There is a difference between being qualified to OSHA 29CFR1910.332 and .333 and being experienced. I’m not discounting the worth of those years of experience (or education), but they are not adequate to keep you safe in the electrical workplace. Field-trained workers and technicians, and even those with degrees, receive little or no training about electrical safety. Apprenticeship programs, up until three years ago, did not include electrical safety in their curriculum. The idea that 15, 20 or even 30 years of field experience makes a worker qualified is exposed as a falsehood by the statistics. In a paper presented at the 2004 IEEE/IAS Electrical Safety Workshop (1), it was revealed that the workers most often injured were laborers with less than two years of experience and maintenance personnel and supervisors with more than ten years of experience. Figure 1 is a slide from that presentation.

Fig. 1: Workers Involved in Most Accidents

OSHA defines a qualified person in 29CFR1910.399, which states, “One who has received training in and has demonstrated skills and knowledge in the construction and operation of electric equipment and installations and the hazards involved.” There are two parts to satisfy, technical skills and knowledge and safety skills and knowledge. Both must be demonstrated. Whereas the technical skills portion may be accomplished through apprenticeships, degrees and field experience the safety side must be accomplished through training and a demonstration of those skills. A degree, license, job position or permit in no way qualifies an electrical worker in OSHA’s eyes.

ONLY “ELECTRICIAN” NEED ELECTRICAL SAFETY TRAINING This is probably one of the most common misconceptions that supervisors and companies have. These companies don’t realize that HVAC, instrumentation and control technicians, as well as multi-craft workers and even laborers may require some amount of electrical safety training, if they are exposed to the hazard. OSHA does not look at a job title to determine whether they require electrical safety training; they look at whether they are exposed to electrical hazards. Both OSHA regulations and NFPA 70E state that anyone who is exposed to an electrical hazard will require training. The level of training will depend on their job tasks and risks to the hazards. Specifically, OSHA states, “The training requirements contained in this section apply to employees who face a risk of electric shock that is not reduced to a safe level by the electrical installation requirements of 1910.303 through 1910.308. Note: Employees in occupations listed in Table S-4 face such a risk and are required to be trained. Other employees who also may reasonably be expected to face comparable risk of injury due to electric shock or other electrical hazards must also be trained.”

IF I’M SHOCKED, THE HOSPITAL KNOWS HOW TO CARE FOR ME One would think so, but that may or may not be the case. This is one of those situations that really depends on who is there when you are admitted. Some hospitals may have one or more doctors specially trained for electrical shock victims, but smaller hospitals may not. Emergency rooms physicians see hundreds, if not thousands of cases each year from vehicle accidents, domestic disputes, gang activity and home accidents that result in broken bones, cuts, lacerations, contusions, concussions, gun shots, and other types of non-electrical injuries. Electrical shock victims are not nearly as common, so when one arrives in the ER, the attending physician may need some help. Dr. A.G. Soto has recommended a one-page (front and back) form (7) to both gather important information concerning the accident and victim (if possible) and to provide some basic information on electrical shock effects and how to manage them.

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Safety Vol. 1 HIRE CONTRACTORS FOR ALL HAZARDOUS ELECTRICAL WORK

○ Minimum arc rating of clothing

This is a true statement if you don’t have the in-house expertise to handle high-voltage or high-risk electrical tasks. However, contracting work out does not typically absolve your company of liability should an accident occur. OSHA’s Multi-Employer Worksite Policy CPL 2-0.124 Rev 15.00 ensures that in most cases the host employer (equipment or facility owner) will be held partially responsible.

○ Highest Hazard/Risk Category (HRC) for the equipment

This policy, in effect since 1999, allows OSHA to split responsibility for an accident in four roles: ● Controlling employer ● Exposing employer ● Correcting employer ● Creating employer OSHA will determine if your company should be assigned one of these roles, then determine if you fulfilled your responsibilities for that role. Citations follow soon after. NFPA 70E also contains requirements regarding both the Host and contracting employers in Section 110.1. Section 110.1(C) requires the pre-job planning meeting be documented.

LABEL MANIA Figure 3 is a typical arc flash hazard warning label required by the NEC Section 110.16 (4). The label in Figure 3 actually has more information than that required by 110.16, as the NEC requirement is to only warn against the arc flash hazard, and Figure 3 has shock warnings and PPE advisements, as well.

○ Required level of PPE ● Nominal system voltage ● Arc flash boundary” NFPA 70E requires this additional information because it is clear that electrical workers are not able to determine appropriate PPE requirements as mandated by 29CFR1910.335. This is most often due to the information not being readily available. For those who appreciate exceptions, there is an exception for this requirement in NFPA 70E, “Exception: Labels applied prior to September 30, 2011 are acceptable if they contain the available incident energy or required level of PPE. The method of calculating and data to support the information for the label shall be documented.”

OSHA DON’T WORRY ME OSHA generally does not pursue legal action against individuals. They follow the Golden Rule – He Who Has the Gold makes the Rules, which are the companies that employ workers. They control the paychecks and working conditions, and therefore bear workplace responsibility. However, if you are a supervisor or manager and are responsible for someone’s death, through a decision or policy you implemented, that can all change. The information below is from the OSHA website: “Referrals or Significant Aid to Prosecutors Addressing OSHA-Related Matters” Criminal Referrals

2007

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“These actions include referrals under Title 29 of the United States Code, Section 666(e), for employee deaths caused by willful conduct violating an OSHA standard, obstruction of justice, state and local investigations and prosecutions, and fraud related to other OSHA matters, such as training verification.” Fig. 3: Typical Arc Flash Hazard Warning Label The wording in NEC 110.16 is mirrored in NFPA 70E Section 130.5(C), Equipment Labeling where it states “Electrical equipment such as switchboards, panelboards, industrial control panels, meter socket enclosures, and motor control centers that are in other than dwelling units and are likely to require examination, adjustments, servicing or maintenance while energized shall be field marked with a label.” NFPA 70E adds the following requirements: “containing all the following information: ● At least one of the following: ○ Available incident energy and the corresponding working distance

Ten to 14 cases a year may not seem like a large number, especially compared to the thousands of cases OSHA prosecutes. That is, unless you happen to be one of those being charged. Note also that these criminal referrals also include obstruction of justice and fraud, such as altering training records. Oh, now I see why I should have been spending that money to train my people. Too late!

OSHA ENFORCES NFPA 70E This is another very common myth, one that refuses to die. I guess it’s because it would make sense, but in reality, OSHA cannot enforce anything but Federal regulations. That confines them to writing citations for violating 29CFR1910 (General Industry) or 29CFR1926 (Construction) regulations. In a letter of interpretation(5), OSHA states, “Industry consensus standards, such as NFPA 70E, can be used by employers as guides to making the assess-

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ments and equipment selections required by the standard. Similarly, in OSHA enforcement actions, they can be used as evidence of whether the employer acted reasonably.” Federal courts have found that NFPA 70E is “standard industry practice.” OSHA may not be able to enforce NFPA 70E, but they can certainly use it against you when they haul you into court.

IF YOU TOUCH THAT 20A CIRCUIT BREAKER, YOU’LL HAVE 20A FLOW THROUGH YOUR BODY That’s a real statement I overheard one day while on a construction site. I hope he was just trying to scare them into complying with safety rules, but maybe he didn’t know the facts. This situation is similar to a safety instructor I once heard tell students that “3mA of current directly across a person’s heart would kill them”. Statements such as these may achieve the desired effect initially, but once the person who hears such misinformation gets the truth, credibility is gone forever. OHM’s Law shows us that only a limited amount of current would actually flow through our bodies. That’s the good news. The bad? It really doesn’t take very much current to injure or kill us. The current from a 120-volt circuit is more than enough to do the job. The typical resistance of our body is about 1,000Ω(6) for the average man. Factors that will modify that value up or down are things such as bone mass, walking surface, shoe material, wet environment, etc., but is a fair number to begin with. At 120V and having 1,000Ω resistance in the circuit, current flow would be limited to a maximum of 120mA. At 75mA a person has a risk of going into ventricular fibrillation. As the current increases, that risk increases until even an instantaneous contact could cause fibrillation. I always tell students in our classes that low voltage does not mean low hazard. Studies consistently show that in the workplace, low-voltage is the number one killer.

LOW-VOLTAGE MEANS NO ARC FLASH HAZARDS For some reason, people downplay the hazards and risks associated with working around low-voltage equipment and systems. Maybe it’s because we aren’t immediately killed or injured by it on the first contact, so now it’s not a big deal. The same rationale seems to apply itself to the arc flash hazard. “If it was dangerous, I’d know it by now”. Good logic! An arc flash hazard can exist as low as 208V; it just requires a large short circuit source. At 480V there is more than enough voltage to push current through the arc(3). Figure 2 is from the TEST NUMBER 4 conducted as prior to the IEEE 1584 working group tests to help establish some criteria. In Test No. 4 the line-side of a 480V 30A circuit breaker was shorted to ground, simulating a phase-to-ground short circuit. There was 480V, 22,000A available short circuit current with an operating time of 6 cycles. The incident energy was estimated at 5.8 cal/cm2. The results were impressive!

Fig. 2: Test Number Four Results

ONE SIZE FITS ALL PROTECTION Do you want to save money, Bunkie? A number of otherwise intelligent people seem to have found a way to do that. Make everyone wear the same super-sized arc flash PPE for all electrical tasks. That will show them how much we love them! Let’s look at what OSHA says. 29CFR1910.335 states, “Employees working in areas where there are potential electrical hazards shall be provided with, and shall use, electrical protective equipment that is appropriate for the specific parts of the body to be protected and for the work to be performed.” Wearing too much protection can be as hazardous as too little, if it interferes with performing the task. Workers not being able to perform the task, or passing out due to heat stress is not making them safer. A super high-rated arc flash suit and PPE does nothing to protect the worker from the arc blast hazard. A person can be protected from the thermal hazard, but when incident energy exceeds 40 cal/ cm2, there’s a good chance the arc blast hazard will be a greater hazard than the thermal hazard. NFPA 70E Section 130.7(A) Informational Note No. 1 states, “The PPE requirements of 130.7 are intended to protect a person from arc flash and shock hazards. While some situations could result in burns to the skin, even with the protection selected, burn injury should be reduced and survivable. Due to the explosive effect of some arc events, physical trauma injuries could occur. The PPE requirements of 130.7 do not address protection against physical trauma other than exposure to the thermal effects of an arc flash.” At this time the arc blast hazard cannot be accurately estimated. This means that when working on or near energized electrical equipment that has a high short circuit available current extra caution is required.

THE GROUND WIRE DOESN’T DO ANYTHING If I had to vote for the most misunderstood electrical component, this would be it. The number of electricians who believe this is pretty amazing. Some (certainly not all) electricians have used the ground wire as another energized conductor, as neutral and,

Safety Vol. 1 in numerous instances they have just cut it off (it doesn’t do anything). This misguided action causes fires, injuries and fatalities. Proper grounding and bonding, as required by the National Electrical Code is critical to worker safety, but people continue to cut ground pins off or use cords that have broken ground pins, disconnect grounds or ignore grounding requirements, all to their harm.

SUMMARY Misinformation causes an unsafe work environment and exposes electrical workers and others to risk of injury and death. It can undo years of training and damage a person’s credibility to the point that nothing he or she says will improve it. Credibility is like trust; once it’s lost it is very hard to recover. Workers exposed to electrical hazards must have accurate information in order to make acceptable and safe decisions when working in the field. One of the most important aspects of NFPA 70E is that it requires an electrical system to be properly engineered, properly installed and properly maintained. If these three requirements are not met in accordance with NFPA 70E Chapter 2, none of Chapter 1 would apply. Chapter 2, and to a lesser degree Chapter 3, are critical to maintaining a safe work environment as mandated by OSHA 5(a)(1), General Duty Clause.

REFERENCES Kowalski-Trakofler, Ph.D. Kathleen, Non-Contact Electric Arc-Induced Injuries in the Mining Industry; a Multi-Disciplinary Approach, 2004 IEEE/IAS Electrical Safety Workshop NFPA 70E®, “Standard for Electrical Safety in the Workplace”, 2012 edition, Chapters 1 and 2 Lee, Ralph H., The Other Electrical Hazard, Electrical Arc Blast Burns, IEEE Transactions on Industry Applications, volume I-A-18, No. 3, May/June 1982 NFPA 70®, National Electrical Code, 2011 edition. Pg. 70-37 Letter of Interpretation, OSHA, General Duty Clause (5)(A)(1) Citations on Multi-Employer Worksites; NFPA 70E Electrical Safety Requirements and Personal Protective Equipment, 0725-2003 ANSI/IEEE, Guide for Safety in AC Substation Grounding, Std. 80-2000, pg. 16 Soto, A.G. MD., Electrical Injuries Management, 2004 IEEE/ IAS Electrical Safety Workshop James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA

27 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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INDUSTRIAL ELECTRICAL SAFETY COMPLIANCE ASSESSMENTS (INSPECTIONS) PowerTest 2014 Dennis K. Neitzel, C.P.E., AVO Training Institute, Inc.

INTRODUCTION The Occupational Safety and Health Administration (OSHA) concluded that effective management of worker safety and health protection is a decisive factor in reducing the extent and the severity of work-related injuries and illnesses. Effective management addresses all work-related hazards, including those potential hazards which could result from a change in worksite conditions or practices. It addresses hazards whether or not they are regulated by government standards. OSHA has reached this conclusion in the course of their evaluation of worksites in their Enforcement Programs, their State-Operated Consultation Programs, and their Voluntary Protection Programs (VPP). These evaluations have revealed a basic relationship between effective management of worker safety and health protection, and a low incidence and severity of employee injuries. Such management also correlates with the elimination or adequate control of employee exposure to toxic substances and other unhealthful conditions. OSHA’s experience in the VPP has also indicated that effective management of safety and health protection improves employee morale and productivity, as well as significantly reducing workers’ compensation costs and other less obvious costs of work-related injuries and illnesses.

ELECTRICAL INSPECTION PROGRAM There is an effective tool that management can use in their efforts to establish and maintain their electrical safety program and that is by incorporating an electrical safety inspection program. The OSH Act of 1970 requires the employer to provide a safe and healthful workplace for every working man and woman. Section 5(a)(1) of the OSH Act, referred to as the “General Duty Clause”, requires each employer to furnish to each of his employees employment and a place of employment which are free from recognized hazards that are causing or are likely to cause death or serious physical harm to his employees and requires the employer to comply with occupational safety and health standards promulgated under the OSH Act. To assist in accomplishing this, the employer can implement a self-assessment or inspection program to ensure that the electrical systems and equipment are properly designed, installed, operated, and maintained in a safe and reliable condition. To be effective the electrical safety inspections should be conducted to verify full compliance with OSHA 29 CFR 1910 electrical related regulations, which include the following:

● 29 CFR 1910, Subpart I, Personal Protective Equipment ○ 1910.132, General Requirements ○ 1910.137, Electrical Protective Equipment ● 29 CFR 1910, Subpart J, General Environmental Controls ○ 1910.146, Permit-Required Confined Spaces (as applicable) ○ 1910.147, The Control of Hazardous Energy (lockout/ tagout) ● 29 CFR 1910, Subpart R, Special Industries (as applicable) ○ 1910.269, Electric Power Generation, Transmission, and Distribution ● 29 CFR 1910, Subpart S, Electrical Standards: ○ 1910.302-.308, Design Safety Standards for Electrical Systems ○ 1910.331-.335, Electrical Safety-Related Work Practices ○ 1910.399, Definitions There are also several industry consensus standards that should be considered as well, such as: ● NFPA 70, National Electrical Code ● NFPA 70E, Standard for Electrical Safety in the Workplace ● NFPA 70B, Recommended Practice for Electrical Equipment Maintenance ● ANSI/IEEE C2, National Electrical Safety Code (NESC) (as applicable) Compliance with these regulations and standards will help to ensure that employers are installing and maintaining electrical systems and equipment in proper and safe working condition, as well as verifying each employee’s utilization of safe work practices and appropriate personal protective equipment for shock and arc flash. Inspections also assist supervisors and managers in meeting electrical safety goals set by the company for regulatory compliance. NFPA 70E, Section 110.3(H) Electrical Safety Auditing, provides additional direction on auditing the electrical safety program and field work on a frequency not to exceed three (3) years and must be documented. This audit is required to contain at least the following four components: ● Employee implementation of the electrical safety program ○ Understanding the program ○ Identify how much supervision emphasizes the program

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Safety Vol. 1 ○ Describe the condition of the program ● Does the electrical safety program address all hazards ○ Determines if employees are exposed to other risks not addressed in the program ● The audit must address the process for revising procedures as needed ○ Where incidents or injuries occur, a review of procedures must take place ○ Procedure revisions or a new procedure may be needed ● Define how procedure revisions are communicated to employees The inspection and audit programs should be carried out by an electrically knowledgeable, qualified person in order to identify deficiencies in electrical equipment or systems, and to correct or properly document any deficiencies found. One way to ensure that the inspection program is on target is to have electrically qualified company safety personnel conduct the inspections, or another option is to contract a third party electrical safety inspector. Using a person from outside the company or facility will often lead to discovery of issues and deficiencies that may be overlooked by self-inspecting. The written electrical safety inspection program should be reviewed on a periodic basis, by electrically qualified persons, to ensure that the check-lists are current and are being utilized. Inspections should include a review of the entire electrical safe work program for energized and deenergized work, which includes the energy control or lockout/tagout program. Written work practices (programs and procedures), personal protective equipment (PPE), and installed electrical equipment and systems physical condition and maintenance should be inspected for compliance with regulations and industry consensus standards. Inspections should also include “work in progress” to ensure that each worker understands and is implementing electrical safe work practices and procedures, and utilizing the proper PPE and insulated tools. This reflects directly on the qualified person training programs. A root cause analysis of the deficiencies identified should be a part of the inspection program. Changes or corrections in processes, practices, and procedures should be analyzed to help prevent a reoccurrence. Any items identified in the inspection or lessons learned should be communicated to others in the organization that may benefit from the information.

MANAGEMENT ROLE Management ultimately bears the burden of effectively administering the electrical safety inspection programs. Their involvement in the development and implementation of these programs is vital to their success. There are several areas that must be considered when developing the inspection program; they include, but are not

limited to: hazard assessments, inspections and audits, electrical safety training for all personnel (qualified and unqualified or electrical and non-electrical personnel), and evaluation of the existing safety management system. To assist employers and employees in developing effective safety and health management systems, OSHA published recommended Safety and Health Program Management Guidelines (Federal Register 54(16): 3904-3916, January 26, 1989). These voluntary guidelines can be applied to all places of employment covered by OSHA. The guidelines identify four general elements that are critical to the development of a successful safety and health management system. ● Management leadership and employee involvement ● Worksite analysis ● Hazard prevention and control ● Safety training

INSPECTION GUIDELINES Employers should perform a self-assessment or inspection to determine the adequacy of their written electrical safety program and procedures and to ensure that they are being implemented. The inspection should also include an inspection of the facility electrical systems and equipment to ensure compliance with the installation and maintenance regulations and standards. There are numerous subjects and items that should be addressed in an electrical safety inspection. The list below identifies several typical deficiencies that are commonly found during electrical safety and compliance inspections of industrial and commercial facilities: ● Operations and electrical safety one-line diagrams, drawings, and identification tags ○ Must be up-to-date per the requirements of NFPA 70E, Section 120.1(1), ○ Must be maintained up-to-date per NFPA 70E, Section 205.2, Single-Line Diagram ● Electrical Hazard Analysis performed ○ OSHA 1910.132(d)(1) requires an overall hazard assessment to determine if hazards are present or are likely to be present ○ NFPA 70E, Section 130.3 requires an electrical hazard analysis be performed ○ NFPA 70E, Section 130.4 provides the requirements for the Shock Hazard Analysis ○ NFPA 70E, Section 130.5 provides the requirements for the Arc Flash Hazard Analysis and arc flash hazard warning label requirements

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● Trained and qualified operators and maintenance technicians ○ OSHA 1910.399 Definitions – Qualified Person

● Grounding and bonding of electrical equipment and systems

○ OSHA 1910.332, Training

○ Per NEC Article 250, Grounding and Bonding

○ OSHA 1910.269(a)(2), Training

○ Per NESC Section 9, Grounding Methods for Electric Supply and Communications Facilities

○ OSHA 1910.132(f), Training (PPE) ○ NFPA 70E, Section 110.2, Training Requirements ● De-energized work procedures ○ Lockout/tagout policy and procedures per OSHA 29 CFR 1910.147, The Control of Hazardous Energy (Lockout/ Tagout) ○ Additional requirements for electrical lockout/tagout per OSHA 29 CFR 1910.333(b), Working on or near exposed deenergized parts ○ The requirements of NFPA 70E, Article 120 for Establishing an Electrically Safe Work Condition ● Electrical safety program ○ NFPA 70E, Section 110.3, Electrical Safety Program ○ OSHA 29 CFR 1910.333(a)(2), Energized Parts ○ Additional resource – The NFPA Electrical Safety Program Book ● Energized safe work procedures ○ OSHA 29 CFR 1910.333(a)(2), Energized Parts ○ OSHA Instruction STD 1-16.7, Directorate of Compliance Programs, paragraph I(2)(d)(2)… ”suitable safe work practices for the conditions under which the work is to be performed shall be included in the written procedures and strictly enforced. These work practices are given in 1910.333(c) and 1910.335.” ● Energized Electrical Work Permit ○ NFPA 70E, Section 130.2(B), Energized Electrical Work Permit ● Shock and Arc Flash Personal Protective Equipment (PPE)

○ IEEE Standard 80, IEEE Guide for Safety in AC Substation Grounding ○ IEEE Standard 142, IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems ● Corrosion of electrical equipment ○ NEC 110.11, Deteriorating Agents ● Maintenance practices (maintenance frequency, methods, and testing) ○ Manufacturer’s Instructions ○ NFPA 70E, Chapter 2, Safety-Related Maintenance Requirements ○ NFPA 70B, Recommended Practice for Electrical Equipment Maintenance ○ ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems ● Exposed live (energized) parts – covers left off or doors left open ○ OSHA 1910.303(g)(2), Guarding of live parts ○ NEC 110.27(A), Live Parts Guarded Against Accidental Contact ● Unused openings not effectively closed ○ OSHA 1910.303(b)(7), Mechanical execution of work ○ NEC 110.12(A), Unused Openings ● Working space around electrical equipment, 600-volts or less ○ OSHA 1910.303(g)(1), Space about electric equipment ○ OSHA 1910.303(g)(1)(ii) – “may not be used for storage”

○ OSHA 1910.132(d) requires a hazard assessment to determine what PPE is required

○ NEC 110.26, Spaces About Electrical Equipment

○ OSHA 335, Safeguards for Personnel Protection provides the minimum requirements to provide PPE for electrical hazards and the required use of insulated hand tools

○ ANSI/IEEE C2, NESC, Section 125.A., Working space about electric equipment

○ NFPA 70E, Section 130.4 determines what shock protection PPE is required ○ NFPA 70E, Section 130.5 provides information for selecting arc flash clothing and PPE ○ NFPA 70E, Section 130.7 provides specific PPE requirements for all parts of the body for shock and arc flash

○ NEC 110.26(B), Clear Spaces

● Working space around electrical equipment, over 600-volts ○ OSHA 1910.303(h)(3), Work space about equipment ○ NEC 110.34(A), Working Space ○ ANSI/IEEE C2, NESC, Section 125.B., Working space about electric equipment ● Identification of disconnecting means

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Safety Vol. 1 ○ OSHA 1910.303(f), Disconnecting means and circuits ○ NEC 110.22, Identification of Disconnecting Means ● Improper or unapproved extension cords ○ OSHA 1910.303(a), Approval – See definition of Approved in OSHA 1910.399 – See OSHA Letter Acceptable Job-Made extension cords, June 17, 1992 ○ OSHA 1910.303(b)(1)(i), “suitability for installation and use” ○ OSHA 1910.305(g), Flexible cords and cables ○ OSHA 1910.305(g)(1), Use of flexible cords and cables ○ NEC 110.2, Approval – See definition of Approved in NEC Article 100

† Do you specify compliance with OSHA for all contract electrical work? † Are all employees required to report as soon as practicable any obvious hazard to life or property observed in connection with electrical equipment or lines? † Are employees instructed to make preliminary inspections and/or appropriate tests to determine what conditions exist before starting work on electrical equipment or lines? † When electrical equipment or lines are to be serviced, maintained or adjusted, are necessary switches opened, locked-out and tagged whenever possible? † Are portable electrical tools and equipment grounded or of the double insulated type?

○ NEC 110.3(A)(1), “suitability for installation and use”

† Are electrical appliances such as vacuum cleaners, polishers, and vending machines grounded?

○ NEC 400.8, Uses Not Permitted

† Do extension cords being used have a grounding conductor?

○ NEC 400.9, Splices

† Are multiple plug adaptors prohibited?

○ NEC 400.10, Pull at Joints and Terminals

† Are ground-fault circuit-interrupters (GFCI) installed on each temporary 15 or 20 ampere, 120 volt AC circuit at locations where construction, demolition, modifications, alterations or excavations are being performed?

● Damaged extension cords ○ OSHA 1910.305(a)(2)(x), “Flexible cords and cables shall be protected” ○ OSHA 1910.305(g)(1), Use of flexible cords and cables ○ OSHA 1910.334(a), Portable electric equipment ○ NEC 400.8, Uses Not Permitted ○ NFPA 70E, 205.13, Single and Multiple Conductors and Cables ○ NFPA 70E, 205.14, Flexible Cords and Cables ○ NFPA 70E, 110.4(B), Portable Electric Equipment ● Damaged cord- and plug-connected equipment ○ All references for “damaged extension cords” also applies ○ NFPA 70E, 245.1, Maintenance Requirements for Portable Electric Tools and Equipment ● Availability and condition of electrical PPE ○ OSHA 1910.132, PPE General Requirements ○ OSHA 1910.137, Electrical Protective Equipment ○ OSHA 1910.335, Safeguards for Personnel Protection ○ NFPA 70E, 130.7, Personal and Other Protective Equipment

† Are all temporary circuits protected by suitable disconnecting switches or plug connectors at the junction with permanent wiring? † Do you have electrical installations in hazardous dust or vapor areas? If so, do they meet the National Electrical Code (NEC) for hazardous locations? † Is exposed wiring and cords with frayed or deteriorated insulation repaired or replaced promptly? † Are flexible cords and cables free of splices or taps? † Are clamps or other securing means provided on flexible cords or cables at plugs, receptacles, tools, equipment, etc., and is the cord jacket securely held in place? Are all cord, cable and raceway connections intact and secure? † In wet or damp locations, are electrical tools and equipment appropriate for the use or location or otherwise protected? † Is the location of electrical power lines and cables (overhead, underground, under floor, other side of walls) determined before digging, drilling or similar work is begun?

OSHA ELECTRICAL SELF-INSPECTION CHECKLIST

† Are metal measuring tapes, ropes, handlines or similar devices with metallic thread woven into the fabric prohibited where they could come in contact with energized parts of equipment or circuit conductors?

The following is an OSHA Electrical Self-Inspection Checklist for additional guidelines on what OSHA will likely look for when conducting an electrical safety inspection.

† Is the use of metal ladders prohibited in areas where the ladder or the person using the ladder could come in contact with energized parts of equipment, fixtures or circuit conductors?

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† Are all disconnecting switches and circuit breakers labelled to indicate their use or equipment served?

ufacturer’s instructions, will provide a means to reduce accidents, injuries, and fatalities in all segments of industry.

† Are disconnecting means always opened before fuses are replaced?

It is always important to ensure that employees are properly trained and qualified for a job. Not understanding the circumstances about the job or task can lead to accidents and injuries. Even properly qualified electrical workers are susceptible to accidents. That is why it is important to make safety an integral part of the planning process for every job.

† Do all interior wiring systems include provisions for grounding metal parts of electrical raceways, equipment and enclosures? † Are all electrical raceways and enclosures securely fastened in place? † Are all energized parts of electrical circuits and equipment guarded against accidental contact by approved cabinets or enclosures? † Is sufficient access and working space provided and maintained about all electrical equipment to permit ready and safe operations and maintenance? † Are all unused openings (including conduit knockouts) in electrical enclosures and fittings closed with appropriate covers, plugs or plates? † Are electrical enclosures such as switches, receptacles, and junction boxes, provided with tight fitting covers or plates? † Are disconnecting switches for electrical motors in excess of two horsepower, capable of opening the circuit when the motor is in a stalled condition, without exploding? (Switches must be horsepower rated equal to or in excess of the motor hp rating.) Is low voltage protection provided in the control device of motors driving machines or equipment which could cause probable injury from inadvertent starting? † Is each motor disconnecting switch or circuit breaker located within sight of the motor control device? † Is each motor located within sight of its controller or the controller disconnecting means capable of being locked in the open position or is a separate disconnecting means installed in the circuit within sight of the motor? † Is the controller for each motor in excess of two horsepower, rated in horsepower equal to or in excess of the rating of the motor it serves?

Important safety tips to help avoid injuries include, but are not limited to: ● Identify the electric shock and arc flash hazards, as well as other hazards that may be present. ● Use the right tools for the job. ● Isolate equipment from energy sources. ● Test every circuit and every conductor every time before you touch it. ● Work on electrical equipment and conductors only when de-energized. ● Turn off, try, test, lockout/tagout, and ground before working on equipment. ● Treat de-energized electrical equipment and conductors as energized until properly lockout/tagout, tested, and ground procedures are implemented. ● Wear protective clothing and equipment and use insulated tools for electrical hazards. Adherence to these basic inspection and safety tips can help avoid serious, or even life-threatening, injuries while working with electrical equipment and systems.

REFERENCES National Fire Protection Association, NFPA 70, National Electrical Code, 2011 Edition National Fire Protection Association, NFPA 70E, Standard for Electrical Safety in the Workplace, 2012 Edition

† Are employees who regularly work on or around energized electrical equipment or lines instructed in the cardiopulmonary resuscitation (CPR) methods?

National Fire Protection Association, NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, 2010 Edition

† Are employees prohibited from working alone on energized lines or equipment over 600 volts?

Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910, Subpart S, “Electrical Standards”, Friday, February 14, 2007

SUMMARY Electrical safety inspections are necessary in order to verify compliance with regulations and standards, as well as to help ensure that electrical installations and equipment are safe. Compliance with the OSHA regulations and NFPA standards, along with other industry consensus standards and electrical equipment man-

ANSI/IEEE C2, National Electrical Safety Code, 2012 Edition

Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.331-.335, Electrical Safety-Related Work Practices, August 6, 1990 Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.147, “Control of Hazardous Energy Source (Lockout/Tagout)”, September 1, 1989

Safety Vol. 1 Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.269, “Electric Power Generation, Transmission, and Distribution”, January 31, 1994 Occupational Safety and Health Administration (OSHA), Subpart I, Personal Protective Equipment, 1910.132, General Requirements, (1st publication) 39 FR 23502, June 27, 1974, (most recent - 76 FR 33606, June 8, 2011 Dennis K. Neitzel, CPE, Director Emeritus of AVO Training Institute, Inc., Dallas, Texas, has over 45 years experience in Electrical Utility, Industrial facility, and shipyard/shipboard electrical equipment and systems maintenance and testing experience, with an extensive background in electrical safety and power systems analysis. He is an active member of IEEE, ASSE, AFE, IAEI, and NFPA. He is a Certified Plant Engineer (CPE) and a Certified Electrical Inspector-General. Mr. Neitzel earned his Bachelor’s degree in Electrical Engineering Management and his Master’s degree in Electrical Engineering Applied Sciences. He is a Principle Committee Member and Special Expert for the NFPA 70E, Standard for Electrical Safety in the Workplace; member of the Defense Safety Oversight Council, Electrical Safety Working Group – DoD Electrical Safety Special Interest Initiative; Working Group Chairman of IEEE 3007.1-2010 Recommended Practice for the Operation and Management of Industrial and Commercial Power Systems, 3007.2-2010 Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, & 3007.3-2012 Recommended Practice for Electrical Safety of Industrial and Commercial Power Systems; Working Group Chairman of IEEE P45.5 Recommended Practice for Electrical Installations on Shipboard - Safety Considerations; and co-author of the Electrical Safety Handbook, McGraw-Hill Publishers. Mr. Neitzel has also authored, published, and presented numerous technical papers and magazine articles on electrical safety, maintenance, and training. For more information, contact Mr. Neitzel by e-mail at [email protected].

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DEVELOPING AN “ELECTRICAL” MULTI-EMPLOYER WORKSITE PROTECTION PROGRAM PowerTest 2014 Don Brown, Sr. Program Developer, Shermco Industries Before we start talking about the development of an “electrical” multi-employer worksite policy, we have to determine whether or not you are responsible for the safety of employees other than your own. In order to do this, you must ask yourself a couple of simple questions. ● Are you the ONLY employer on your property? ● Are you responsible for any contract employees on your property? In most cases, you are not the only employer on the jobsite, and you could be working as a subcontractor for another company. In either case, you are always responsible for the safety of your own employees. How could you be held responsible for the safety of employees that are not your own? In order to determine this, we must look at the definition of a multi-employer worksite. According to the Advisory Committee on Construction Safety and Health (ACCSH): Multi-employer Worksites: A worksite at which two or more entities are performing tasks that will contribute to the completion of a common project. The entities may or may not be related contractually. The contractual relationship may or may not be in writing. On multi-employer worksites, both in construction and industry, more than one employer may be citable for the same condition. In a Letter of Interpretation dated July 20, 2012, OSHA does not use the definition suggested by ACCSH, as that committee advises OSHA on only construction related issues. However, in a more broad sense, a multi-employer worksite is one that has more than one employer performing work toward a common goal, whether that is a daily function of operations, or on a construction site. Now that we have determined that you are on a multi-employer worksite, let’s see what type of employer you are. There are four classifications of employers in this scenario – the creating employer, the exposing employer, the correcting employer, and the controlling employer. Let’s define each one before getting into developing the electrical portion of the program. ● The Creating Employer – The employer that causes a hazardous condition that violates an OSHA standard. ● The Exposing Employer – An employer whose own employees are exposed to the hazard. ● The Correcting Employer – An employer who is engaged in a common undertaking, on the same worksite, as the exposing employer and is responsible for correcting a hazard. This usually

occurs where an employer is given the responsibility of installing and/or maintaining particular safety/health equipment or devices. ● The Controlling Employer – An employer who has general supervisory authority over the worksite, including the power to correct safety and health violations itself or require others to correct them. Control can be established by contract or, in the absence of explicit contractual provisions, by the exercise of control in practice. Now that we have the definitions clarified, let’s look into the liability, or the potential for citations to be issued in each case. In order to have an employer issued a citation by OSHA for a hazardous condition, there must be a two-step process to determine whether only one employer will be cited, or if more than one employer will receive the citation. Keep in mind that a single employer may fall into multiple categories with regard to the same scenario. ● Step One – The first step is to determine whether the employer is a creating, exposing, correcting, or controlling employer. Since we have already defined each of these, you can determine relatively easily which category the employer falls under. ● Step Two – Step two is to determine if the employer’s actions were sufficient to meet the obligations under the OSHA requirements. The extent and type of action required by an employer will vary depending on the category that applies. In many cases, you will fall under more than one category of employer. That is, a creating, correcting, or controlling employer will most likely also be an exposing employer. Also, if you are an exposing, creating or controlling employer, you may also be a correcting employer if you have the contractual authorization to correct the hazard. Let’s look at a couple of generic scenarios to see what would happen in a given situation.

Scenario #1a You are installing a new 480 VAC distribution panel at a facility for some new equipment. The panel has been properly mounted in accordance with NEC and local codes, power supply wiring has been pulled and has been terminated in the new panel, but has not been terminated at the supply, or feeder, source. No covers are in place, no barricades are set up, and no hazard boundaries have been established to prevent the exposure to other employees in the area. Let’s look at the site of the new panel first. Is there a hazard present, and if so, what is that hazard?

Safety Vol. 1 Since the power has not been connected as yet, there is no exposed energized source of electrical energy, and there is no electrical hazard. In this part of the scenario, there is no liability or citation to be issued.

Scenario #1b However, let’s continue the same scenario. Wiring has been pulled, no covers in place, no barricades and no boundaries have been established. Now we are connecting the source of electrical energy to the feeder breaker. Proper LOTO procedures have been followed as far as the source of energy, all of the proper PPE and electrical safe work practices have been established, and boundaries have been established at the source side of the feeder. All proper work practices have been addressed here, but there are still exposed electrical parts at the new panel. The source wiring is now terminated and the breaker has been closed, feeding power to the new panel. What, if any, is the type and extent of the exposure? What classification type of employer do you fall into at this point? Creating, exposing, correcting, or controlling? Identify the hazard first. There is the hazard of exposed, energized parts at 480 VAC, so there is a shock hazard, as well as an arc flash hazard. As you are the employer that energized the conductors without proper barricading, leaving the panel covers off and the internal parts exposed, you fall into two different categories – creating and correcting. What about exposing? At this point you are not an exposing employer as none of your employees are at the new panel location. However, there are potentially other employees at that location. Once your employees arrive at the new panel, you are now an exposing employer. Can you be considered the controlling employer at this point? By definition, if you are the primary, or general, contractor, you could be considered the controlling employer. If you are a subcontractor, no you cannot be considered the controlling employer. So at what level does the citation come in? In this situation, if you are not the controlling employer, you would be cited as the creating employer. You created the exposure, or hazard, therefore you would receive the citation as such.

Scenario #2 You have contracted to perform work at XYZ refinery during one of their periodic shut-down/turnaround overhauls. During this turnaround, it is the responsibility of your company to test substation transformers, switchgear, breakers, and relaying equipment. You have performed this type of testing many times before, and several times with this particular company. While testing one of the substation transformers, one of your testing technicians sets up all of the appropriate barricades, signage, and completes all of the required pre-testing paperwork, such as the JHA, LOTO, etc. The technician connects the test leads to the transformer properly and energizes the test set. When he began the test, he was sitting on one of the bushings, and when he pushed the test buttons to begin the test, he received an electrical shock to the buttocks.

35 What, if any, is the type and extent of the exposure? What classification type of employer do you fall into at this point? Creating, exposing, correcting, or controlling? What classification does XYZ refinery fall into at this point? What type of citation, if any, will XYZ Refinery receive after this incident? Why? Your company would fall into the creating and exposing categories, and could likely receive a citation as the creating employer. XYZ refinery is the controlling employer. However, they exercised reasonable care and determined that your company had the technical expertise, safety knowledge and had implemented safe work practices. They were relying on you, the industry expert, to exercise all of the proper precautions for the testing and provide trained, qualified persons to conduct the tests. They were therefore not citable for the violation of improper work practices. These are just two potential scenarios that arise on a fairly frequent basis. There are many other possibilities that could arise during this type of work environment. However, one thing to be concerned with is your level of responsibility during a visit from an OSHA compliance officer following an accident, or worse, a fatality on your worksite. One thing we have all heard about time and time again is the necessity for documentation. This is not only true for your employees, but for any contractors that work for you, whether they are job-specific or imbedded within your company. Job-specific contractors are those that come onto the site for a particular job, finish the work, then leave. They are on site for a relatively short amount of time. That could be anywhere from one day to several weeks, depending on the scope of work. Imbedded contractors are those whose normal place of work is your facility. These types of contractors could be those such as facility security, facilities maintenance, or any of a number of other contractors. How can you be held responsible for those employees? Aren’t they being paid by someone else? Isn’t their company responsible for their safety? Let’s take a look at just how you can be held accountable for someone else’s employee. One of the first things you should do when setting out to find a contractor to perform work at your facility, whether it is temporary or long-term, is to make sure that their safety program at least meets your safety program requirements. You do this by having them provide you with a copy of it! If your review of their safety program meets your company’s safety program, it is time to move to the training program to make sure that the employees have had all of the required safety and equipment training that is necessary for your facility. Make sure the training is all documented and it meets the most recent standards and regulations. For example, if someone has a copy of a certificate in their training record that proves they attended NFPA 70E training, but it is from the 2004 edition, the training is out of date, since the standard has gone through two additional revisions since that time. NFPA 70E-2012 Article 110.2(D)(3) states that “Retraining shall be performed at intervals not to exceed 3 years.” Likewise, if someone says they

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have attended the NFPA 70E – 2012 training, but there is no clear documentation in their training record, then they did not attend the class. If they can’t prove that they attended the class, then they did not attend the class. Additionally, if someone is supposed to perform testing on a particular piece of electrical equipment, they need to have been trained in the use of the test equipment, and that training has to be documented in their training record per NFPA 70E-2012 Article 110.2(E) Otherwise, there is no way to prove that they are performing the testing properly and will be able to interpret the testing and diagnostics properly. This could lead to a failure of the equipment and potentially an injury, or worse, to an employee. Once the training documentation has been verified, one of the next steps is to inform each of the contractors of the hazards that they may be facing. Whether this is created by them during the work, or by other contractors performing work in the vicinity, these hazards, or potential hazards, must be communicated. NFPA 70E-2012 Article 110.1 discusses the relationships with contractors and the responsibilities of both the host employer and the contract employer with regard to electrical related work practices. One of the easiest ways to communicate the hazards on the worksite is by holding daily safety meetings among the safety personnel. Each company safety representative comes to the meeting before work starts each day with a scope and location of work that their company will be performing. That way, everyone is aware of the potential hazards in a given area and that information can be relayed to their respective companies. This is then used during each work team’s JHA before work begins. Communicating all of the training and hazards on a jobsite is a primary concern not only for facility owners, but for on-site contractors as well. Failure to communicate, or ignoring the hazards can not only cause injuries to workers and damage to equipment; it can also result in criminal and civil actions. Post fatality inspections conducted by OSHA during the period of 2007 through 2010 have resulted in 49 criminal referrals or significant aid to prosecutors. These are broken down as follows: ○ 2007 – 10 referrals ○ 2008 – 14 referrals ○ 2009 – 11 referrals ○ 2010 – 14 referrals In an article in The National Law Review, December 12, 2013 (Criminal Charges Follow Fatal Workplace Accidents), stiff OSHA fines are not the only thing facing employers following fatal workplace accidents. The owner of one company is going to prison, while another owner faces multiple murder charges! In one case, the president and owner of a business in New Hampshire was sentenced to 10 to 20 years in prison after a conviction of two counts of manslaughter. These counts stem from an explosion at a gunpowder-substitute manufacturer that resulted in the deaths of two employees.

In another case, which is being investigated, the district attorney has filed murder charges against a contractor over a building collapse that killed six people and injured 13 others. The contractor faces six counts of third-degree murder, six counts of manslaughter, and 13 counts of recklessly endangering another person. The contractor is not the only person facing criminal prosecution. Charges are also being made in the same case against an excavating contractor. The charges in this part of the case are six counts of involuntary manslaughter and 13 counts of reckless endangerment. In this case, in addition to the criminal prosecution, OSHA has proposed $397,000.00 in penalties against the two companies. Criminal prosecutions are not limited to the construction and general industry business sector. Charges have been brought and convictions have been obtained in connection with a mining tragedy in 2010 that killed 29 West Virginia miners. You see, not only do businesses get fined and sanctioned because of unsafe work place situations and actions. The business owners and other responsible parties are being held accountable as well. These criminal charges and convictions do not take into consideration the civil litigation that could take place. In conclusion, let’s look at not only the safety of the workers, as that itself should be enough to make someone be concerned. You must also look at the impact that a violation could have on the owner and safety professional on a jobsite or facility. Criminal prosecution, incarceration, and civil penalties are all possibilities that could arise from an accident or fatality. Add to that the legal action that could be taken by the families of the victim and you just end up complicating the problem. Keep everyone’s safety at the forefront each and every day. Look out for them and maybe, just maybe, they will look out for you.

REFERENCES OSHA Instruction CPL 02-00-124, OSHA’s Multi-Employer Citation Policy NFPA 70E-2012, Standard for Electrical Safety in the Workplace OSHA Regulations, 29CFR1910.331 - .335, Electrical Safety Related Work Practices National Law Review, December 12, 2013, Criminal Charges Follow Fatal Workplace Accidents Don Brown is the Senior Programs Developer for Shermco Industries in Irving, Texas. He has been in the electrical industry for over 40 years and has been implementing and training electrical safety for the last 15-plus years. Mr. Brown just completed his certification through NFPA as a Certified Electrical Safety Compliance Professional (CESCP). He has written electrical safety programs for large data centers, petrochemical facilities, and manufacturing facilities, and is in the process of updating many of these to include the upcoming changes in the NFPA 70E—2015 Edition.

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PERSONAL PROTECTIVE GROUNDING NETA World, Fall 2015 Issue Jeff Jowett, Megger It is a common expression in firearm safety that many a person has been killed by an unloaded gun. This, of course, refers to the consequences of carelessness or inattention to detail. The electrical industry has a clear parallel in the de-energized circuit; in ordinary speech, the equipment or circuit that has been (supposedly) turned off. Even when effectively isolated from its own power source, electrical equipment in high-energy environments like switchyards and substations can still develop dangerous voltages from induction by nearby live circuits, as well as what the utilities refer to as an “event” — an unexpected rise in voltage from a disturbance on the line such as a lightning stroke. An indispensable safeguard against such contingencies is the installation of protective grounds. The description and implementation of protective grounding has been well established by organizations such as OSHA. Personal protective grounds provide maximum safety for personnel working on de-energized systems or equipment by equalizing voltage differences at the worksite (Figure 1). The aim is to keep the voltage across the worker at a safe level in the event of the equipment or system becoming accidentally energized from any possible source. Personal protective grounds dissipate static voltages and protect against induced voltages from adjacent energized systems. In addition, they enable protective devices to trip as quickly as possible. Personal protective grounding prevents accidental death or injury by minimizing the magnitude and duration of shock hazard.

OSHA 1910.333(c)(3) states: If work is to be performed near overhead lines, the lines shall be de-energized and grounded, or other protective measures shall be provided before work is started. If the lines are to be de-energized, arrangements shall be made with the person or organization that operates or controls the electric circuits involved to de-energize and ground them. The requirements for compliance on transmission and distribution lines are addressed in OSHA 1910.269(n). The application of grounds shall create an equipotential zone protecting the employee. The grounds shall be capable of conducting the maximum available fault current at the grounded point for the time necessary to clear the fault; the ampacity of a 2 AWG copper conductor is the minimum. The circuit must be de-energized and tested for absence of nominal voltage before grounds are installed. The ground end of the grounding conductor must always be installed first, and then the other end is connected to the equipment to be serviced, using a live-line tool. Conversely, when the protective grounds are removed upon completion of the task, the conductor-end connection is removed first, again using a live-line tool. When working on cables at a location remote from the terminal end, the terminal end may not be grounded if the possibility of hazardous transfer of potential exists. During testing procedures, if grounds need to be removed for test implementation, workers must use insulating equipment and be isolated from any hazard. Situations may also arise where the installation of protective grounds is impracticable or would present greater hazards than working without. In such cases, the installation of protective grounds may be excused. As described in 1910.269(n)(2)(i)-(iii), lines and equipment may be treated as de-energized, provided three conditions are met: (1) Assurance that lines and equipment are de-energized under the provisions of paragraph (m) of this section, (2) no possibility of contact with another energized source exists, and (3) the hazard of induced voltage is not present. Proper sizing of personal protective grounds is critical and must be implemented in detail because protective grounding doesn’t merely contend with nominal current but also must be adequate for all available fault current. Protective grounds must be capable of withstanding all electrical and electromagnetic stresses. The requirement can be implemented with a three-step process:

Fig. 1: Consequences of Protected and Unprotected Circuits

● Step One – Calculate the maximum available fault current for all interconnection points throughout the electrical system in question. Relative information includes the utility interconnection, transformer sizes and impedances, and conductor sizes and lengths. It may be presented in the form of a single

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Safety Vol. 1 line diagram, with symmetrical and asymmetrical fault currents noted for each bus.

● Step Two – Determine the appropriate type and size of grounding conductors for each system part. Appropriate grounding conductor size is then incorporated into the Lock Out/Tag Out procedures. ● Step Three – Thoroughly inspect grounding equipment prior to each use. Clamps, ferrules, serrated jaw inserts and the like should be inspected for tightness. The standard for inspection and test is ASTM F-2249, Standard Specification for In-Service Test Methods for Temporary Grounding Jumper Assemblies Used on De-Energized Electric Power Lines and Equipment. This consists of three parts: (1) Testing grounding jumper assemblies on a time interval established by the user to ensure defective assemblies are removed from service in a timely manner; (2) retesting after performing any maintenance that may have affected the integrity of the assembly; and (3) retesting again after any assembly may have been subjected to short circuit or lightning surge. Sometimes conflicting information exists in the literature on the effects of current on the human body, but significant early research conducted by Charles Dalziel in the 1940s culminated in the formula:





I = k/√t

Where I = current (amps), k is a function of shock energy, and t is time (seconds). The formula indicates a time/current relationship, which is expressed as function of shock energy. The effect on the human body is based on the amount of current and the duration of exposure, such that k50 is 116 for a 110-lb body, and k70 is 157 for a 155-lb body. The formula can calculate current magnitude for heart fibrillation, producing a time/current curve as seen in Figure 2. Human body resistance is placed from 500 to 1000 ohms, hand to foot or hand to hand. This figure is profoundly affected in work situations by the wearing of insulating gloves and boots. But a contravening factor is that reclosers may not have been disabled, with short intervals between reclose not allowing the body to recover from a first shock before receiving a second. Shocks above the 600 V level may further reduce body resistance by puncturing the skin, thereby exposing internal organs, which have less resistance to higher current levels.

Fig. 2: Heart Fibrillation Time vs. Current An example: A worker with a 110-lb body weight could receive a shock of 67 mA for three seconds before going into heart fibrillation, whereas a 155-lb worker would tolerate 91 mA for three seconds.

Fig. 3: Electrical Equivalent of Jumper

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Safety Vol. 1 Accordingly, the protection afforded by Personal Protective Equipment (PPE) grounds is designed to reduce voltage drop across the worker’s body well below the value that would produce fibrillation, burns, or other injury. A successful equipotential grounding method places the worker in a parallel path with a jumper of sufficiently low resistance to divert all but a harmless level of current around, as opposed to through, the worker (see Figure 3). Voltage rise across the worker is minimized, while fast clearing of protective devices is effectively implemented. The jumper must have adequate ampacity to maintain a low resistance during the fault clearance. The design of PPE grounding, therefore, must ensure that heart fibrillation current will never be reached under system fault conditions. Critical data is provided in Table 1, regarding the ampacity and resistance of various sizes and types of grounding conductors. A worst-case scenario is also provided in Table 1 because it would require significant calculations to determine dc offset and X/R ratio for various load and short-circuit situations. Updated Short Circuit and Coordination Studies are necessary to determine adequate sizing.

Table 1: Current Carrying Capabilities of Copper Grounding Cable The next column in NETA World will continue with description of the parameters for safe and effective grounding equipment.

REFERENCES Dalziel, Charles F., The Effects of Electric Shock on Man, IRE Trans. on Medical Electronics (PGME-5), May 1956. AVO Training Institute, Dallas, Texas Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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HUMAN ERROR AND SAFETY NETA World, Fall 2015 Issue Paul Chamberlain, American Electrical Testing Co., Inc. What is human error? Human error is the outcome of an action that does not produce the human’s intended result(s). It can be summed up by saying things did not go as planned. James Reason stated, “Human error is a consequence, not a cause. Errors are shaped by upstream workplace and organizational factors… Only by understanding the context of the error can we hope to limit its reoccurrence.”

No matter where the need to rush comes from, there must always be the need to push back and realize that this time pressure can lead to a mistake. Take the time to slow things down; it is quicker to do things right once, then to do it wrong and have to do it a second time.

The 6 P rule (Proper Prior Planning Prevents Poor Performance) can go a long way to preventing a human error, but there is still that human factor. Human beings are fallible and make mistakes. Those mistakes are usually caused by only a few factors.

Being distracted either mentally or physically can lead to a lapse of judgement or a missed step. When doing something critical that requires intense awareness, always ensure that distractions are kept to a minimum. In this technological day and age, cellular phones are a major distraction. Make it a habit to power them down or put them elsewhere and on vibrate whenever doing something critical. Cell phones are a good example of mental and physical distraction. Using a phone requires a physical interaction to enable a call and to have a conversation with the caller. Mentally, a caller is required to engage in the conversation and make judgement calls or opinions based upon the information the caller is sending or receiving.

TIME PRESSURE When employees rush to complete a project or a task, they can have a lapse of judgement. Missing steps, improper communication, and failing to recognize warning signs are just a few of the issues that can occur when rushing. Being in a rush is caused by either internal or external forces. Internal could mean a need to get home at the end of the day or scheduling conflicts with the individual’s personal life. A good example of external forces is a critical project that needs to be completed by the end of the week, but has been delayed due to rain. Perhaps internal forces are in play for the employee working on the project because his son is scheduled to pitch his first high school baseball game that Friday evening, but the work is still unfinished. To make it to the game for the first pitch, the employee completes his tasks for the day quickly. Hopefully, rushing through the work does not produce any mistakes — but it can. And those mistakes can lead to incorrectly operated equipment, potential injuries, or worse.

DISTRACTIONS

Other distractions can include a change in work shift, which can contribute to tiredness and dulled senses. If the weather changes drastically from hot to cold or vice versa, it can be a distraction. Distractions can also come from outside the work environment. Trouble at home, kids getting bad grades, and money issues all contribute to a mental distraction, which can be detrimental in the work environment. It is a good idea to always ensure that any distraction, whether a phone or not, is minimized during any act where improper action can cause significant consequences.

External time pressure can occur when a boss or peer is pressuring another employee to complete the work quickly. Maybe they need to move on to another location or task, or maybe there is only a limited outage window that was impacted by some external force (e.g. other contractors eating up outage time). Be aware of Mondays and Fridays. On Mondays, some employees may not be fully recovered from a full and exciting weekend. This can cause mental lapses in judgement due to being tired or not fully engaged in the work. On Fridays, they may be in a rush to get out the door and start an exciting weekend, causing mental disengagement with the task. Mental disengagement is not exclusive to Mondays and Fridays; it also applies after any prolonged absence from work, such as before and after long weekends, vacations, layoffs, etc.

Table 1: Phonetic Alphabet

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Safety Vol. 1 COMMUNICATION

THE BIG PICTURE

Ensuring that a message is properly sent and received is critical. Using the phonetic alphabet and numerals is necessary when communicating equipment identifications or other nomenclature (see Table 1). This prevents peers and other employees from going to the wrong equipment or potentially using incorrect or misheard settings.

All of the previous human conditions contribute to an employee or peer making an error. The first and most effective means of reducing that error is to first be fully engaged in the task at hand. Identify those things that may be a distraction or may contribute to a mistake, and eliminate those items from the work task. Many accidents occur because the employee continued blindly on in a task without heeding any of the little warning signs that may occur. When something doesn’t seem right, stop, take a step back to reevaluate, and ask questions of the team performing the work. Find out why things aren’t right, and heed those little warnings. Be cognizant of any internal problems and acknowledge that they may affect the work — and discuss that with fellow workers. Doing this will minimize the possibility of a problem occurring.

It is always a good idea to use a three-part communication when doing critical tasks. Three-part communication consists of: ● A sender saying a direction or information ● A receiver repeating the information verbatim ● The sender acknowledging that the information is correct If the information is repeated back incorrectly, then the sender states that the information is incorrect, and then repeats step 1. Using three-part communication ensures that the message sent is the message received. As a receiver of information, it is also important to get all the information needed to successfully complete the task. This means that everything needs to be questioned. Question why certain test procedures are used, question why there was a lockout performed and by whom and when. To ensure that the big picture is achieved, get an understanding of all aspects of the job. As the sender of information, ensure that the receiver truly understands what is necessary. Emphasize and repeat the steps needed and the results expected. Write it down and give notes to the receiver. This ensures that there is complete understanding, whether it is between members of a work crew or if turnover of work is conducted from one work group to another.

PLACE KEEPING Place keeping is used to mark the steps in a procedure or work document that have been completed so that steps are not accidentally omitted or repeated. Use place keeping when using a procedure or work document to perform critical activities. When suspending performance of a procedure, place keeping is used to identify the last step completed. Prior to restarting the work, conduct a thorough re-review of the procedure.

FLAGGING AND OPERATIONAL BARRIERS Flagging involves highlighting a component to improve the chances of performing actions on the correct component. Operational barriers are used to mark or cover components that are not to be worked on or manipulated during an evolution. Flagging and operational barriers are particularly helpful when several similar components are in close proximity to those affected by the work activity. Research indicates that several events can be attributed to an individual starting an activity on one component, taking a break or becoming otherwise distracted from the component, and returning only to perform manipulations on the wrong component.

Simple, everyday tools can help mitigate human fallibility. Taking notes with pen and paper is the old-school, tried-and-true method. Using laptops and scheduling programs are a newer methodology. Write things down so they won’t be forgotten, either on paper or electronically. Come up with plans and procedures for the task, and write them down step by step before the work begins. This helps ensure that the right skills, tools, equipment, and personnel are present for the work. Pre-job briefings are an effective means of documenting and communicating steps as well as hazards on the job. The more complex or unfamiliar a task is, the more complex the pre-job briefing must be. Ensure that all people affected by the task attend the pre-job briefing. This can include other contractors not directly involved in the scope of work but who are in or near the work area where the task is being performed. Being aware of all contributing factors and planning for their mitigation helps make the work environment safer for all. Everyone makes mistakes, but we can identify and minimize the factors that contribute to those mistakes. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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POWER TRANSFORMER HAZARD AWARENESS NETA World, Winter 2015 Issue Scott Blizard, American Electrical Testing Co., Inc. Performing a condition analysis or maintenance on a power transformer and auxiliary devices is a hazardous task that requires an experienced individual with a solid ability to identify potential hazards and mitigate risks. Condition analysis of a power transformer may be performed using methods and products designed to test and diagnose the equipment when it is operating, such as infrared survey, partial discharge detection equipment, and online oil analysis. The Personal Protective Equipment (PPE) required should be appropriate and adequate for all tasks performed. This article is an overview of some of the potential hazards of a power transformer and various means of safeguarding as well as mitigation of those hazards. This article does not include every potential hazard, but rather, explores some potentially hazardous situations that can occur while performing work on a power transformer and auxiliary equipment. Additional hazards may exist, depending on the type or condition of the equipment. Take all procedures and instructions seriously, and verify that the instruction or equipment operation and maintenance manuals used are for the correct equipment. Check for and identify potential hazards prior to beginning every task by using a Pre-Job Brief worksheet.

ELECTRICAL AND MECHANICAL HAZARDS Improper Lock Out/Tag Out (LO/TO) is a major contributing factor to injuries caused by power transformers and auxiliary devices. Controlling hazardous energy is essential, and many forms of energy may be involved. To determine the proper LO/TO procedures, always refer to the appropriate OSHA regulation or required procedure, such as 29 CFR 1910.147 and .333, as well as manufacturer instructions. Electricity is the most obvious hazardous energy source. Electrically de-energize the power transformer and auxiliary devices from their primary energy source and ensure the equipment is disconnected from all sources of power, both ac and dc, if applicable. Once de-energized, verify that the equipment is at a zero energy state using the manufacturer’s approved method. Verify the accuracy of the detection or voltage measuring device against a known source, check for zero energy on the de-energized equipment, and then test the detection equipment against a known source again. This will verify that the detection meter used was functioning properly during the initial check. Testing for voltage will require its own level of PPE, depending both upon the voltage level and arc-flash hazard level and test procedures per NFPA 70E 2015 — Standard for Electrical Safety in the Workplace or OSHA 29 CFR 1910.269 — Electric Power Generation, Transmission, and Distribution regulation.

Electrical energy isn’t the only energy that requires LO/TO. Devices such as motor-operated switches and circuit breakers and others may contain a large amount of mechanical energy. This energy must be dissipated prior to servicing the equipment or serious injury could occur. Once the energy has been discharged or dissipated, LO/TO the source of the stored energy, if feasible. Ensure that remote operating handles are tagged in a local or manual mode. This will prevent someone from inadvertently operating the equipment.

CHEMICAL HAZARDS Certain types of power transformers may also pose a chemical hazard; take caution with gases, chemicals, and liquids. Use proper containment of liquids (e.g. spill containment pads) and address environmental concerns. Ensure compliance with all owner, state, and federal regulations. Beware of units containing Polychlorinated Biphenyls (PCBs) or other hazardous fluids. When working on such units, follow appropriate state and federal guidelines for fluid handling and disposal, and avoid skin contact. Some cleaners may pose a respiratory and skin irritant if used in enclosed areas or on bare skin. Gain knowledge of the material and check the applicable Safety Data Sheet (SDS) to identify any potential health effects from its use. Once again, proper PPE is necessary for using some cleaners; for example, nitrile gloves, safety glasses, face-shield, and even respiratory protection may be needed.

CONFINED SPACE When performing the visual inspection, mechanical inspection, maintenance, or repairs on a power transformer, personnel may be required to enter the actual tank. Entering into a confined space requires the entrant to be aware of the conditions within that space. The entrant needs to first ask: Is this confined space located at a facility regulated by the OSHA 1910.269 Electric Power Generation, Transmission, and Distribution regulation, or is it a commercial entity or space regulated under OSHA 1910.146 (permit-required confined spaces regulation)? These OSHA regulations have different requirements, depending on the location of the space and its hazards. OSHA has created a flow chart to help with that determination, located within OSHA 1910.269 Appendix A. This flow chart is shown in Figure 1 and can also be viewed at http://tinyurl.com/ p329zxo.

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● The entrant must also determine if, under 1910.269, the space is considered an “enclosed space.” ○ Enclosed space: A working space, such as a manhole, vault, tunnel, or shaft, that has a limited means of egress or entry, that is designed for periodic employee entry under normal operating conditions, and that, under normal conditions, does not contain a hazardous atmosphere, but may contain a hazardous atmosphere under abnormal conditions.

Fig. 1: Appendix A-5 to §1910.269 — Application of §§1910.146 and 1910.269 to Permit-Required Confined Spaces To answer the questions on the flow chart, the entrant must know the following from the OSHA regulations. ● OSHA 1910.146(b) defines a confined space. ○ “Confined space” means a space that: – Is large enough and so configured that an employee can bodily enter and perform assigned work; – Has limited or restricted means for entry or exit (for example, tanks, vessels, silos, storage bins, hoppers, vaults, and pits are spaces that may have limited means of entry.); – Is not designed for continuous employee occupancy. ● OSHA 1910.146(b) describes when the confined space requires a permit to enter. ○ “Permit-required confined space (permit space)” means a confined space that has one or more of the following characteristics: – Contains or has a potential to contain a hazardous atmosphere; – Contains a material that has the potential for engulfing an entrant; – Has an internal configuration such that an entrant could be trapped or asphyxiated by inwardly converging walls or by a floor which slopes downward and tapers to a smaller cross-section; – Contains any other recognized serious safety or health hazard. ● The entrant must know if the work to be performed falls under the scope of the 1910.269 regulation — put simply, if that work is conducted during the operation and maintenance of electric power generation, control, transformation, transmission, and distribution lines and equipment. Specific information on that definition may be found in all of 1910.269(a)(1).

○ Note to the definition of “enclosed space”: The Occupational Safety and Health Administration does not consider spaces that are enclosed but not designed for employee entry under normal operating conditions to be enclosed spaces for the purposes of this section. Similarly, the Occupational Safety and Health Administration does not consider spaces that are enclosed and that are expected to contain a hazardous atmosphere to be enclosed spaces for the purposes of this section. Such spaces meet the definition of permit spaces in §1910.146, and entry into them must conform to that standard. ● The entrant must also know the potential hazards within the space that must be controlled prior to entry in a 1910.269 regulated enclosed space. For more information regarding those hazards, see all of 1910.269(e).

OTHER PHYSICAL HAZARDS When performing the visual inspection, mechanical inspection, maintenance, or electrical tests on a power transformer, gravity is an energy that may also need to be controlled. The size and weight of panel covers and inspection plates may make them difficult to handle. Should gravity be a potential energy source, ensure that the energy is dissipated and controlled as part of the LO/TO procedure.

IMPROPER PPE HAZARDS After verification that the power transformer is de-energized, the method of disconnecting the equipment may require a different form or class of PPE. Ensure that proper PPE is used for the class of disconnecting means. Refer again to the NFPA 70E 2015 or OSHA 1910.269. They will indicate what level of protection is required, depending on the task and within certain levels of exposure. Identifying the correct level of PPE and gloves will aid in the mitigation of injury from a potential arc flash. However, the table within NFPA 70E only provides information based on known values of the short circuit current available, the clearing time in cycles, and minimum working distance. If those factors are unknown, more information must be gathered prior to performing the work to ensure personnel safety. Table 1 provides the approach boundaries from NFPA 70E. It indicates at what proximity to the alternating-current, energized equipment that the PPE must be donned.

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(1)

(2)

Nominal System Voltage Range, Phase to Phasea

(3) Limited Approach Boundaryb

(4) Restricted Approach Boundaryb; Includes Inadvertent Movement Adder

Exposed Movable Conductorc

Exposed Fixed Circuit Part

Not Specified

Not Specified

Not Specified

50 V to 150 V

3.00 m (10 ft. 0 in.)

1.0 m (3 ft. 6 in.)

Avoid Contact

151 V to 750 V

3.00 m (10 ft. 0 in.)

1.0 m (3 ft. 6 in.)

0.3 m (1 ft. 0 in.)

751 V to 15 kV

3.00 m (10 ft. 0 in.)

1.5 m (5 ft. 0 in.)

0.7 m (2 ft. 2 in.)

15.1 kV to 36 kV

3.00 m (10 ft. 0 in.)

1.8 m (6 ft. 0 in.)

0.8 m (2 ft. 7 in.)

36.1 kV to 46 kV

3.00 m (10 ft. 0 in.)

2.5 m (8 ft. 0 in.)

0.8 m (2 ft. 9 in.)

46.1 kV to 72.5 kV

3.00 m (10 ft. 0 in.)

2.5 m (8 ft. 0 in.)

1.0 m (3 ft. 3 in.)

72.6 kV to 121 kV

3.00 m (10 ft. 0 in.)

2.5 m (8 ft. 0 in.)

1.0 m (3 ft. 4 in.)

138 kV to 145 kV

3.4 m (11 ft. 0 in.)

3.0 m (10 ft. 0 in.)

1.2 m (3 ft. 10 in.)

161 kV to 169 kV

3.6 m (11ft. 8 in.)

3.6 m (11ft. 8 in.)

1.3 m (4 ft. 3 in.)

230 kV to 242 kV

4.0 m (13 ft. 0 in.)

4.0 m (13 ft. 0 in.)

1.7 m (5 ft. 8 in.)

345 kV to 362 kV

4.7 m (15 ft. 4 in.)

4.7 m (15 ft. 4 in.)

2.8 m (9 ft. 2 in.)

500 kV to 550 kV

5.8 m (19 ft. 0 in.)

5.8 m (19 ft. 0 in.)

3.6 m (11 ft. 10 in.)

765 kV to 800 kV

7.2 m (23 ft. 9 in.)

7.2 m (23 ft. 9 in.)

4.9 m (15 ft. 11 in.)

>50 V d

Table 1: NFPA 70E 2015 Table 130.4(D)(a)) — Approach Boundaries to Energized Electrical Conductors or Circuit Parts for Shock Protection for Alternating Current Systems Note 1: For arc flash boundary, see 130.5(A). Note 2: All dimensions are distance from exposed energized conductors or circuit part to employee. ● For single-phase systems, select the range that is equal to the system’s maximum phase-to-ground voltage, multiplied by 1.732. ● See definition in Article 100 and text in 130.4(D)(2) and Annex C for elaboration. ● Exposed movable conductors describe a condition in which the distance between the conductor and a person is not under the control of the person. The term is normally applied to overhead line conductors supported by poles. ● This includes circuits where exposure does not exceed 120V. Again, the PPE must be adequate for the task and energy levels, and worn prior to entering within the Restricted Approach Boundary. Additional tables exist for direct-current energized equipment.

INSTALLATION OF TEMPORARY PROTECTIVE GROUNDS Grounds are an excellent secondary means of protecting the worker from inadvertent energization. Refer to any applicable

OSHA regulation such as 29 CFR 1910.269, NFPA 70E, and ASTM F855 for specific guidance on grounding locations and sizing of grounds required for the task. Grounds must always be applied upstream and downstream of the equipment and as close to the work as possible. Using correctly sized and applied grounds is an additional safeguard for employees should there be a form of electrical energy introduced into the system or equipment being worked on. Induced voltage or back-feed are just two forms of energy that may be inadvertently introduced into a system that has been properly Locked Out/ Tagged Out.

IN CONCLUSION When performing maintenance and testing on a power transformer, take care of the following: ● Obtain all service bulletins, maintenance documents, arc-flash studies, and manuals prior to working on that specific device. ● Review all prints and one-lines associated with the equipment. ● Establish a safe work area, and barricade off the work area. ● Perform a pre-job brief with all employees on-site. ● Wear proper PPE.

Safety Vol. 1 ● Disconnect the electrical feed and control circuit(s), verify mechanical interlocks are properly engaged, and test equipment before performing visual or mechanical inspections. ● If applicable, verify that there is zero energy (test, check, test), and discharge all stored energy, including pressurized gasses and gravity. ● Complete the Lock Out/Tag Out (for all energy sources). ● Connect grounds where and /if applicable. ● Identify, visually mark, or flag the equipment being worked on. Being aware of and mitigating the hazards listed here can lead to a safer work environment while performing inspection, maintenance, and testing of a power transformer. Scott Blizard has been the Vice President and Chief Operating Officer of American Electrical Testing Co., Inc. since 2000. During his tenure, Scott acted as the Corporate Safety Officer for nine years. He has over 25 years of experience in the field as a Master Electrician, Journeyman, Wireman, and NETA Level IV Senior Technician.

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UNDERSTANDING AND IMPLEMENTING THE ANSI/NETA ECS-2015 STANDARD FOR ELECTRICAL COMMISSIONING SPECIFICATIONS PowerTest 2015 Lorne Gara, Orbis Engineering and Ron Widup, Shermco Industries Whether installing, upgrading, or expanding an electrical system the ultimate goal is for the system to be safe and reliable. All components in the system have to be safe and reliable, this includes the design, engineering, equipment, wiring, and construction. Although there are many different methods to safeguard the installation and prove safety and reliability, the most important is the acceptance tests and commissioning. The International Electrical Testing Association (NETA) recognized that electrical commissioning has not been well defined in the industrial and utility markets, though there is a greater degree of documentation and guidance within the building and data center sectors. This was one of the motivations for NETA to develop an electrical commissioning specification that was apt to apply on a global basis to many industries, and thus the NETA commissioning standard was developed and approved as a consensus-based standard. NETA has developed a new electrical testing standard, the ANSI/ NETA ECS-2015 Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems (NETA ECS). No matter what type of industry sector you are in, when it comes to electrical power equipment it is important that you understand the processes and procedures that take place from a system’s initial concept to final acceptance and energization at your facility. Whether it is a steel mill, refinery, paper mill, electrical utility, data center, hospital, commercial building…the list goes on and on. Regardless of the industry, all require the individual pieces of electrical equipment to interconnect with each other and work together as a system if safety and reliability is to be assured. The difference becomes the complexity of the system and how much interconnection of equipment is required to complete “the system”. After design, procurement, and installation one of the first steps in the commissioning process is performing electrical acceptance testing. It is also important to understand what acceptance testing tasks are meant to accomplish. This is clarified within the scope of the ANSI/NETA document Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems (NETA ATS). The NETA standard states: “These specifications cover the suggest-

ed field tests and inspections that are available to assess the suitability for initial energization of electrical power equipment and systems.” And goes on to say “The purpose of these specifications is to assure that tested electrical equipment and systems are operational, are within applicable standards and manufacturer’s tolerances, and are installed in accordance with design specifications.” The NETA ATS has a section that addresses system functional tests but does not completely address the complexity and requirements of a comprehensive electrical commissioning process. This contributed to the need to develop the new commissioning standard. Acceptance testing tasks are very important, and provide the data necessary to assure the owner that he has electrical equipment that has not only been installed properly but is also functioning as intended and designed. Factory Acceptance Testing ● Manufacturer tests at the factory usually witnessed by the commissioning agent. ● Individual equipment tests very similar to the ANSI/NETA ATS. ● System commissioning tests at this stage will be restricted to how much equipment is connected together and what amount of interconnection wiring is complete. ● It may be possible to get a large amount of the pre-energization tests completed at this stage (example: a switchgear building complete with switchgear, relays, and SCADA systems). Field Acceptance Testing ● Many problems can be created from disassembly, storage, shipping, installation, and construction following the factory tests, all reasons why tests need to be competed in the field. ● It may be necessary to complete some of the field inspections and tests several times during the shipping routes and construction phases. ● Inspections and tests should be completed after lengthy storage times or when poor storage facilities are used (ie: poor weather or poor environment such as salt water or hazardous gases in the atmosphere). ● Inspections and tests should be completed at points of transfer of shipping company or shipping method (ie: barge to rail, rail to truck, truck to laydown yard, laydown yard to final placement).

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Safety Vol. 1 ● Final field tests include individual equipment tests as per ANSI/NETA ATS. ● Complete all of the applicable tests listed in the ANSI/NETA ATS. ● Inspections and tests are completed to assure that tested electrical equipment and systems are operational, are within applicable standards and manufacturer’s tolerances, and are installed in accordance with design specifications.

ELECTRICAL COMMISSIONING Commissioning is the systematic process of verifying, documenting, and placing into service newly installed, or retrofitted electrical power equipment and systems.

DIVISION OF RESPONSIBILITY The NETA ECS states the division of responsibility between the owner and the commissioning organization.

The Owner’s Representative The owner’s representative shall provide the commissioning organization with the following: ● A short-circuit analysis, a coordination study, an arc-flash hazard analysis, and a protective device setting sheet as described in ANSI/NETA ATS, Section 6. ● Most recent version of the electronic setting files for intelligent electronic devices and relay logic diagrams.

Commissioning is critical for all new or retrofit installation projects to verify the correct system operation to the design, thus contributing to the safe and reliable operation of the system.

● Complete set of as built electrical plans and specifications.

THE BASIC FRAMEWORK:

● The factory and field acceptance test reports.

PRE-DESIGN STAGE

● Notification of when equipment becomes available for commissioning work. Work shall be coordinated to expedite project scheduling.

At this stage, the owner should select the commissioning team. The team would work with the owner to develop the owner’s project requirements (OPR), a project schedule, and the commissioning scope and budget.

QUALIFICATIONS The NETA ECS highlights some of the requirements for the qualifications of the commissioning organization and personnel.

Commissioning Organization ● The commissioning organization shall be an independent, third-party entity which can function as an unbiased authority, professionally independent of the manufacturers, suppliers, and installers of equipment or systems being evaluated. ● The commissioning organization shall be regularly engaged in the commissioning of electrical equipment, devices, installations, and systems. ● The commissioning organization shall use personnel who are regularly employed for electrical commissioning services. ● The commissioning organization shall submit appropriate documentation to demonstrate that it satisfactorily complies with these requirements.

Commissioning Personnel Personnel performing these commissioning activities shall be trained and experienced concerning the apparatus and systems being evaluated. These individuals shall be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must evaluate the test data and make a judgment on the serviceability of the specific equipment.

● Drawings and instruction manuals applicable to the scope of work.

● Project schedule. ● Site-specific hazard notification and safety training. ● Owner’s project requirements (OPR). ● Basis of design (BOD) document. ● Designated representative(s) for the project commissioning activities.

The Commissioning Organization The commissioning organization shall provide the following: ● All necessary services and technical expertise to conduct electrical commissioning. ● Notification to the designated representative(s) prior to the commencement of any electrical commissioning activity. ● Timely notification of deficiencies based on the results of the commissioning activities. ● Written record of all electrical commissioning activities and a final report.

COMMISSIONING PROCESS The NETA ECS defines the commissioning intent and the owner’s project requirements. Commissioning is the systematic process of verifying, documenting, and placing into service newly-installed, or retrofitted electrical power equipment and systems. Commissioning is critical for all new or retrofit installation projects to verify the correct system operation to the design, thus contributing to the safe and reliable operation of the system.

48 The commissioning process involves owner’s project requirements (OPR), basis of design (BOD), factory acceptance tests, field acceptance tests, verification of the component interconnections, and functional testing of the system in part and in whole. Acceptance tests and commissioning work provides baseline results for routine maintenance of the system and related components.

Safety Vol. 1 ● Documentation of the general communication channels and project hierarchy. ● Detailed schedule of the project, including design, construction, acceptance testing, commissioning, and energization stages and milestones. ● General description of commissioning activities that will occur during construction, energization, and post-energization.

OWNER’S PROJECT REQUIREMENTS (OPR)

● Commissioning checklists and test forms specific to the project.

OPR are a written document that details the functional requirements of a project and the expectations of how it will be used and operated. This includes project goals, measureable performance criteria, cost considerations, benchmarks, success criteria, and supporting information. (The terms project intent or design intent are used by some owners for their commissioning process owner’s project requirements.) (ASHRAE Guideline 0-2005)

● A process for approval by the owner and operator to allow the equipment to be energized.

DESIGN STAGE At this stage, the basis of design is created. The commissioning team should verify the basis of design meets the OPR, develop a commissioning plan, develop checklists, and perform the design review.

Basis of Design (BOD) The BOD is a document that records the concepts, calculations, decisions, and product selections used to meet the OPR and to satisfy applicable regulatory requirements, standards, and guidelines. The document includes both narrative descriptions and lists of individual items that support the design process. (ASHRAE Guideline 0-2005)

COMMISSIONING PLAN The NETA ECS highlights the commissioning plan and the contents. A commissioning plan is a document that outlines the organization, schedule, allocation of resources, and documentation requirements of the commissioning process. The commissioning plan should be developed by the commissioning authority during the design stage of the project. The commissioning plan should be updated and expanded during the construction, acceptance testing, and functional testing phases of the project by the commissioning team. Parties involved in the execution of the commissioning plan shall work from the most up-to-date version of the plan. The commissioning plan should include the following information: ● Overview of the commissioning stages and activities. ● Roles and responsibilities for the commissioning team throughout the project.

● A process for approval by the owner and turnover of the project and equipment from the commissioning team to the owner.

CONSTRUCTION STAGE At this stage, the commissioning team verifies equipment complies with the OPR, executes the factory acceptance testing, field acceptance testing, and pre-energization commissioning inspections and tests.

INSPECTIONS AND COMMISSIONING PROCEDURES There are three voltage classes of equipment detailed within the NETA ECS: ● Low-Voltage Systems (less than 1,000 volts) ● Medium-Voltage Systems (greater than 1,000 volts and less than 100,000 volts) ● High-Voltage and Extra-High Voltage Systems* (greater than 100 kV and less than 1,000 kV) Within each voltage class many of the commissioning tasks are the same, however there are some differences in execution between equipment classes due to different types of construction or complexity of operation. By breaking the standard into voltage classes, NETA is able to address the various nuances and requirements of commercial, industrial, and utility grades of equipment, independent of the industry at which the equipment is located. *Note: High and extra-high voltage systems are combined into one category in the NETA ECS. For instance, the commissioning of a low-voltage power circuit breaker and related system is typically not as complex as a medium-voltage circuit breaker and the related system[s]. Regardless of the voltage class of the electrical system or systems being commissioned, there are some basic aspects that apply to all. Listed below are several of the basic steps that will be applied globally to all systems, but be aware there are many voltage and project specific tasks that are not listed below. Refer to the NETA ECS for a more comprehensive listing.

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Safety Vol. 1 Typical Commissioning Inspections and Tests (Common To All Voltage Levels) Pre-Energization Prior to complete system energization, assure the following pre-energization tasks have been completed. ● Review the owner’s project requirements (OPR), basis of design (BOD), project specifications, and regulatory requirements for information specifically related to the commissioning of the electrical system. ● Review factory and field acceptance test data, documentation, results, and deficiencies to verify acceptable condition and suitability for initial energization and final acceptance. ● Verify all equipment has been tested according to the most recent edition of the ANSI/NETA Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems (ANSI/NETA ATS). ● Verify nameplate and equipment ratings are documented and correct in accordance with the most current drawings. ● Review drawings, logic diagrams, protective device settings, engineering studies, and other pertinent information to verify accuracy and completeness. ● Visually inspect equipment. ● Verify equipment is clearly labeled with unique designations and match designations on drawings, documentation, programming, and communication protocols. ● Verify equipment, doors, and fences are labeled with appropriate safety labeling and have the correct information in accordance with applicable regulations. ● Verify equipment and circuits are correctly bonded and grounded in accordance with applicable regulations. ● Confirm that correct electrical equipment clearances have been met. ● Verify correct operation of mechanical, electrical, and safety interlocks on electrical power equipment. Verify duplicate keys are destroyed or retained by authorized personnel in accordance with manufacturer’s recommendations.

● Verify intelligent electronic devices, communication protocols, and SCADA systems are connected to an adequate time synchronization source and all devices display the correct date and time. ● Verify applicable communication points to end device(s). ● Verify transformers are in the correct DETC and LTC tap position(s) for energization. ● Verify and document correct start-up procedures on UPS and battery system components. ● Confirm batteries have been equalized and float charged in accordance with manufacturers’ requirements. ● Verify that indications and records are cleared for faults, alarms, and meters. ● Create as-left setting files. ● Submit test data, as built drawings and relay as left files to owner prior to energizing equipment. ● Create a written energization plan.

ENERGIZATION AND TRANSFER TO OWNER STAGE At this stage, the commissioning team completes the final inspections, energizes the equipment, monitors equipment, completes reports and transfers the facility to the owner or operator.

Energization ● Restrict access to the substation and components during energization and commissioning activities. ● Verify removal of temporary protective grounding equipment. ● Verify correct position of switches, circuit breakers, and transfer switches for control circuits, instrument transformer circuits, and power circuits. Verify test switches and terminal block disconnects/switches are in the correct position in accordance with energization plan. ● Follow and document the steps of the energization plan. ● Verify correct current and voltage values to protective devices and metering.

● Verify current transformer circuits are complete and do not have an open-circuit. Shorting devices should be in the intended position.

● Verify correct operate and restraint values to differential protection.

● Verify instrument transformer tap connections are correct and match documentation, most current drawings, and protective device settings.

● Verify equipment phasing.

● Verify protective device settings are correct and match documentation, drawings, and engineering studies. ● Verify correct operation of applicable devices for protection and control schemes, SCADA, and communication protocols. ● Verify intelligent electronic devices, communication protocols, and SCADA systems properly trigger events and disturbance records.

● Verify correct system phase angle and sequence. ● Verify correct motor rotation for motors on electrical equipment and associated equipment. ● Verify transformer load tap changer and automatic voltage regulator operation. ● Verify battery and UPS systems are free of alarms and are in the specified operating mode. ● Verify monitoring devices are functioning properly. ● Verify no alarms or fault indications are present.

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● Obtain post-energization oil and gas analysis on applicable devices.

Applicable equipment manuals and operational instructions shall be readily available for the owner and operator.

● Create and submit NERC compliance and any regulatory requirement reports (NERC requires this within 30 days of energization).

SUMMARY

● The manufacturers of installed equipment should be notified of the actual energization date for warranty purposes. ● Perform thermographic survey of equipment. ● Monitor equipment loading and compare to design criteria. ● Complete commissioning report and supply documentation.

TRANSFER TO OWNER/OPERATOR ● A formal and documented turnover of the project and the facility shall be performed. ● The operator receiving the turnover shall be informed of any outstanding deficiencies and any abnormal operating conditions. ● The turnover shall include all documentation, drawings, and operational responsibilities required. ● All contractor locks shall be removed from the facility and the operator place locks where required.

DOCUMENTATION The commissioning organization shall furnish a copy or copies of the complete documentation as specified in the commissioning contract. The commissioning documentation shall include the following: Report ● Summary of project. ● Description of electrical system. ● The final commissioning plan and the results of the implementation of that plan. ● A copy of the commissioning design review records and logs and submittal review logs. ● A complete copy of the testing and performance test forms. ● Identification of systems or assemblies that do not meet the owner’s project requirements. ● Analysis and recommendations. ● Resolution plan for incomplete tasks. ● As-left relay logic diagrams and setting files. Drawing packages ● All applicable drawing packages shall be as-built. ● A complete as-built drawing package shall be left on site and a duplicate as-built package shall be submitted to the owner/operator.

One of the more common problems found during energization or system loading is the misoperation of differential protection. If the equipment was only acceptance tested and the components tested individually without looking at the protection system as a whole, it would be easy to miss a design error or setting error especially on more complex protection schemes. This can be easily avoided with proper commissioning. Simple primary injection tests of differential protection circuits will verify correct connection and settings of the protection scheme. By defining the commissioning process, the NETA ECS will help guide the owner and the commissioning team to work together to develop the OPR, BOD, and commissioning plan. It is important to note the commissioning work starts early in the project and continues throughout the project. Fundamental documents such as the OPR and BOD, are valuable tools that should be the focus of commissioning tests. So whether you have a low-voltage, medium-voltage, or high-voltage electrical power system, it should be part of the project plan to create a commissioning team early in the project and include specifications for both acceptance testing and commissioning to assure safe and reliable performance of your electrical system. Lorne Gara is a Technical Manager for Orbis Engineering. He provides technical support for the engineering, field services, and automation departments of Orbis and many of its Clients. Lorne has a wide range of experience in engineering, commissioning, maintenance, fault analysis, and start-up of utility and industrial power systems across North America. He has extensive experience with protective relay setting development, commissioning, and testing protection and control systems. Ron Widup is the CEO of Shermco Industries in Dallas (Irving) Texas and has been with Shermco since 1983. Shermco provides electrical power system testing, maintenance, commissioning, engineering, and training in the United States and Canada as well as electric rotating machinery remanufacturing and service. Ron has a degree in Electrical Power Distribution from Texas State Technical College in Waco, Texas. He is a NETA Certified Level IV Senior Test Technician, State of Texas Journeyman Electrician, a member of the IEEE Standards Association, an Inspector Member of the International Association of Electrical Inspectors, and an NFPA Certified Electrical Safety Compliance Professional (CESCP).

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PRE-JOB BRIEFINGS: AN INDISPENSABLE SAFETY TOOL NETA World, Fall 2016 Issue By Paul Chamberlain, American Electrical Testing Co., Inc. Protection from hazards always begins with proper prior planning. An important aid to planning a job correctly and thoroughly includes using a tool known throughout the industry as a pre-job briefing (PJB). These tools are commonly called tailgates or tailgate meetings in construction parlance, but no matter what they are called, they are designed to do the same thing: identify relevant hazards on the jobsite or during performance of a task and communicate those hazards to all persons on the job who may be affected. Per the NFPA 70E 2015, Standard for Electrical Safety in the Workplace, Article 110.1(H) clarifies when a job briefing should be conducted: Before starting each job, the employee in charge shall conduct a job briefing with the employees involved. The briefing shall cover such subjects as hazards associated with the job, work procedures involved, special precautions, energy source controls, PPE requirements, and the information on the energized electrical work permit, if that might affect the safety of employees occur during the course of the work. The NFPA also includes a sample Job Briefing and Planning Checklist under Informative Annex I (Table 1). Although this specific form is not required, a similar form should be created to aid the employee in the identification and mitigation of potential hazards.

Identity

Hazards Voltage levels involved Skills required Any “foreign” (secondary source) voltage source ❏ Any unusual work conditions ❏ Number of people needed to do the job ❏ ❏ ❏ ❏

Ask

❏ Can the equipment be de-energized? ❏ Are backfeeds of the circuits to be worked on possible?

Check

❏ Job plans ❏ Single-line diagrams and vendor prints ❏ Status board ❏ Information on plant and vendor resources is up to date

Know

❏ What the job is ❏ Who else needs to know — Communicate!

Think

❏ About the unexpected event... What if? ❏ Look — Tag — Test — Try ❏ Test for voltage — FIRST ❏ Use the right tools and equipment, including PPE

Prepare for an emergency ❏ Is the standby person CPR trained? ❏ Is the required emergency equipment available? Where is it? ❏ Where is the nearest telephone? ❏ Where is the fire alarm? ❏ Is confined space rescue available?

❏ Shock protection boundaries ❏ Available incident energy ❏ Potential for arc flash (Conduct an arc flash hazard analysis.) ❏ Arc flash boundary

❏ Is a standby person required?

❏ Safety procedures ❏ Vendor information ❏ Individuals are familiar with the facility

❏ Who is in charge

❏ Install and remove temporary protective grounding equipment ❏ Install barriers and barricades ❏ What else...?

❏ What is the exact work location? ❏ How is the equipment shut off in an emergency? ❏ Are the emergency telephone numbers known? ❏ Where is the fire extinguisher? ❏ Are radio communications available?

Table 1: Sample Job Briefing and Planning Checklist Source: NFPA 70E 2015, Article 110.1(H), Informative Annex I

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Even the Occupational Safety and Health Administration (OSHA), under 29 CFR 1910.269 - Electric Power Generation, Transmission, and Distribution Standard, specifies the requirement for a PJB.

performer, it is hard to develop a form that encapsulates all of those needs. The employer should be able to identify which hazards are greatest or are a more pressing need to address within the workforce, and develop a PJB adequate enough to identify those hazards.

● 1910.269(c)(1)(i): In assigning an employee or a group of employees to perform a job, the employer shall provide the employee in charge of the job with all available information that relates to the determination of existing characteristics and conditions.

One item of concern that should be addressed in every PJB is the need to identify the means of preventing the inadvertent or unexpected release of electrical energy. Since that is one of the greater and most prevalent hazards within the testing industry, it is also a good idea to identify how it will be controlled. Whether it is controlled via individual lock out/tag out, switching and tagging, live-line clearances, and/or the use of grounding, it should be indicated on the PJB. Additionally, it is wise to allow the performer a space within the form to indicate lock or tag or ground locations to ensure the proper removal when the work is completed.

● 1910.269(c)(1)(ii): The employer shall ensure that the employee in charge conducts a job briefing that meets paragraphs (c)(2), (c)(3), and (c)(4) of this section with the employees involved before they start each job. OSHA also requires that the PJB cover “hazards associated with the job, work procedures involved, special precautions, energy-source controls, and personal protective equipment requirements.” Additional PJBs may be required should the task or workplace location change significantly enough to change the hazards involved in performing the work. The more potential hazards, the more detailed the PJB should be. Additionally, more extensive PJBs may be required for inexperienced employees. The only time a PJB does not need to be conducted, per OSHA 1910.269(C)(5), is if an employee will be working alone. It states: “However, the employer shall ensure that the tasks to be performed are planned as if a briefing were required.” OSHA’s website, under its e-tools, suggests that a checklist be used to facilitate the PJB: Keeping a written record of job briefings is not specifically covered by the standard, but it is a best practice to do so. A written checklist can include the hazards, procedures, precautions, and PPE requirements associated with a job, as well as a column for employee signatures indicating they are knowledgeable about job hazards and safety procedures. Such documentation can help ensure that proper briefings are held at the right times (for example, beginning of a shift) and that everyone has been informed. For an example checklist, see the Job Briefing and Planning Checklist in Annex I of the National Fire Protection Association’s NFPA 70E, Standard for Electrical Safety in the Workplace, 2004 Edition. As seen in this quote, even OSHA refers back to the sample PJB in the NFPA 70E. PJBs come in a variety of versions and styles. They come from utilities, large manufacturers, and from individual testing companies. All of them are designed to do one thing, and they do it fairly well: They aid the task performer(s) in identifying and minimizing risks associated with the hazards of performing the task. Some PJBs focus strongly on physical hazards, others focus on task-specific procedures, and some help identify human-error traps. Since a PJB is designed to be a quick and simple-to-use tool for the task

Addressing and indicating the limited, restricted, and arc-flash boundaries on the form is also recommended. This will make it easier for performers to advise visitors to the work location of the various approach distances. Additionally, the hazard/risk category level, PPE level category, and any additional PPE required to complete the task should be indicated on the form. The person in charge who fills out a PJB form should review all hazards with the performer(s) of the task and give them ample opportunity to ask questions. A PJB should be a give-and-take discussion, not a dictation. The review of the PJB should be conducted with all personnel who may be affected by task performance or with anyone else whose work may impact the task. This includes contractors, subcontractors, and peripheral workers on the jobsite. Once the review is complete, the names of all persons attending the PJB review should be noted. It may be as simple as printing each name on the PJB itself, or the PJB may have a separate signin sheet. Should the task or the job location significantly change, a new PJB or review/amendment of the old PJB form may be necessary. Should a visitor arrive on-site, they should be immediately stopped from encroaching upon the work area, and the PJB should be discussed, apprising them of the potential hazards on the job site. Identifying and mitigating potential job hazards is important in the prevention of possible injuries or accidents. It is up to the employer to provide an adequate means of identifying and addressing those hazards. A PJB form is required in most cases, and is an easy and effective means of identification. The employer should ensure it is adequate for the tasks the employees will be performing, and the employee should use the provided form to help prevent potential injuries. Should an employee have suggestions on improving the form, they should voice those suggestions to the employer. After all, it is the employee’s form to use. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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FIRST RULE OF TROUBLESHOOTING: TRUST, BUT VERIFY NETA World, Winter 2016 Issue By Don Genutis, Halco Testing Services It can be difficult to piece together a puzzle when troubleshooting — but when the information provided by the client is incomplete or just incorrect, the task is even more difficult. As we began our ascent up the steep, winding, two-lane mountain road, we were already 30 minutes late due to circumstances beyond our control. We were on our way to a remote, high-power radio broadcasting tower to troubleshoot a problem when our technician stated, “I probably should have gotten gas back there in that little town.” Our destination was another 25 miles away. Going back to the town would put us another 30 minutes behind schedule; however, based on the fuel-gauge level, it was a reasonable assumption that we would make it to the job site and back to town later, so we pushed on. This adventure actually began the evening before when we received a call from a customer requesting help to troubleshoot his Automatic Voltage Regulator (AVR). Because we were unfamiliar with this apparatus, we did an Internet search and found some information about AVRs. Though there wasn’t much, at least we found enough to gain a better feel for the equipment. One photo online showed three motor-operated variacs connected to a three-phase isolation transformer and three single-phase buck/ boost transformers. Essentially, an AVR’s job is to provide a stable output voltage. In this particular case, the load primarily consisted of the 30kv transmitter with a couple of additional minor loads. Considering that the customer is at the very end of a long, rural overhead distribution line, voltage regulation along with emergency power is a necessity. When we arrived at the customer’s site, we looked past the mammoth radio towers and had a tremendous view of the sprawling Los Angeles basin. After a deep breath, it was time to meet our customer. Our new customer was a likable guy with a great deal of knowledge and experience with keeping the station operational. We quickly learned that much of the basic troubleshooting was complete, and there wasn’t much information to go on regarding possible causes of the problem. Essentially, a utility event tripped a circuit breaker on the critical load panel, and now, the AVR did not function properly under load. The voltage was fine without load. Upon removing the apparatus covers, we were pleased to see that the basic component layout closely resembled the Internet photos. Almost immediately, we spotted six large fuses that seemed to be associated with the variacs. Our customer informed us that he had

already checked all of the fuses. In most cases, checking the fuses and incoming power is the first rule of troubleshooting. We began operating the variacs manually, checking voltages, applying load, and then finally speaking to the manufacturer. The manufacturer provided great support, and after being brought up to speed, asked if we had checked the fuses. We replied that they were checked by the customer, and the manufacturer suggested other checks. We dug deeper, but no problems were uncovered. What initially may have been a microprocessor problem now began to look like an isolation transformer failure. We determined that removal of the six variac fuses would provide good isolation for the connection of our test equipment. Our technician removed the fuses and found that all six fuses were blown. Problem solved. We all had a good-hearted laugh with the customer, wrapped up, and proceeded down the mountain and off to the next adventure. By the way, we did make it back to town for gas. Troubleshooting is often performed while the equipment remains energized. As always when troubleshooting, first adhere to proper safety procedures. The customer’s explanation of the problem usually provides valuable key facts that help point the troubleshooting technician in the right direction. Before going too far down the wrong path, it’s best for the technician to first verify everything, which is the basis for the first rule of troubleshooting. Always remember that the customer may not be 100 percent accurate with either recollection of the failure events or their initial troubleshooting results. Oh, and the second rule of troubleshooting: Always remember to check the fuses twice. Don A. Genutis holds a Bachelor of Science degree in Electrical Engineering and has been a NETA Certified Technician for more than 15 years. He has held various principal positions during his 30-year career in the electrical testing fieldand has primarily focused on advancing no-outage-testing techniques for the last 15 years. Don presently serves as President of Halco Testing Services in Los Angeles, California.

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DISTRACTED DRIVING NETA World, Winter 2016 Issue By Paul Chamberlain, American Electrical Testing Co., Inc.

In this day of modern technology, it is easy to get overwhelmed with the number of distracting devices in our world, and these devices are encroaching upon the driving environment. Cell phones are an awesome way to communicate over long distances, but couple them with texting, email, Internet, and mobile video or audio, and they are an absolute attention grabber. Smartphones can be coupled with hands-free Bluetooth devices that allow a driver to talk with limited interaction, and they can display directions when used as a GPS. However, even when using these safer methods of interaction, they divert the attention of the driver from their primary task — driving a vehicle. Cell phones aren’t the only distractions inside a vehicle. People still eat or drink while driving, play with the radio, read papers or magazines, talk on CB radios, and perform personal grooming like shaving or brushing their hair. It is amazing what people will do while driving and the risks they are willing to accept.

LATEST INFORMATION ON DISTRACTED DRIVING The National Highway Transportation and Safety Administration, which is part of the United States Department of Transportation, has created a website for distracted driving information at www.distraction.gov. It is loaded with statistics and information that can be disseminated to co-workers, teen drivers, and used by employers for employee distracted-driving awareness training. Here are some key facts and statistics from that website: ● In 2014, 3,179 people were killed and 431,000 were injured in motor vehicle crashes involving distracted drivers. ● As of December 2014, 169.3 billion text messages were sent in the U.S. (includes Puerto Rico, Guam, and the Philippines) every month. ● Ten percent of all drivers age 15 to 19 involved in fatal crashes were reported as distracted at the time of the crash. This age group has the largest proportion of drivers who were distracted at the time of the crash. Drivers in their 20s are 23 percent of drivers in all fatal crashes, but are 27 percent of the distracted drivers and 38 percent of the distracted drivers who were using cell phones in fatal crashes. ● The percentage of drivers text messaging or visibly manipulating handheld devices increased from 1.7 percent in 2013 to 2.2 percent in 2014. Since 2007, young drivers (age 16 to 24) have been observed manipulating electronic devices at higher rates than older drivers.

● At any given daylight moment across America, approximately 660,000 drivers are using cell phones or manipulating electronic devices while driving, a number that has held steady since 2010. ● A 2015 Erie Insurance distracted-driving survey reported that drivers do all sorts of dangerous things behind the wheel, including brushing teeth and changing clothes. The survey also found that one-third of drivers admitted to texting while driving, and three-quarters say they’ve seen others do it. ● Five seconds is the average time your eyes are off the road while texting. When traveling at 55 mph, that’s enough time to cover the length of a football field blindfolded. ● Smartphone ownership is growing: In 2011, 52 percent of drivers reported owning a smartphone; by 2014, that number had grown to 80 percent. The greatest increases in smartphone ownership are among adults age 40 and older.

HOW EMPLOYERS CAN REDUCE DISTRACTED DRIVING Employers are certainly not powerless to prevent distracted driving by employees on company time or in a company vehicle. The U.S. DOT encourages employers to create a distracted-driving policy, and will provide videos, posters, and sample policies to encourage better driving habits. Hands-free technology can be provided for employees, or it can be encouraged to purchase it. First, however, be aware of which states allow the use of such devices. See Figure 1 on the next page for more information regarding hands-free device use and texting bans or allowances. There are many things that can divert a person’s attention while driving, and in this digital age, the cell phone is probably the most prevalent. Communicate with employees about distracted driving and follow your state laws. Make it a point to be a better, more attentive driver, and you should realize improvements in your own driving ability and safety. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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Fig. 1: State laws govern cell-phone use and texting while driving.

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TEST EQUIPMENT: MANAGING THE HIDDEN DEFECTS NETA World, Winter 2016 Issue By Ashley Harkness, Emerson Electrical Reliability Services You are testing a modern, digital protective relay. Your testing device is a modern, top-of-the-line, computer-driven, digital relay test set. The reliability of the protected power system is on the line. You think that your test equipment is at 100 percent. Then, in the middle of the job, it fails. Could this have been avoided? Perhaps it could. In this article, we will consider test equipment condition issues, steps to reduce their unplanned outage, and ways of managing test equipment’s hidden effects.

THE CHALLENGE OF REAL LIFE In the real-life rush to get to the job, do we give our test equipment a good look over? NFPA-70E requires handheld test equipment to be inspected before use. The reason is simple: If there are broken test leads, damaged probes, or cracked meters, you might have a serious safety issue on your hands. The same goes for more costly and important capital equipment. Many of the newer test equipment devices are highly reliable, computer-driven instruments. They are designed to perform complex testing such as on protective relays. Left undisturbed on a lab bench in a clean, warm, safe environment, they are expected to perform well for many years. However, is that how a testing company actually uses them? Is the actual field environment safe and warm? Perhaps not. A typical field scenario might go like this: Test equipment is manhandled into the back of a bouncing pickup truck; driven to the job site over rough construction roads; connected to a noisy, erratic generator; and carried from location-to-location or pushed on a stiff-wheeled, jolting cart. This environment can really shake things up! After over 40 years repairing test equipment, I have learned a few simple rules: Shake up the equipment and it will fall apart. Loose screws and hardware, disconnected cable assemblies, broken switches, jammed relays, and broken internal wires are very common; in fact, 95 percent of repairs are mechanical in nature. Mechanical degradation is the killer of test equipment. And there are other issues to consider: What about those instrument cooling fans that suck in all manner of dirt and bugs? Is this another recipe for future trouble? You can bet on it. Dirt can be very conductive. Combined with high humidity, internal tracking and short circuits can kill your equipment. What about bugs? Consider spider webs inside your expensive test set — not to mention the surprise as their eggs, hatching at your job site, flood your work area with hungry, active baby black

widow spiders. Bugs can also damage insulation. They can slime their way around inside the equipment, leaving nasty substances on circuit boards with serious consequences. If it can fail, it will fail — always when least expected and when needed most. What is a testing company to do? Simple applications of the same skills we bring to the job are the first line of defense. ● Look at the test equipment. Inspect it regularly. Anything out of the ordinary is a sure clue. Are all the handles, knobs, and other mechanical parts complete, secure, and intact? If not, report it. ● Listen for strange noises when you pick it up or move it. Loose hardware will talk to you if you listen. That is a signal to check it out. ● Check for proper accessories. A missing power cord, test leads, or programmer dongle will mean delays as replacements are sought. ● Make sure the manufacturer’s instruction manual is with the equipment. There are too many stories of test equipment not working, only to find that instructions were not followed. Instruction manuals have the parts list and, more important, the manufacturer’s contact information. ● Encourage notification from your team when an instrument is suspicious. Back on the shelf for another team member to grab later is not the correct procedure. ● Do not blame people for damage or breakage unless it is a clear habit. Instead, concentrate on finding and solving the problems.

SERVICE-TO-SERVICE PROVIDERS Talk to your instrument calibration/maintenance service providers. They are test instrument experts and will tell you if significant changes are occurring. We often forget that while we deliver service to our clients, we need their service, too. Our calibration vendors are our partners in our ultimate success. They need to better understand our needs. Does your commercial calibration laboratory understand your harsh work environment? They will often calibrate your equipment, find it working properly, and return it to you. Internal inspection is not always a standard procedure. Remember that they, too, are in a competitive business where extra effort means extra cost.

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Safety Vol. 1 You may need them to routinely open and complete an internal inspection. They can clean it out and look for obvious defects. This is the same as lifting the hood of your truck to inspect the engine. This may only be appropriate for limited equipment in your inventory, but the cost of this ounce of prevention will be cheaper than having equipment fail on the job site. During the vendor visit, ask a few other related questions: ● Does the calibration service use manufacturer’s specifications and procedures or produce its own? Often, even the manufacturer’s information is sparse and lacking detail or full testing requirements. Your provider can make necessary provisions. ● Does the calibration service test each function of the test equipment? In some cases, the proper operation of mechanical switches and lamps is as important as the accuracy of the metering. This is especially true for test sets that test circuit breaker trip units. Communication is the key. If they do not know your needs, will this service be provided? Probably not.

RECORD KEEPING We know from wide experience in the electrical maintenance and testing industry that all systems, electronic and mechanical, will age and degrade over time. Similarly, we need to track changes in our test equipment. ● Do you keep the maintenance history of your test equipment? Repair orders and calibration certificates are critical. With them, the insight to the future serviceability of equipment can be revealed. When more repairs are needed or increasing close-to- or out-of-tolerance conditions are found, a replacement decision must be made. Review the records on a frequent basis. ● Too often, we continue to use obsolete test equipment long after its day is done. Yes, I have a beloved, old-friend analog meter, too. And, in some rare situations, it is the correct tool. However, we need to focus on technology changes. Sometimes, that means sending our old friends out to pasture. Records will give us the information we need to make even these tough decisions. Say goodbye, and purchase new equipment. ● If new technology requires more training, keep records. OSHA clearly states that if there is no paperwork, i.e. records, it did not happen. No records may lead to increased liability. Records can be easily kept electronically. They may also be required by clients as part of a bid package. Attention to test-equipment recordkeeping is an important part of the service that we, as testing companies, provide to our clients.

CONCLUSION Our ability to continue providing successful service to our clients depends on how we maintain and service our tools. Improving test-equipment reliability is a matter of observation and communication. Make sure to give your test equipment the inspections it needs. Make sure to communicate your expectations and needs to company users and service vendors. Keep good records. Take proactive steps. It is the best way to manage the hidden defects of your test equipment. Ashley Harkness, Jr. is an Electrical System Specialist at Electrical Reliability Services. He joined the company (then known as Electro-Test, Inc.) in 1982. Until 2013, his duties included operation and management of the internal calibration laboratory program. During these years, he also managed the manufacturing department making specialized test equipment and led specialized electrical projects including European Community Machinery and EMC Electromagnetic Compatibility Directive testing, basic insulation level (BIL) impulse testing, process and control instrumentation acceptance and testing, electrical equipment forensic investigations, and electrical product safety testing. In 2005, Ashley became manager of the ERS medium-voltage systems (switchgear and cables) on/off line partial discharge/cable testing program. In 2014, his assignment changed to NFPA 70E trainer for ERS client organizations and internal training.

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BELIEFS DRIVE BEHAVIORS PowerTest 2016 D. Ray Crow, Senior Member, IEEE and Danny P. Liggett, Senior Member, IEEE

ABSTRACT For more than 50, years research has shown that a correlation exists between the number of incidents, injuries, and fatalities. Investigation into electrical incidents indicates there is more to understand about the causal effect of the number of incidents occurring. Many electrical incidents are caused by undesirable actions of people. These are called unsafe acts. Why do people perform unsafe acts? Lack of experience, knowledge, or skills often come into play. What people believe about safety is another important component. The intent of this paper is to explore these relationships and to focus on unsafe behaviors and beliefs about safety. By investigating and using the actions outlined in this paper fewer incidents will occur resulting in a decrease in injuries and fatalities.

As shown in Fig. 2 “Elements of Human Performance”, there are three primary things that impact what people do. What they know, the level of their skill, and their willingness to do it1. The lack of skill, experience or knowledge has been a significant factor in every incident investigation in the past couple of decades. To improve personal safety employees require continuing knowledge and training to perform their tasks in a safe manner.

Index Terms – Beliefs, Behaviors, Electrical Safety

INTRODUCTION Fig. 1 “Incidents Lead to Fatalities” shows the relationship between incidents, injuries, and fatalities. Understanding the behavioral-based components involved when incidents occur is important information to study to change the safety culture. This element of study has been missing from the data available to assist in improving workplace safety. Most often, this type of information has never been compiled and reviewed.

Fig. 2: Elements of Human Performance What is typically ignored is what people think and believe about the standards and procedures they are asked to follow. More time and focus on understanding why people resist accepting new requirements needs to be explored2. Every person has thoughts about the things they are asked to do. One common factor not recognized is everything we see, read and hear is filtered through our beliefs. At least one other filter applies and that is experience. Experience plays a significant role in what people tend to accept. Dr. Mary Capelli-Schellpfeffer told the authors, “We can perceive only what we experience.” Everyone molds information that is received into an understanding that fits into his or her previous experience. In some instances, the information is completely new and cannot be molded into previous experience. When that happens, a person’s basic beliefs and principles play a role in how the person interprets the data.

Fig. 1: Incidents Lead to Fatalities

Neuroscience tells us everything we can know is our version of it3. We try to make our experiences and what we see, read and hear fit into “our world”. “Our world” is built around our beliefs. We seek information that aligns with what we already believe and

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Safety Vol. 1 discount or ignore information that goes against what we already believe, a process called “confirmation bias”. So strong is this bias that we are unable to pay adequate attention to information that goes against our beliefs even when enticed by monetary incentives4 or evidence that blatantly disconfirms our position5. This can, and many times does, lead us to interpret standards and procedures differently from other people when we read them. We also do this with what we see. Two people can watch an event and will have different understandings of what occurred. As you read this paper you will most likely have a different understanding of the material from what the authors intended. You will filter the material through your beliefs and experiences. Most people arrive at work with the intention of doing a good job, doing the right things and being a productive employee. People do what they believe is the right thing to do based on their experiences and beliefs. What needs to be explored and understood is what people believe about safety and how to influence those beliefs.

How Do They Impact Performance? A lot of time is spent identifying unsafe acts and not enough time is spent on why people choose to perform unsafe acts. Unsafe acts or inappropriate behaviors contribute to incidents and injuries. It is estimated that 91% of incidents are caused by inappropriate behaviors6. Unsafe acts and inappropriate behaviors are key areas that need attention. Fig. 3 “Behavior – A Leading Indicator for Safety”6 provides another layer to the chart shown in Fig. 1. This does not mean that the incidents are the fault of the employees. Equipment can fail and set up a situation or an unsafe condition where an employee can be injured as a result of this failure if the condition is not recognized. An example of this is a disconnect switch where all of the blades failed to open. Failure to test for the absence of voltage has contributed to numerous incidents, injuries and fatalities.

It is important to understand that different experiences and beliefs exist in every person at every level of an organization. The beliefs of management will drive behaviors that may create some of the issues causing incident rates to remain high. For example, an emphasis on meeting deadlines can be perceived to be more important than safety.

BEHAVIORS What Are They? Behaviors can be defined in many ways. Behaviors of people can be observed. They are actions that people do or do not do. Some examples of behaviors are: testing for the absence of voltage, wearing voltage rated gloves while testing for voltage, and wearing your seatbelt while driving or riding in a vehicle. If we perceive people in this way (as a collection of responses to a collection of stimuli), it fosters an understanding that behavior is predictable and thus changeable. We just have to understand how to do it. Not taking appropriate actions is also a behavior. Not wearing your seatbelt or failing to test for the absence of voltage are also behaviors. In either context inappropriate behaviors are called unsafe acts. Observation data related to behaviors that was not recorded previously is a new way to find your leading indicators of possible incidences. Collecting and reviewing multiple behavioral actions is valuable to locate beliefs about safety that are impeding the implementation of a new or changed safe work practice. The importance of collecting and reviewing behavior-based data on an on-going basis must be stressed within organizations. Behaviors will tell you what people believe.

Fig. 3: Behavior – A Leading Indicator for Safety When incidents occur there is generally something missing in the company’s safety program. Placing blame for the incident on the employee is a behavior that managers or supervisors might take. Safety supervisors should focus efforts on root cause analysis with employee involvement to solve safety issues. Fault finding or placing blame for an incident is the weakest form of changing behavior. The effect of placing blame usually teaches people to understand that they should not get caught6. Fault finding or placing blame has little to do with changing beliefs or behaviors. Incidents, injuries and fatalities are typically the consequences of inappropriate behaviors. We need to understand what behaviors are occurring, both appropriate and inappropriate. But we need to continue to move upstream and get into leading indicators. In order to move upstream we need to understand why people engage in inappropriate behaviors.

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What Drives Behaviors?

BELIEFS

The prevention of electrical incidents and injuries is hampered by the attitude that “Good workers don’t get hurt”7.

What Are Beliefs?

Even the most qualified and experienced person makes mistakes in the workplace. Thankfully, most mistakes do not result in injury. What we learn from these mistakes are a part of our experiences. Our experiences play a large role in driving beliefs and behaviors. All behaviors are either intrinsically driven or extrinsically driven8. Intrinsically driven behaviors come from our internal beliefs. If we believe that seatbelts will save our lives or prevent injury we will use them. If we don’t believe in seatbelts, we won’t wear them. Section III will cover, in more detail, how beliefs impact our behaviors. Abraham Maslow developed the Hierarchy of Needs9, and it has been used to help understand people’s behaviors. See Fig. 4 “Maslow’s Hierarchy of Needs”.

Beliefs are a conviction of the truth of something. This is derived from consideration or examination of the evidence available to us. It is a mental attitude of acceptance toward a proposition10. It is an opinion. A person can and often does accept an idea as the truth based on the person’s experiences and knowledge. If the idea is work related, then experience plays a significant role in how a worker’s belief is generated. An example of an old belief that changed through experience was the belief that the world was flat. This belief was based on the existing evidence available at that time. This belief changed as new experiences proved the world was round. A more recent example is the arc flash phenomenon associated with electricity. There are still people who do not believe that this is a hazard or that an arc flash will ever happen to them. So they believe they do not need to take any action, such as putting on arc flash PPE. The lack of experience often leads to the lack of belief in a rule or requirement related to safety. Therefore, a person’s belief may lead to the rule or requirement being ignored or not followed.

Where Do Beliefs Come From?

Fig. 4: Maslow’s Hierarchy of Needs Sometimes our needs and beliefs are aligned. When this occurs then our behaviors are intrinsically driven. When our needs and beliefs are not aligned, then our behaviors become extrinsically driven. It is important to understand that our “needs” can have more of an impact on our behaviors than our beliefs. An example of this extrinsically driven behavior is peer pressure. Our desire to “fit in” can overrule even our own natural internal sense for being safe. Extrinsically driven behaviors are usually driven from needs or from people following requirements that are imposed upon them. They may not necessarily believe that is it the right thing to do or they may not want to do it. They engage in these behaviors because it is necessary to keep their job or get a raise. Extrinsically driven behaviors are unreliable and intermittent and may not be performed at 2 a.m. when no one is around.

From the moment we are born, we begin to have experiences. As we collect these experiences, we begin to form beliefs. We touch the hot stove and get burned. We make a connection between the hot stove and getting burned. Our belief becomes that we should not touch the hot stove and if we do we will get burned. When we go to school, teachers begin to provide us with knowledge and our classmates give us new experiences. We go out into the world and have experiences. Listening to the news on TV or the radio provide us with different opinions. We take all of this information and we build beliefs. Each of us will have different experiences and this knowledge will drive us to create different beliefs. The social culture we experience impacts our beliefs. What may be acceptable in one culture may not be acceptable in another culture. Cultures exist at multiple levels. A culture can exist in a country, a state, a city or even in the electrical shop at a facility. These cultures impact our beliefs. To some degree, we will adopt the beliefs of the culture we are in. Sometimes this acceptance is immediate and some times it takes time to alter our own belief system. An example of this is that welders believe that getting shocked is just part of the job. It is a culture that has existed in the welding community for so long that shocks are not reported and continue to be ignored The environment we are in also impacts our beliefs. While culture and environment can be related they are different. The culture has more to do with the values of the people. The environment relates more to the physical environment we are in. For example, good housekeeping and safety go hand-in-hand. If we are assigned

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Safety Vol. 1 to a clean environment we will find ourselves behaving in a safe manner to maintain that environment. Conversely if we find a disorganized, unclean environment, we may adopt the belief that it is acceptable to have disorganized environments. The environment may have created a belief that drives a behavior of carelessness. These three things, experiences, social culture and environment, all impact our beliefs. Collectively, these concepts constitute a worker’s experience. These concepts on a work site are likely different from the person’s off-site experience. Two beliefs might be maintained as they are in different environments. People are likely to follow safety rules at work but may ignore them in the home environment even though the hazard is the same. For example, ladder safety, eye protection, hearing protection, etc. Connections about the hazard being similar or the same can be missed as there may be no job briefings, training, or discussions taking place at home.

How Do Beliefs Impact Behaviors? The relationship between beliefs and behaviors is like a tree. You see the leaves (behaviors) but not the roots (beliefs)11,12. Similarly, beliefs and behaviors are much like an iceberg, where most of the iceberg is below the surface of the water, beliefs are not visible. As mentioned before, if we do not believe that a requirement or an appropriate behavior has any value then we will not perform that behavior unless we are forced to. While we are being watched we will perform that behavior. But it is unlikely that we will perform the appropriate behavior if we think we can get away with not doing it. Why? Because we do not believe it is necessary or has any value. It is not about being lazy or a lack of regard for the rules, it is about what we believe. One example of a belief impacting behavior is using voltage rated gloves. Many electricians do not think they are necessary. When asked why, several common responses are heard. “I have been doing this for 25 years and I never needed them.” “I am not touching anything hot so I don’t need them.” “Good electricians don’t need them.” All of these reasons are based upon their belief. Their experience has reinforced their belief that gloves are not necessary. Beliefs will drive a person to make a decision that will either be an appropriate behavior or an inappropriate behavior. See Fig. 5 “Beliefs Drive Behaviors”.

Fig. 5: Beliefs Drive Behaviors If an inappropriate behavior is chosen, then it becomes a roll of the dice whether an incident will occur. If an incident does not occur, then that result will reinforce the inappropriate behavior. As this cycle continues without adverse results it can easily become a belief and a habit. A habit is an acquired pattern of behavior that becomes almost involuntary or automatic. Under pressure or stress people will always default to their beliefs or habits regardless of procedures and training. Habits can be developed for appropriate behaviors in the same way. See Attachment A “Appropriate vs. Inappropriate Beliefs”, at the end of this chapter, for a model representing this process.

How Do Beliefs Change? Is it possible? Yes. Is it easy? No. Changing beliefs must follow certain steps. Some beliefs are so strong that people will cling to those beliefs at all costs. This needs to be considered when we set out to change a person’s beliefs and behaviors. John Maynard Keynes stated, “The difficulty lies, not in the new ideas, but in escaping the old ones.” We are resistant to change because it causes a change in our world and our beliefs. Telling people what to think will not change their beliefs13. We have to influence how they think and what they believe. Workers must be provided with some experience that challenges all previous experience. The trick then is to find that new experience and provide it to the worker. Consequences also drive beliefs and behaviors. It is important to understand what consequences are controlling behaviors. Soon, certain, and positive consequences are the most effective in driving our behaviors. Timing is important. A consequence that follows soon after a behavior will control behavior more effective than a consequence that may never occur. Consistency is also important. A significant consequence that is certain to follow a behavior con-

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trols behaviors more powerful than an uncertain consequence. The significance of the consequence plays a large role on behaviors. A positive consequence controls behavior more powerfully than a negative consequence6.

world. This is how we end up with different interpretations of the same concept, idea, or thought.

Management and peer pressure can set a positive (or negative) belief structure in an organization. A management system that accepts unsafe behaviors to get the job done can drive negative belief systems. A manager that rewards a person for getting a job done even though it is understood that unsafe behaviors were taken will influence workers to believe that taking short cuts with safety is acceptable. However, management that immediately addresses unsafe behaviors in the workplace will drive a positive belief system.

There are many thoughts and ideas on how to change people’s beliefs. One concept is storytelling. Stories attract attention and are easier to remember. People relate to stories. Stories impact us emotionally. If we can move the person’s heart, we can move their head14. Important information told through a situational story that explains the old conditions and introduces a new belief or desired outcome enables people to recall the information to mind. The story must be convincing and connect to recent situations clearly understood by the audience15. The desired change must have a worthwhile benefit and must be seen as possible. Telling a story is one way of providing a new experience for some workers. The story must align with the worker’s previous experience to be of value.

Peer pressure is one of the most powerful consequences that effect behaviors in an organization. Peer pressure offers soon, certain, and positive feedback that can and will effect beliefs and behaviors. The feeling that one is accepted by others in the workplace is a powerful factor in driving behaviors. A person’s acceptance in the work group may be more important to them than the possibility of injuries that may or may not occur due to evading or ignoring safety requirements. Ensure that employees are involved and participate in safety. Employee involvement in safety is a key element to developing a positive peer pressure that will not tolerate unsafe behaviors. All safety efforts that work, are effective because they influence employee behaviors6.

How the Brain Incorporates New Beliefs Our brain is made up of about 100 billion cells called neurons. All of these neurons make connections with other neurons. All in all the brain is capable of making 40 quadrillion connections. Each second our brain is creating new connections. As we have experiences, doing, seeing or hearing, our brain makes these new connections. As mentioned earlier these experiences become the basis for our beliefs. As experiences are repeated the connections for these become layered with additional connections, making these connections strong. In turn the beliefs become stronger and more powerful. Studies of professional athletes’ brains has shown that they use less “brain power” when playing than a normal person performing the same actions11. The reason for this is the repetition. Professional athletes practice these actions over and over so that the actions become an automatic habit or behavior. The repetition provides more experiences for the athlete and strengthens the connection in the brain.

Storytelling Method of Changing Beliefs

Autonomy, Competence, and Relatedness Method of Changing Beliefs Another concept discussed by both Edward Deci8 and Daniel Pink15 contains three elements; autonomy, competence, and relatedness. Each of these elements must be addressed in order to change a belief. Autonomy is about being involved and having influence on the outcome. It is not about allowing a person to do whatever they please. For some time now the concept of involving people in creating requirements has been used successfully. One of the principles put forth by Stephen Covey1, seek first to understand then to be understood, is an example of how one needs to understand the issues and concerns of people when implementing a new requirement. This is a form of supportive autonomy where people are engaged in the process. If requirements are not gaining support by the people who have to implement them, then they probably were not involved in creating the requirements. By engaging people in the process, we gain buy-in from the people who need to follow the requirements.

Changing Beliefs

Everyone wants to be recognized as being good at what they do. By encouraging people to be competent we are building understanding in what the requirements need to be. In doing numerous audits of facilities the authors have learned that one of our great failings is that we assume people already know what is required and why. This is simply not true. We need to constantly encourage learning and provide education to people to allow them to be competent.

Each of us build a mental representation of our own reality, our own world, based upon our beliefs. We try to fit what we see, read or hear into our world based on what we already believe. Sometimes the fit is not very good and we will have a tendency to reject any idea that does not fit into our world or belief system. If we do accept a new concept we may alter the concept to fit into our

As with storytelling, we need to build a connection with the current situation and provide a benefit to the requirements. People need to be able to clearly see a purpose in any requirement. The requirement needs to be directly connected to their job and to a goal. The goal has to be something they believe in. Safety is always important.

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Safety Vol. 1 Education and Training Method of Changing Beliefs Change is probably the only thing that is consistent in our world today. Codes are constantly being updated. New technology is being introduced. People will feel left behind if training and educating is not provided. Training may be required to take place in different forms. Some people learn best by reading or in a class room environment. Some people learn best by doing “hands-on” work. Ongoing training is mandatory in the workplace to stay on the leading edge of safety.

PEOPLE For the last couple of decades we have worked on safe work practice procedures and improving electrical equipment. Fig. 6 “Critical Elements of Electrical Safety”16 shows three critical elements for addressing electrical safety. However, the third critical element of “people” and their underlying safety beliefs have not been an area of focus and study. People are exposed to the electrical hazards and are involved in the incidents, injuries and fatalities. If the safety beliefs of people interfere with using the “improved equipment” or following the “best procedures”, then electrical safety performance will continue to suffer. Electrical safety performance will improve by focusing on the critical third element of “People”.

To understand what a worker believes, it is necessary to become familiar with the worker’s experience. For instance, to communicate with a worker about “hot work”, it is necessary to reach a common understanding of what the term means. A worker’s understanding of the term is almost completely dependent upon his or her previous experience. What people believe can be seen by observing their behaviors, even if the behavior is a non-action. Observations can help identify critical behaviors that are tied to a belief that leads to unsafe acts. These observations are leading indicators to show underlying or hidden beliefs that will counter the desired safe work practices. As seen in Fig. 2, the shift in “Will” is vital to accepting new beliefs, creating new knowledge, and building new skills. With new or changed beliefs, the behavior can now move from an extrinsic behavior to an intrinsic behavior. Step Two: Hold open discussions with all stakeholders. Include all organizational levels for acceptance of changes. Open discussions are critical in order to understand the counter currents to a new requirement12. By understanding these issues, changes in beliefs can begin. By openly addressing issues and beliefs with all levels of the organization, people will align more readily with the new requirement due to involvement and a deeper understanding. Step Three: Reinforce new beliefs and behaviors. Explain the value of new requirements. Once beliefs have been changed, they must stay in place. There has to be continuous reinforcement regarding the value of new requirements2. Job briefings, classroom training, hands-on training, storytelling and use of analogies all provide the reinforcement and strengthening that is needed. Similar to professional athlete training that builds strong connections and behaviors that lead to automatic habits, this level of safety behaviors and habits can be implemented into the workplace. Building and strengthening the connections in our brains through continual training and education will result in strong beliefs becoming intrinsic safe behaviors and leading to automatic safe work habits.

Fig. 6: Critical Elements of Electrical Safety

ACTIONS Steps to Changing Beliefs Step One: Understand people’s beliefs about safety. Only after we understand what people believe can we begin to impact those beliefs. Observe and record behaviors showing resistant beliefs. Don’t attempt to change every behavior. Pick the safety behaviors that are most critical for your company or site first, then move on to others.

CONCLUSIONS Making changes in electrical safety performance requires shifting beliefs about electrical safety and the work practices used. Understanding how to discover and then change beliefs of people is the key missing piece to improvement in electrical safety performance. Observing, compiling data, studying the leading indicators, implementing change through inclusive methods, and sharing a unified belief about Safe Work Practices will fill in this missing element. The next step change in electrical safety performance must address the safety beliefs of people. It takes time, but is time well spent. Workers must be provided with new experiences which

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they recognize as a benefit. In order to create an intrinsic reaction from people (one that they believe is the right thing to do), the beliefs and behaviors of people must be willingly changed. Consequences drive beliefs and behaviors. Soon, certain, and positive consequences are the most effective in driving our behaviors. Peer pressure is one of the most powerful drivers that effect behaviors in an organization. Employee involvement in safety is a key element to developing a positive peer pressure that will not tolerate unsafe behaviors.

8. Edward L. Deci, Why We Do What We Do, New York, NY, Penguin Group. 1996

Changing beliefs comes through study, measurement, including people, and evaluating results. Providing reinforcement for intrinsic safety behaviors will create the desired outcome of improved electrical safety performance.

12. Kerry Patterson, Joseph Grenny, David Maxfield, Rn McMillan, Al Switzler, Influencer, New, NY, McGraw Hill, 2008

Appropriate Behavior

Hierarchy of Needs

Nothing Happened

I/B Re-enforcement

En ro vi t en nm

Experiences

cia l

Beliefs So

11. David Rock, Quiet Leadership, New, NY, Haper Collins, 2007

13. John Maxwell, Thinking for a Change, New York, NY, Center Street

15. Daniel Pink, Drive, New York, NY, Riverhead Books, 2009

Behaviors

A/B Re-enforcement

10. Encyclopedia Britannica, Inc. Encyclopedia Britannica, Inc. 07 Nov. 2010

14. Peter Guber, Tell to Win, New York, NY, Crown Business, 2011

Inappropriate Behavior

Safe Execution

9. A.H., Maslow, A Theory of Human Motivation, Psychological Review 50(4) (1943)

Attachment A: Appropriate vs. Inappropriate Behaviors

REFERENCES 1. Stephen R. Covey, The 7 Habits of Highly Effective People, New York, NY, Fireside, 1990 2. Howard Gardner, Changing Minds, Boston, Massachusetts, Harvard Business School Press, 2006 3. Charles S, Jacob, Management Rewired, New York, NY, Penguin Group, 2009 4. Snyder, M., & Swann, W. B., Jr. (1978). Hypothesis-testing processes in social interaction. Journal of Personality and Social Psychology, 36, 1202–1212 5. Snyder, M., & Campbell, B. H. (1980). Testing hypotheses about other people: The role of the hypothesis. Personality and Social Psychology Bulletin, 6, 421–426 6. Krause, Hidley, and Hodson, The Behavior-Based Safety Process,1990 7. Dr. Mary Capelli-Schellpfeffer et al, “Correlation Between Electrical Accident Parameters and Sustained Injury”, IEEE PCIC Conference Record, 1996, Paper No. IEEE-PCIC-96-3

16. Danny Liggett, Refocusing Electrical Safety, in the IEEEIAS Transactions Sept/Oct 2006 Daryld Ray Crow (S’68, M’72, SM’03, LSM’07) graduated from the University of Houston in 1969 with a BSEE degree. After graduation Ray went to work for the Aluminum Company of America where he provided engineering support for Alcoa plants worldwide on the design, installation, and operation of power and rectifier systems, provided plant engineering support which included electrical safety, served as team leader for writing a number of Alcoa electrical standards including the development of and training for Alcoa’s electrical safe work practice standard. He retired from Alcoa in 1996. After retiring from Alcoa, Ray worked for Fluor Global Services and Duke Energy as a Principal Technical Specialist providing design and consulting electrical engineering for plant power distribution systems and safe work practice programs, standards, and assessments/audits. Ray presently is the Principal Technical Specialist for DRC Consulting Ltd. and performs consulting work on electrical safe work practices standards, assessments/audits, electrical safe work practice training, and electrical engineering projects. He was chair of the Petroleum and Chemical Industry (PCIC) Safety Subcommittee 2004-2006, chair of the 2004 IEEE IAS Electrical Safety Workshop, is an alternate member on the NFPA 70E technical committee “Standard for Electrical Safety in the Workplace”, a member of the IEEE 1584 Committee, and was the working group vice chair for the 2007 revisions to IEEE 463 “Standard for Electrical Safety Practices in Electrolytic Cell Line Working Zones”. Ray has co-authored and presented papers and tutorials on electrical safety and auditing for the PCIC and has presented safety topics and tutorials at the IEEE Industry Applications Society Electrical Safety Workshops and IEEE IAS Pulp and Paper Industry Conference. In 2010 Ray received the IEEE IAS Petroleum and Chemical Industry Committee Electrical Safety Excellence award.

Safety Vol. 1 Danny P. Liggett (M’91, SM’98) has been employed by DuPont since 1989. He was employed by an engineering/construction firm from 1968 until his employment with DuPont. During his employment with the engineering/construction firm he worked as an electrical superintendent for 15 years. During his employment with DuPont he has worked as an Electrical Consultant with primary focus on construction activities and electrical safety. His work also involves work with maintenance activities at the DuPont sites. He is a member of the DuPont Corporate Electrical safety Team, Senior Member of IEEE, Past Chair of the IEEE IAS PCIC Safety Subcommittee and Past Chair of the PCIC Tutorials Subcommittee. He currently serves as Chair of the PCIC IAS Electrical Safety Workshop Subcommittee. Danny served as Chair of the 2000 IEEE IAS Electrical Safety Workshop. He has served on the NFPA National Electrical Code Panel 8 representing the Cable Tray Institute and the NFPA National Electrical Code Panel 6 representing the American Chemistry Council. He currently represents the American Chemistry Council on the National Electrical Code Technical Correlating Committee, as an alternate on National Electrical Code Panel 3 and as an alternate on NFPA 70E. He has authored or co-authored 15 papers on electrical safety, 10 of which have been published.

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NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

6

ALABAMA 1

2

3

4

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

ARKANSAS 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

ARIZONA

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

CALIFORNIA 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

22

23

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

36

37

30

Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power e tin , Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

COLORADO 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

CONNECTICUT 45

46

47

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

ILLINOIS 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

GEORGIA 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

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FLORIDA 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

INDIANA 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

KENTUCKY

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

IOWA 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

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Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 MAINE www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 LOUISIANA www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

MARYLAND 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

MICHIGAN 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

MASSACHUSETTS 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

MINNESOTA CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

MISSOURI 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

NEBRASKA 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

NEW JERSEY 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

NEW HAMPSHIRE

NEVADA 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

NEW MEXICO 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

NEW YORK 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

151

152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

OHIO 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

NORTH CAROLINA

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

157

158

159

160

161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

OKLAHOMA 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

SOUTH CAROLINA 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

PENNSYLVANIA

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

OREGON

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

TENNESEE 181

182

183

184

185

186

187

188

189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] TEXAS www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

197

198

199

200

201

POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

206

207

208

209

210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

UTAH 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

WISCONSIN

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

VIRGINIA

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

WASHINGTON 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

242

243

244

Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

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Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

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ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT2018 Standard for Certification of Electrical Testing Technicians.

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VOLUME 2

SAFETY Vol. 2 HANDBOOK

SERIES III

HANDBOOK

Published By

SAFETY

SERIES III

SAFETY VOL. 2 HANDBOOK

Published by

InterNational Electrical Testing Association

SAFETY VOL. 2 HANDBOOK TABLE OF CONTENTS Finding and Retaining Qualified Electrical Workers: It’s About Safety in the Workplace ...................................................................... 5 Mike Moore

The Importance of an Effective Electrical Safety Program...................................... 10 Daryld Ray Crow

Internal Electrical Safety Audit .......................................................................... 14 Terry Becker

How OSHA and the NFPA Work Together ......................................................... 21 Ron Widup and Jim White

Safety Tips for Qualified Persons ...................................................................... 23 Jim White

Rotating Machinery Hazard Awareness............................................................. 27 Scott Blizard and Paul Chamberlain

Electrical Safety Myths and Rumors ................................................................... 31 David K. Kreger

Determining Maintenance Intervals for Safe Operation of Circuit Breakers ............. 34 Jim White

Reduce Risk with PESDs Making NFPA 70E Compliance Safer .............................. 40 Phil Allen

The Electrical Safety Trifecta ............................................................................. 46 Terry Becker

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InterNational Electrical Testing Association 3050 Old Centre Kà] ¡ , Suite 101, Portage, Michigan 49024

269.488.6382

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Planning and Performing a Power Quality Survey ............................................... 48 Ross Ingall and Richard Bingham

Hand Protection ............................................................................................. 53 Paul Chamberlain

Commissioning Progress Communication ........................................................... 57 Michael Lewark

Extension Cord Safety ..................................................................................... 61 Dennis Neitzel

Significant Change to OSHA’s 1910.26 and 1926 Regulations ........................... 67 Jim White

The Impact of Electrical Safety to Maintenance: NFPA 70B and CSA Z463 ............ 73 Jim White and Jarret Solberg

Protective Devices Maintenance and the Potential Impact on Arc Flash Incident Energy ............................................................................ 80 Dennis Neitzel

Potential Impact of ISO 55000 on Maintenance Critical to Electrical Safety ........... 87 H. Landis Floyd

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InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

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Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

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Safety Vol. 2

FINDING AND RETAINING QUALIFIED ELECTRICAL WORKERS: IT’S ABOUT SAFETY IN THE WORKPLACE PowerTest 2013 Mike Moore, Shermco Industries Do you believe that positive safe behaviors and actions are inherently programmed into each human from birth or that these traits are learned as we progress in life? Do you think that some workers may not have the mental faculties to learn these positive safe behaviors and actions due to their life origin or life status? To offer any answers to these questions we must delve into some controversial topics and conversations that will surely create more questions, but it’s a much needed effort when as industry leaders that actually engage in electrical safety techniques and practices multiple times per day; we may have to make life or death decisions on the behalf of our subordinates. Electrical workers that interact with energized equipment face some very unique hazards not found in any other occupation. These electrical hazards such as electric shock, arc blast and arc flash can offer disabling injuries, traumatic burns and even worse, death. Since the late 1990’s a heightened awareness has been placed on the protection of electrical workers worldwide. Training, clothing, regulatory language, equipment labeling, hazard documentation and communication, procedures, maintenance planning/ cycles and electrical equipment engineering enhancements have positively changed the electrical workers life for the better, but we still have numerous ideological challenges to overcome with our fellow electrical workers. In this litigious society we live in today we as managers and leaders in the electrical industry have to make very unique and complicated decisions about our fellow electrical workers and the electrical contractors we hire every day. Just knowing the “electrical business”, and asking a few questions about safety practices and electrical skills isn’t going to cut it anymore. This paper will challenge the way in which you qualify electrical workers prior to their employment and how you qualify the electrical contractors that work in and around your electrical workers every day. As the manager or leader of a crew performing electrical work you have to be in the know about all the workers on your site and have the ultimate goal of keeping all of the site’s electrical workers safe. Sometimes you may just have to say no, not today, maybe you can do this task another day!

THE LABOR EPIDEMIC Before we get too far into this paper, let’s discuss the compounding challenges of retaining your current electrical workers.

The pool for skilled, safe, qualified electrical workers is basically tapped out. You have to recruit them from somebody else with better wages, better benefits or some other special deal. Hiring, training and qualifying newer electrical workers is like herding cats, it isn’t going anywhere fast. There are numerous challenges you have to think through with the newly hired workers. Why, do you ask? Read below. Purge your mind of all politics and preconceived notions about labor, the economy, the President and whatever conspiracy theory you may have and let’s look at some statistics. The United States of America is in a national labor emergency of epidemic proportions; yes, it’s an emergency when you can’t fill your ranks with skilled, qualified and ready to work technicians and engineers. The unemployment rate has consistently stayed over or around 8.2% for the last 17 months. The jobless rate has been as high as 9.2% in the last 3 years and close to 23 million people are either underemployed, out of work or have completely given up looking for work. New jobless claims are still over 350,000 per month, incomes for workers are spiraling downward, and millions of recent college graduates have nothing to look forward to after clearing the last step of their graduation stage. Additionally the current skilled workforce is losing its qualified and experienced workers at an average rate of ten thousand per year. These are the senior, experienced, knowledgeable, qualified workers that will turn 65 years of age, every day, for the next 20 years and as these 73 million workers leave the marketplace so do their skills, talents, knowledge, and inherent trade techniques. Since the end of World War II there has been an accelerating decline in skilled workers. This decline was not evident as the American economic engine revved up in the 50’s, 60’s, 70’s, 80’s, and into the roaring 90’s. The Baby Boomers were the largest contributor to the skilled labor pool while the most recent generations of “X” and emerging generation of “Y” have not met the demand of the industry to date. To further the question concerning the lack of talent in the labor pool, the streets of many of our great cities are full of the young 99%’ers’. The 99%’ers are the unemployed, twenty-somethings who are college educated, seem motivated to work and demand high paying jobs that are at a near riot status in our major cities. We constantly heard the back and forth rhetoric from our political representatives during our recent political debates about how America is moving towards a “landmark general election” and that

6 “the need for jobs” is at the center of the debate. The old class warfare debate is as strong as ever with snarling attacks from both sides. With these kinds of numbers, facts and opportunities left open, who would ever have thought that there was such a large unmet demand for skilled labor. Who would ever have thought that the need for skilled labor would be in a niche market sector like the electrical installation, maintenance, testing & repair of electrical systems and equipment? How do the newer generations of Americans fit into the demand for skilled labor and safety?

GENERATIONAL TRENDS The “Baby Boomers” The Baby Boomer Generation, by definition are people who were born between the years 1946 and 1964. As of right now Baby Boomers are between the ages of 44 and 62. The Boomer generations are the folks who built and motivated the American economy for the last 60 years. Their social, cultural and economic impact on the United States has been unprecedented in its history and is currently the single largest economic group in the United States today. The Boomers’ “work hard, play hard” mentality allowed them to have one of the highest discretionary income levels (wealth) over any other age group and they account for 45% of all consumer demand. As these Boomers retire and leave the workforce, the demands they place on the goods producers and service providers will create some challenges as there are fewer qualified workers to produce and service the retiring Boomer society. However, the Baby Boomers as a whole did not save very effectively for retirement and some may be retiring too early, or moving into a less demanding working pattern, working less rigid jobs, playing golf on weekends and dining at leisure all while still possessing their skills, talents, knowledge, and inherent trade techniques from a lifetime of hard work and no way to pass these skillsets. The exit of the Baby Boomer generation compounds an already looming crisis with the lack of qualified and skilled workers that has existed over the last 30 years. Skill levels in the US workforce have stagnated with Americans 25–34 years of age who do not possess the higher skills that their Baby Boomer parents do.

The “X Generation” The 46 million X Generation of sons and daughters of the Baby Boomers did not wholly move into the skilled trade sectors, but instead went to college, sought professional degrees, jobs and technical assignments overall, making much less income than their Boomer parents. They are officially the first generation to challenge the notion that each generation will be better off than the one that preceded it. A study, “Economic Mobility: Is the American Dream Alive and Well?” focuses on the income of males 30-39 in 2004 (those born April, 1964 – March, 1974) and is based on Census/BLS CPS March supplement data. The study, which was

Safety Vol. 2 released on May 25, 2007, emphasized that in real dollars, this generation’s men made less (by 12%) than their fathers had at that same age in 1974, thus reversing a historical trend. The study also suggests that per year increases in the portion of father/son family household income generated by fathers/sons have slowed (from an average of 0.9% to 0.3%), barely keeping pace with inflation, though increases in overall father/son family household income are progressively higher each year because more women are entering the workplace, contributing to family household income. In the next 5 years the X Generation will make up the largest majority of the workforce in America replacing the roughly 20 million skilled Boomers with only a third of the skilled workforce required to support the demands for goods and services. The balance of the X Generation will continue to work in the professional services sector.

The “Y Generation” The roughly 80 million Y Generation folks entering the workforce today are the most technologically diverse generation in American history, but they barely make the global top ten of educated and trainable workers. America is no longer a skill-abundant country compared with an increasing share of the rest of the world. As a result, in the coming decade, America will face broad and substantial skill shortages. The Y Generation prefers to work independently with self-directed projects; prefers learning that provides interaction with their colleagues who they also consider as their friends and require much more structure and direction. Many Y Generation children were born from teenagers to middle-aged moms who postponed childbearing to establish a career. One third of this generation was born to single, unwed mothers. This generation is polite, believes in manners, adheres to strict moral codes, and believes in civic action. This is a generation that places a generally high value on making money - more than any previous generation - and they see education as a means to this goal.

Workforce Challenges Like the X Generation before them, they seek professional careers. Studies predict that Generation Y will switch jobs frequently and will not have the passion for “the company” that the older and more career established employees do. They require learning to be entertaining and fun, and become quickly bored in a learning environment that is not highly active and interactive. With the global booming numbers of Y Generational workers added to the employment pool, economic prospects for the Y generation look bleak due to the late 2000 and 2008 recessions. As of July 2012, the seasonally adjusted jobless rate for people 20 to 24 years old was 13.5 percent. For workers aged 25 to 29, the rate (available only on an unadjusted basis) was 9.3 percent, a full percentage point above the national rate. As the Boomers exit the workforce over the next 10 years, the small in scale X generation will try to fill the gap. The X generation

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Safety Vol. 2 will never stand a chance to meet the needs of the demands of the industry, it was just too small. As the Y generation moves into the workforce they do not seem to be as motivated to take skilled labor or “hands-on” jobs. The industrial sector does not seem appealing to the Y Generation who chose to attend college and graduated with expectations of hitting the labor pool at the same income level as their parents. It remains to be seen where this generation will end up, but whatever the outcome, working long distances from home in remote isolated areas with limited communications and long workdays away from social circles may create a challenge in retaining these folks. The question arises; who in the heck is going to move this country forward in the next 10 – 20 years?

Generations and Change With that said, it’s time to start off with a shot across the bow while trying to write a politically correct paper. The generational classes may affect work ethic; how generations think and react about how their personal safety and the safety of those that work around them? It’s done, I said it; the successful development of a safety minded culture may be affected by age! One example, younger workers may consider themselves as bulletproof and invincible and may exhibit a complete lack of fear and awareness. They may not have the intensity or faculties to evaluate their task and the hazards involved with the task at hand as an older experienced worker would who may feel he has more to live for and chooses not to take unreasonable risks. This generational related risk-taking behavior is not new among workers in any organization. A second example of this behavior is that Baby Boomers may be more likely to cut corners to save money or get the job done on time. As the loyal and faithful worker the Boomer is concerned with fulfilling the profit potential of an organization, so they may take more risks. So are these statements real or just some arbitrary gut feeling? The American Society of Safety Engineers is urging business to modify their workplace safety efforts to accompany a changing workforce. Currently the workplace injury rates for older workers are the lowest of any age group, but their fatality rate is the highest. The U.S. Dept. of Labor’s (DOL) workplace statistics for 2004 show that those 64 and older had the lowest number of workplace injuries, but the fatality rate for those 55 and older rose by 10 percent. In 2003, workers 65 and older “continued to record the highest fatality rate of any other age group, more than three times the rate of fatalities for those aged 25-34,” according to the DOL. Most of these fatalities were transportation-related, from falls, from being struck by an object and from homicides. This leaves another question that is usually bypassed, discussed in another manner, or worse never addressed. How do you communicate the very real challenges utilizing the skills of the workers in each scenario? As an electrical worker they are reviewed and receive salary advances based off of their performance, skills and

safety culture. Sometimes you just have to say no, not today; if a worker does not have the skills or the ability to perform a high risk task, reassignment is needed!

SAFETY AND BEHAVIORS Behavior Based Safety Culture The behavior-based safety culture on any worksite is based on the notion that the “safety culture” is a learned culture and that culture is a product of organizational learning through behavioral awareness and training. If these behaviors are the ‘ingredient’ that pulls everything together to lead to a safe and healthful job completion, then the additional ingredients must be high quality management policies, job planning documents, quality project materials, serviceable job related equipment and qualified workers. When all the correct ingredients are in place they trigger people’s safe behavior on the job. For example, if quality equipment was missing from the job site, people will typically become innovative and either use make-shift equipment, or take short-cuts just to get the job done. This would be a key ingredient for unsafe behaviors. In other words, the lack of quality ingredients will lead to unsafe or risky behaviors. The negative aspect of a behavior-based safety culture is based on the notion that some people often find that unsafe behavior is rewarding in some way. For example you hear “safety practices and paperwork make the job slower and take more people to the job” or that the use of PPE is a punishment for prior poor performance, “PPE is too burdensome to work in, this task will only take a minute, let’s get it done before the boss gets in and sees us without PPE”. The more this risky behavior goes on and workers are injured, the more the behavior is reinforced in the minds of the workers. Jim White, who is an electrical safety and skills trainer at Shermco Industries, always comments in safety discussions similar to this one, “that the reason that folks survive situations like this is that they are either lucky or good”. With this said, it sounds as if you buy the best project and safety stuff, employ the very best folks, have the very best management policies and procedures, have the best job and safety skills and the very best safety training that coincidentally you will have the better safety culture than that of a less fortunate company that performs similar work. This just goes to show that companies that are truly safety driven and actually instill safety in the minds of their workers have the best overall safety records, lower incident rates and higher morale in the ranks. When hiring experienced electrical workers from other employers in the industry you must understand the safety culture from which they came. Asking questions about the qualifications and work experiences of the electrical worker is a given, additionally direct and specific questions about their past employers management policies, practices, job planning documents and how they maintained their job-related equipment can give you a view into the behavioral practices of that worker. Electrical workers that

8

Safety Vol. 2

are moving from lower tier companies may require a more robust approach acclimating them to the safety culture that you have in place. It makes all the sense in the world to pair new electrical workers with the best-of-the best in your organization so that your safety culture is rubbed into the newer electrical worker on the job.

cal limits of approach, electrical personal protective equipment (PPE), servicing energized equipment, Lock Out/Tag Out, alerting techniques, test instruments calibration, how to understand NFPA Labeling of electrical gear, responsibilities for Electrical Safety and responsibilities for the training requirements.

When hiring contractors a much bigger set of responsibilities and liabilities are introduced to the worksite, as well as new risks exposed to your employees. The introduction of third-party contractors to the worksite is one of the biggest exposures of liability and risk that you face regardless whether your company is the host employer or a subcontractor to the host. The electrical contractor is usually recognized as “knowledgeable” and usually gives the impression that “they know what they are doing”. Most owners trust the contractor completely based off of some perception they have endless labor resources and capabilities. Additionally qualifications such as “Journeyman” & “Master” electrician are sometimes viewed and accepted as being highly qualified to perform high-risk tasks with no regard to questioning the safety and skills training of the electrical workers, the company’s management policies, practices, job planning documents or how they maintained their job-related equipment. If the worker will need additional training and evaluation he may be a hazard to himself. Sometimes you just have to say no, not today, maybe never to a contractor, even if you have had a long term relationship with them!

Now that the company has been evaluated, let’s move to the workers, and evaluate them before they ever hit the worksite. Request copies of the resumes of all workers especially the managers. Request copies of training certificates for skills and safety training and start asking questions of all the electrical workers about electrical hazard identification and mitigation and how they work within the management policies and practices. Once the contractors arrive on the worksite, be involved in the contractor’s hazard risk analysis/ job safety analysis process. Inspect the contractor’s tools and equipment for calibration, serviceability and “prior use”. Once the contractors are on site continue to inspect the worksite, ask questions and look for hazards, as well as communicating and mitigating any hazards that may be found.

How do you ensure you’re getting a safe contractor in the door that has the desired safety culture and technical depth and talent? Prior to the performance of any work you should qualify the company to make sure their safety goals align with yours, and then qualify the electrical workers to ensure that they can safely perform their services for your customer and lively hood, as well as safely interact with your electrical workers. ● As the owner or host of an electrical contractor it’s time to start the game of show and tell. At the very minimum you need to see the following from the contractor prior to the performance of any work. Always start by asking for specific information about the company such as OSHA 300 records of which can tell you a lot about past illnesses and injuries that arise from exposures in the work environment.

Be in touch with the contractors at an almost personal level. There are some factors that affect how frequently and how closely you as the controlling employer must inspect them in order to meet the legal case standards of reasonable care. Reasonable Care is the legal obligation imposed on an employer by OSHA. It requires they adhere to a standard of reasonable care to “foresee hazards that could potentially harm others”. That’s legal language meaning that you are responsible for your contractors and what they do and you have to show that you clean up after them or keep them safe and healthful. First thing you have to show is how much the controlling employer knows both about the safety history and safety practices of the employer it controls and about that employer’s level of expertise. This should be documented prior to hiring the contractor. Second you have to show how you will enforce the other employer’s compliance with your safety and health requirements. Third you have to show that you have a plan to enforce the other employers’ compliance with safety and health requirements with an effective, graduated system of enforcement and follow-up inspections. Better said, yet better proven by documentation in a safety plan prior to the start of the project

● Ask for their recordable rate, also known as the TRIR which is a measure of the rate of recordable workplace injuries, normalized per 100 workers per year.

If the contractor balks at these requests, sometimes you just have to say no to them, not today, you’re not qualified to work for the owner or host!

● You need to also request to review their experience modifier or “EMR,” which is the number used by insurance companies to gauge the past cost of injuries, as well as the future chances of risk. Usually an EMR of 1.0 is considered the industry average, but anything over .5 to .6 deserves some Q & A. Lastly, obtain copies of the contractor’s management policies and practices such as their ESP or electrical safety program.

Rational and Emotional Intelligence

● Key points of review need to be their policies and procedures that cover their electrical safe work practices, electrical energized work practices, electrical shock approach boundaries, electri-

Emotional intelligence (EI) refers to the ability to perceive, control and evaluate emotions. Some researchers suggest that emotional intelligence can be learned and strengthened, while others claim it is an inborn characteristic. Though at first, the thought you may have is how does EI have anything to do with safety and safety culture? It has much to do with how we perceive, reason, understand and manage the verbal or nonverbal external information we receive and how it’s delivered and how we accept this verbal or nonverbal information and mentally process that in-

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Safety Vol. 2 formation. We all perceive others through the filter or perspective of our own cultural upbringing, often without being aware of it: communication can go wrong without our understanding why. Think about it, if you are worried, having a bad day, frightened, or even happily excited, your thought processes can be impacted as they would be if you were engaged in an intense phone call or after having consumed several alcoholic drinks. Think how “off your game” you would be if your boss had just chewed you out, your significant other just left you or your dog died and you were in the midst of performing high risk energized work, your thoughts would not be 100% on the task at hand. Keeping emotions in control while in the performance of electrical work isn’t easy, but taking steps to clear the mind makes a huge difference. These distractions are huge and could be documented on the JHA or alternate sources as a mental release, or a way to communicate that added hazard that you may need a little help in switching to your “A game”. Regardless how you feel about the situation you can’t allow yourself or other workers to fall into your trance. Emotional development plays a key role in electrical safety as well. If the developmental level of a person, which is controlled by and usually the same as the highest parent, is that of a teenager, then some thoughts about the emotional maturity of the electrical worker need to be thought through. We know of workers that seem to peek at a low to moderate skillset and never have higher aspirations or achieve what they ought to be capable of as their tenure grows. This may be an ED or EI issue. Much research is underway on the subjects of emotional intelligence and emotional development and there is key evidence emerging about the impact these two subjects have on the workforce. When managing electrical workers being involved in their personal life is tough and it is usually sacred ground not to be crossed, but when the performance of their duties can be affected by their current life challenges the intrusion is justified and legally required. Sometimes you just have to say no, not today, reassignment!

Programming the Change Changing the safety culture in any company involves some very critical elements. One major element is leadership! Senior management has to be in the lead and the prime influence to make the safety culture change a reality. This means creating, directing, reinforcing, and enforcing management policy at all levels of the organization with full visibility, best indicated by the time they devote to safety matters. The middle management down through the supervisor and line management have to be empowered and have some degree of autonomy for safety initiatives. Leaders have to stay relevant and keep abreast of new skills and techniques to operate in this new era, and the challenges they will face if they decide to remain stagnant. Leaders must be challenging, engaging, inspiring and influencing, but most of all they must have high credibility in the organization, meaning that you are

willing to admit mistakes to yourself and others, give honest information about safety performance even if it is not well received, and follow through on safety-related commitments. Excellence in safety performance easily correlates with excellence in other performance metrics such as productivity, profitability, quality, moral and customer service. Work place demographics are changing, with employee populations growing more diverse in background, belief, and geography. So too are business practices. The second critical element for changing the safety culture in any company involves acknowledging that safety is a “core business value” and integral to the very existence of the organization. This key element must be communicated and instilled in the individual employee at work and at home. This means it’s a functional lifestyle change from risk taking behaviors at home and with the family. The employee actually becomes an active part of building a safety culture and will be able to protect what really matters to them at work and away.

SUMMARY Once again, when discussing the topics of life origin and life status controversy ensues almost every time and someone cries afoul, but when it comes to the safe performance of your duties in and around electrical installations, some people just don’t get it. As a leader you make a determination if a person is not qualified to work for the day, un-trainable or un-savable and these decisions are especially tough when it’s nearly impossible to find a trained and qualified replacement worker to take up the slack, but not having a preventable injury, or worse a death on your conscience is huge! Just a note of reference about generational workers; at times stereotypical references are made about the generational aspects of the American culture and it’s important not to make assumptions about individuals based on age. Not every boomer is ignorant of technology and not every Generation Y worker is lazy and uncommitted. Blending the experience of the older generations with the freshness of younger generations can yield positive results for employers. Multigenerational viewpoints can enrich the workplace, so organizations should use this as a strength. The employment contract of the 21st century is different from when the baby boomers first entered the workforce. The relationship is more fluid for both employer and employee – younger employees may be more mobile and appear less loyal, but the same is true of most organizations and has been for the last 70 years.

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Safety Vol. 2

THE IMPORTANCE OF AN EFFECTIVE ELECTRICAL SAFETY PROGRAM PowerTest 2013 Daryld Ray Crow, DRC Consulting, Ltd.

ABSTRACT The purpose of this paper is to cover the importance of developing, implementing, and maintaining an electrical safety program. It includes key elements of an electrical safety program and provides information on where the gaps may be in your existing program. Index Terms — Electrical Safety Program, Key Program Elements, Safe Work Practices

INTRODUCTION Developing, implementing, and maintaining an electrical safety program is critical to help ensure the safety of personnel working in your facility. Having an electrical safe program is a mandatory requirement in NFPA 70E “Standard for Electrical Safety in the Workplace” and CSA Z462 “Workplace Electrical safety”.12 Both standards require the employer to implement and document an overall electrical safety program that directs activity appropriate for the voltage, energy level, and circuit conditions. The electrical safety program must be written, published, and available to all employees. The electrical safety program must be appropriate for the conditions that exist on the site. Electrical safety training of your personnel and auditing of your electrical safety program as well as auditing of field work should be a requirement in your electrical safety program.

REASONS TO HAVE AN ELECTRICAL SAFETY PROGRAM Most incidents and injuries related to electrical systems can be avoided by following the safe work practices outlined in an effective electrical safety program. Besides the personal pain of suffering an injury, incidents can result in lost time, medical costs, equipment damage, production loss, and legal costs. Four important reasons to have an electrical safety program are: it’s the right thing to do, the legal aspects, it documents rules, policies and practices, and the economic issues.3

It’s The Right Thing To Do The electrical safety program should be based on and require an attitude of caring. It should include concern about the well-being and safety of employees and their co-workers. An effective electri-

cal safety program provides written direction to workers, establishes safe work requirements, and provides performance measures. It includes guidelines to ensure a safe workplace for all employees who work in an environment where an electrical hazard may exist.

Legal Aspects Meeting the requirements of local regulation and consensus standards including safe guarding employees from shock and flash hazards is mandatory. U.S. OSHA regulations, Canadian Provincial and Federal OH&S Regulations, ANSI Z10, CSA Z1000, EN 50110-1, NFPA 70E, and CSA Z462 are examples of these documents.

Documents Rules, Policies, and Practices The program should provide clear guidance and requirements that include documented work rules, policies and practices. The employer is responsible to ensure that all hazards in the workplace are understood. The employer must work with employees to generate procedures for implementation by employees and train employees to understand and implement the electrical safety program and associated procedures. Documentation should include single line drawings that are up-to-date and readily available. The employees are responsible for implementing the electrical safety program principles, controls, and procedures. An effective electrical safety program is a powerful resource for arc flash & shock hazard management and allows for enforcement.

Economic Issues Economics is another reason for implementing an effective electrical safety program. A written program that provides clear guidance for accepted work practices to employees will help prevent low morale and productivity in the workplace. The policy should include a requirement for investigating and reporting all incidents from a fact finding not fault finding concept to find the root causes of incidents. This concept will help prevent these issues from happening in the future. Preventing future incidents will provide a safer work place for employees, lead to minimizing medical costs, legal costs, insurance costs, and repair and replacement of failed equipment, as well as loss production due to failure of equipment. Dollars spent on implementing an effective electrical safety program reportedly results in a 400 percent return on Investment.4

Safety Vol. 2 DIFFERENT APPROACHES TO CREATING AN ELECTRICAL SAFETY PROGRAM There are different approaches to creating an effective electrical safety program. One can use existing company resources. This approach could utilize a key safety expert within the company or it could use a companywide safety team/committee consisting of cross functional and facilities personnel to write the program. One can also use an outside consultant that specializes in providing electrical safety programs for different companies. If an outside source is used, the written document should be reviewed and approved by a company safety team/committee.5 Establish an electrical safety team/committee to manage the electrical safety program, Implement electrical safe work practice training, and provide overall guidance for the electrical safety program. For an electrical safety program to be successful it requires sponsorship from key upper management. The program must be written, be readily available to all employees, and require training to ensure understanding of the requirements in the document. The program should mandate electrical safe work practice training and refresher training that includes class room training and on-the-job training. The electrical safety program needs a champion(s) at the worker level. Employee involvement in safety is a key element to developing a positive peer pressure that will not tolerate unsafe behaviors. 6

KEY ELEMENTS OF AN ELECTRICAL SAFETY PROGRAM The purpose and scope of the electrical safety program should be clearly defined. Identify the objective and limitations of the program including the support by management and basic corporate beliefs. (Example: “All injuries are preventable. Sound safety practices are a condition of employment”).5 The program should identify the roles and responsibilities of management and supervisors, employees, contractors, and visitors. Program principles, preventive and protective measures, and the requirement for documented work procedures should be included. The program needs to have a requirement to ensure the qualification of employees that includes demonstration of understanding and proficiency to perform required tasks. Competency must be demonstrated. The requirement should include a review of the employee’s current roles and responsibilities and define clear responsibilities and requirements (Ensure the right worker is doing the right work) 7 Mandate periodic audits of the electrical safety program and its rules, policies, and practices to ensure compliance and to verify that the preventive and protective control measures are working. Auditing should include periodic audits at the supervisory level, annual internal audits, and external audits not to exceed once every three years.8 A safety program should include a requirement for holding a meeting with contractors before allowing them to work on your

11 site. The meeting should include discussions on hazards that may exist during the contract employer’s work and the safe work practice requirements that must be followed during work at your facility. The meeting should also include feedback from the contractor of any hazards that may be created by the contactor’s work. The meeting should be documented by the employer.12 A job briefing should be required before start of work. Effective job briefings save lives. Include the requirement that single line drawings are up-to-date and readily available. Guidance on the requirements and rules for switching procedures should also be provided. Include the requirements for working inside the Limited Approach Boundary of energized electrical conductors or circuit parts and the requirement to create an electrically safe work condition before start of work (exceptions: diagnostic testing, trouble shooting, infeasibility). The program should include other electrical safety issues specific to your facility such as specialized equipment and the associated work tasks related to that equipment.9 Only electrically qualified persons should be allowed to work on exposed energized electrical conductors or exposed parts above 50 volts. Working on exposed energized electrical conductors and circuit parts should only be allowed as a last resort. Energized work should only be allowed when an energized electrical work permit (EEWP) is issued by upper management. The EEWP should include the requirement for a hazard risk evaluation procedure before start of work on energized conductors or circuit parts. The hazard risk analysis should include a shock hazard analysis and an arc flash hazard analysis (see annex F in NFPA 70E and CSA Z462). Identify the training requirements for electrically qualified and unqualified persons. Training should include but is not limited to working near un-insulated overhead power lines, the use of barricades/work zones, understanding the shock boundaries (limited, restricted, and prohibited), the arc flash boundary and requirements for arc rated clothing and PPE, emergency procedure training, the requirements for first aid and emergency procedures including CPR, methods of release of victims from contact with exposed energized electrical conductors or circuit parts, and training on the care, use, and maintenance of electrical specific PPE, tools, and equipment including the use of temporary protective grounds where required. Lockout/tagout training is mandatory. All training must be documented.10 Only qualified people should be allowed to use electrical test instruments and equipment. Identify the type of meters and equipment that can be used at the facility. The program should identify required test procedures and documentation requirements for rubber insulating protective equipment and insulated tools and equipment including insulated bucket trucks. Include the requirement to use GFCIs or an assured grounding program on all cord-and-plug connected equipment. Consider the use of battery operated tools where appropriate.

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HIERARCHY OF CONTROLS

Training and Refresher Training

Safety-related work practices and PPE requirements are just two components of an overall electrical safety program. ANSI/AIHA Z10, CAN/CSA Z1000, ISO 14001, and OSHA 18001 provide additional information on the elements that should be included in an overall safety program. “Hierarchy of Controls” should be considered when creating a holistic safety program. The key elements include Engineering Controls, Policies and Procedures, Training – Classroom and On-The-Job training and Refresher Training, and Personal Protective Equipment.11 All these elements are important; however, the most effective element is engineering controls. Design the equipment and electrical system to prevent or minimize people being exposed to electrical hazards.

Training should include classroom training and on-the-job training. Both types of training are important. Classroom training provides an overview of current electrical safe work practices and procedures. Classrooms allow for discussions to clarify the material being presented. Classroom training also provides the opportunity for a greater depth of understanding and a better grasp of the principles behind the information being presented. On-the-job training uses a hands-on training method to ensure understanding of the safe work practices and gives the opportunity to demonstrate proficiency in the work practices involved.

Engineer Control Some elements of engineering controls are listed below:

Employees should receive additional training (or retraining) if any of the following conditions exist: ● If the supervision or annual inspections indicate that the employee is not complying with the safety-related work practices

● Remote racking of breakers

● If new technology, new types of equipment, or changes in procedures necessitate the use of safety-related work practices that are different from those that the employee would normally use, or

● The use of maintenance switches to minimize the time employees may be exposed to an arc flash

● If he or she must employ safety-related work practices that are not normally used during his or her regular job duties

● Arc-resistant switchgear ● Remote switching of breakers

● Additional use of differential relays ● Zone selective interlocking (Smart relays to minimize tripping time) ● High resistant grounding ● Hi-Speed Light Sensitive Relays ● Hi-Speed Light Sensitive Relays With Current Detection ● The use of two tie breakers in series ● The use of 3-cycle breakers ● Type 2 low voltage starters ● Ground and Test Devices ● Integral ground switches interlocked with associated breakers ● Hi-Speed Grounding Switch - “Crowbar” Switch ● The use of Ground Ball Studs ● Installation of “Mimic Bus” on switchgear ● “Fed From/ Feed To” information on equipment labels

Policies and Procedures Policies and procedures include: 1. Program Principles – the principles on which the program is based, 2. Program Controls – the controls set how the program is to be measured and monitored, and 3. Program Procedures – the procedures to be used during performance of work.

Refresher training should be conducted no less often than every three years. In today’s rapidly changing environment refresher training may need to be provided more frequently. Refresher training is important to ensure employees are informed on the leading edge thinking of safety.12

Personal Protective Equipment Personal protective equipment is required to help prevent shocks and burns. If things go wrong during a task, the PPE may prevent injuries from occurring.

CONCLUSION Creating and maintaining an electrical safety program that documents and meets your company’s specific needs and the needs of the various stakeholders is a key to success. Your electrical safety program should include key elements such as holding effective job briefings, creating an electrical safe work condition before start of work, and requiring the use of appropriate personal protective equipment for the task. The program should also include well-defined roles and responsibilities of management and employees, training and retraining requirements, holding safety meetings with contractors, and auditing of the program and field work. Ensuring a thorough knowledge and understanding of these rules, principles, and procedures by upper management, supervisors, and employees will reduce risk and save lives. Including these elements will ensure a strong electrical safety program.

Safety Vol. 2 REFERENCES 1

NFPA 70E, Standard for Electrical Safety in the Workplace, 2012

2

CSA Z462, Workplace electrical safety, 2012

3

Ray and Jane Jones, Electrical Safety in the Workplace, 2000

4

R.L. Doughty, R.A. Epperly, and R.A. Jones, Maintaining Safe Work Practices in a Competitive Environment, IEEE Transactions 1991

5

D. Ray Crow, Your Electrical Safety Culture Starts With Your Electrical Safety Program, Tomas A. Edison Institute Conference, 2005

6

Krause, Hidley, and Hodson, The Behavior-Based Safety Process, 1990

7

James R. White, Electrical Safety, A Practical Guide to OSHA and NFPA 70E, 2012

8

John D. Aeiker, D. Ray Crow, Shahid Jamil, The Importance and Process of auditing an Electrical Safety Program, IEEE PCIC 2008

9

Kenneth G. Mastrullo, Ray A. Jones, Jane G. Jones, The Electrical Safety Program Book, 2003

10

Cooper Bussmann, Safety Basics – Handbook for Electrical Safety, 2004

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ANSI Z10, Occupational Health and Safety Management Systems, 2005

Daryld Ray Crow (S’68, M’72, SM’03, LSM’07) graduated from the University of Houston in 1969 with a BSEE degree. After graduation Ray went to work for the Aluminum Company of America where he provided engineering support for Alcoa plants worldwide on the design, installation, and operation of power and rectifier systems, provided plant engineering support which included electrical safety, served as team leader for writing a number of Alcoa electrical standards including the development of and training for Alcoa’s electrical safe work practice standard. He retired from Alcoa in 1996. After retiring from Alcoa, Ray worked for Fluor Global Services and Duke Energy as a Principal Technical Specialist providing design and consulting electrical engineering for plant power distribution systems and safe work practice programs, standards, and assessments/audits. Ray presently is the Principal Technical Specialist for DRC Consulting Ltd. and performs consulting work on electrical safe work practices standards, assessments/audits, electrical safe work practice training, and electrical engineering projects. He was chair of the Petroleum and Chemical Industry (PCIC) Safety Subcommittee 2004-2006, chair of the 2004 IEEE IAS Electrical Safety Workshop, is an alternate member on the NFPA 70E technical committee “Standard for Electrical Safety in the

13 Workplace”, a member of the IEEE 1584 Committee, and was the working group vice chair for the 2007 revisions to IEEE 463 “Standard for Electrical Safety Practices in Electrolytic Cell Line Working Zones”. Ray has co-authored and presented papers and tutorials on electrical safety and auditing for the PCIC and has presented safety topics and tutorials at the IEEE Industry Applications Society Electrical Safety Workshops and IEEE IAS Pulp and Paper Industry Conference. In 2010 Ray received the IEEE IAS Petroleum and Chemical Industry Committee Electrical Safety Excellence award.

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INTERNAL ELECTRICAL SAFETY AUDIT PowerTest 2013 Terry Becker, P.Eng., ESPS Electrical Safety Program Solutions Inc..

OUTLINE Occupational health and safety management systems include a requirement for audit. Safety in the workplace must be measured. If you implement preventive and protective control measures, how do you know they are providing the safety performance and reducing risk related to workplace hazards? With respect to electrical hazards, have you developed and implemented an Electrical Safety Program? If you have an Electrical Safety Program does it include a requirement for Auditing and Corrective Actions? New in NFPA 70E-2012, is Article 110.3(H) and CSA Z462, Clause 4.1.7.8 Electrical Safety Auditing. This new content outlines a requirement for auditing a developed Electrical Safety Program every three years. It indicates that the controls used in the “field” need to be verified as being followed. The best due diligence for an employer for electrical hazards management is to implement a comprehensive Electrical Safety Program. The best method to determine the performance of your Electrical Safety Program is by completing an audit and implementing prioritized corrective actions against the findings.

QUESTIONS TO ASK YOURSELF? There is a lot of activity in industry in the United States and Canada with respect to Workplace Electrical Safety. Employers are taking more of a reactive approach to “dealing with” arc flash and are neglecting shock. Employers are taking a “bottom up” approach to the implementation of preventive and protective control measures to mitigate or reduce the risk of exposure to workers to arc flash and shock hazards. Electrical Specific PPE, Tools & Equipment are been procured first without understanding why it is required and how a Qualified Electrical Worker would determine when they need it. Engineering incident energy analysis studies are been completed when workers have not training and there is no arc rated PPE procured yet. Engineering incident energy analysis studies are being complete and reports issued to companies been reviewed to validate that they are correct. There is a lack of the development and implementation of Electrical Safety Programs in industry. Implementing and auditing the Electrical Safety Program is the best way to sustainably manage electrical hazards. When companies do implement Electrical Safety Programs they may miss three critical elements: Incident Reporting, Management and Investigation, Electrical Incident Emergency Response, and Electrical Safety Audit. An Internal

Electrical Safety Audit identifies opportunities for improvement in the application of preventive and protective control measures. ● Have you implemented an Electrical Safety Program? ● Do your Qualified Electrical Workers “Establish an Electrically Safety Work Condition?” Do you have a LOTO Program and is it being followed? ● Have you considered Engineering “Safety by Design” controls? Have you had an Engineering Incident Energy Analysis completed? Was incident energy mitigation recommended and was it implemented and is it working? If you installed detailed Arc Flash & Shock labels as the employer, did you confirm the design of the label or did you let the engineer use the software to determine the label? ● Do your Qualified Electrical Workers establish an Electrical Work Zone with red “Danger” tape? Are other Warning signs in place when required? Have you implemented the requirements for a Safety Watch for high risk work tasks? ● Are your Qualified Electrical Workers following the requirements of your Electrical Safety Program? ● Do you have Electrical Safe Work Procedures developed and are they utilized? Have they been updated recently to align with NFPA 70E-12 or CSA Z462-12? ● Is the Electrical Specific PPE, Tools & Equipment you procured the right PPE, has it been inventoried, was it the right size for workers, stored properly, performing as intended, tested to acceptable frequencies, and properly cared for, used and maintained? Have you checked the laundering of the arc rated clothing? ● Do you complete electrical equipment maintenance? Do you manage any environmental contamination related to your energized electrical equipment? Have you identified the most critical electrical protective equipment and completed maintenance for it at an acceptable frequency? ● If you have an Electrical Safety Program, have you completed an Internal Electrical Safety Audit, identified gaps and prioritized corrective actions?

WHAT IS AN ELECTRICAL SAFETY AUDIT? Occupational health and safety management systems identify auditing and provide guidance on what is required. Auditing can

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Safety Vol. 2 be completed in different forms, Supervisory Level, Peer to Peer, Internal Electrical Safety Audit, External Electrical Safety Audit, and Qualified Electrical Worker Electrical Safety Competency Validation. Safety auditing follows a structured process to ensure consistent and defendable results. Verification and validation to measure performance is accomplished by: Interviewing management, supervisors and workers, Reviewing documentation, and Observations/ Inspections. Findings by performing an audit can be defended and corrective actions implemented to improve performance and ensure risk reduction measures are working as intended.

WHY SHOULD I PERFORM AN INTERNAL ELECTRICAL SAFETY AUDIT? Without completing an Internal Electrical Safety Audit you have no way to confirm that the preventive and protective control measures you have invested time, money and human resources to implement are working at all or as intended to reduce risk of exposure of workers to arc flash and shock?

WHAT DO I DO WITH THE RESULTS? Completing an Internal Electrical Safety Audit without prioritizing the findings to implement corrective actions will defeat the purpose of the Internal Electrical Safety Audit. Ensure that you review the findings with the Electrical Safety Steering Committee that you constituted for review and management of electrical hazards. The Electrical Safety Program Manager should then present to Management the findings and recommended prioritized corrective actions.

CONCLUSION Without performing an Internal Electrical Safety Audit you have no way to measure electrical safety performance and ensure your investment of time, money and human resources is effective and mitigating or reducing worker risk of exposure to electrical hazards.

A PICTURE IS WORTH A THOUSAND WORDS:

How do you know if you don’t check?

HOW CAN I COMPLETE AN INTERNAL ELECTRICAL SAFETY AUDIT? Internal Electrical Safety Audits are typically completed on an annual basis. A formal project is initiated and a schedule created for the Internal Electrical Safety Audit. A project manager should be assigned the responsibility; this is typically the Electrical Safety Program Manager. The Electrical Safety Program Manager will notify management, supervisors and workers that a scheduled Internal Electrical Safety Audit is planned and will involve their participation for interviews and retrieval of documentation. Communication to workers that work task observations will be completed either planned or unplanned. Electrical power distribution equipment and Electrical Specific PPE, Tools & Equipment inspections will be scheduled. Permission must be received to take digital pictures of findings, good or bad. The Internal Electrical Safety Audit should also identify “best practices” and recognition provided.

Should there be tags on these locks?

WHO PERFORMS THE INTERNAL ELECTRICAL SAFETY AUDIT? An Internal Electrical Safety Audit can be implemented by an individual or a team. The Internal Electrical Safety Audit needs a “Lead Auditor” identified. Qualified Electrical Workers should be engaged to participate in the audit as part of the audit team.

Is this an approved set of Temporary Protective Grounds?

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Safety Vol. 2

Is this an approved set of Temporary Protective Grounds?

Is this an approved set of Temporary Protective Grounds?

Installing engineering incident energy mitigation is a good practice.

Is that wiring energized? Is it properly abandoned?

Does this meet the CEC or NEC? Would you stick your hands into this enclosure?

How far should temporary power go? Where does it go, do we know? How long is temporary?

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Are the wiring methods approved in this energized enclosure? Is this an acceptable condition? Would you stick your hands into this “magic box?”

Is the VFD cooled properly sticking out of the MCC? Don’t worry about all of the other open doors on this energized 600V MCC? Is this a normal condition for this energized equipment?

To the right is a cable tray penetration through the wall and there is a blizzard and snow is blowing into the electrical room and melting? Is that ok? Does the cable tray wall penetration meet the NEC or CEC?

If I told you there was a vent above this energized 480V MCC and there was a blizzard outside and snow was blowing backwards through the vent would you believe me? Yes, that is a small snow drift accumulating on top of the energized MCC.

If the electrical equipment to the right of the snow was energize, would there be a problem?

It may be tough to see it, but there is a pool of water in the middle of the picture on top of this high voltage energized switchgear. Is that ok?

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Safety Vol. 2

Is this detailed Arc Flash & Shock label really correct? Did a software program create it? Did a lawyer create it? Did the Professional Engineering endorse the use of this label?

Is this detailed Arc Flash & shock label correct? Does the Professional Engineer that included it in his “Stamped” report know if it is correct? What information is wrong on this label and is this same information wrong in the “Stamped” report?

Over 3 foot long rack in, rack out tool. This is good and extends the Working Distance.

Is the information on this label correct to IEEE 1584? Would the Qualified Electrical Worker know what it means and be able to ask his Supervisor?

Is all of the Electrical Specific PPE, Tools & Equipment inventory present in this locker?

Are any of these arc flash suits fit for use? What sizes are available? Where are the arc flash suit hoods and do they have fans and is the lens dark brown or very light greet tint?

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Would I throw my own personal clothes into a closet or would I fold them and or hang them?

Is the leather protector glove the right leather protector glove for the rubber insulating glove?

Will this “lab coat style” arc flash suit jacket protect me?

Should I use this insulated hand tool?

Is “electrician’s tape” supposed to be used on the shaft of a screwdriver? Is it approved?

Which arc rated face shield would you use if you had to choose, the one on the left or the one on the right?

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Would you use this? Do you pre-use inspect your Electrical Specific PPE, Tools & Equipment?

Does your company own one or more of these Rescue Hot Sticks?

Would you use this for arc flash protection for your face?

Terry Becker, P.Eng., is the owner of ESPS Electrical Safety Program Solutions Inc. in Calgary, Alberta, Canada. Terry has over 24 years experience as an Electrical Engineer, working in both engineering consulting and for large industrial oil and gas corporations. He is a Professional Engineer in the Provinces of Alberta, British Columbia, Saskatchewan, and Ontario. Terry is the past Vice Chair of the CSA Z462 Workplace Electrical Safety Standard Technical Committee, and currently an Executive Committee member, voting member, and leader of Working Group 8 Annexes, as well as a member of the IEEE 1584 Committee, the CSA Z463 Guideline for Electrical Equipment Maintenance Standard Committee, and a member of the NFPA 70E Annexes Working Group.

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HOW OSHA AND NFPA 70E WORK TOGETHER NETA World, Spring 2014 Issue Ron Widup and Jim White, Shermco Industries

In 1970, President Richard Nixon signed into law the Occupational Safety and Health Act (OSHA). At that time 14,000 work-related fatalities and 2.5 million disabling injuries were reported each year. The workforce was approximately one-half what it is today, maybe a bit less. Yet still today, according to the latest data from the Bureau of Labor Statistics, 4,690 workers were killed on the job in 2010, an average of 13 workers per day. The cost of job-related injuries and illnesses is a staggering 250 billion dollars to 300 billion dollars per year. With data from the U.S. Bureau of Labor Statistics and compiled by the Electrical Safety Foundation International, electrical-related fatalities have shown decreases since 1992, the first year data was available. See Figure 1. In 2010 there were 163 fatalities resulting from contact with electricity, a huge decrease from 1994 when there were 348 fatalities. This is not to downplay the significance of those fatalities. No worker should be given the death sentence for the crime of working. This is to point out the change in the electrical culture that has been taking place over the last 20 years. The combination of OSHA enforcement and the implementation, and probably more significantly, a better understanding of NFPA 70E, Standard for Electrical Safety in the Workplace accounts for a good portion of the improvement.

Fig. 1: Trending of Electrical Fatalities. Courtesy Safety Foundation International.

HOW DID THE 70E COME TO BE? In the 1970’s OSHA decided that an industry-based consensus process would be the best method for developing such a highly-technical regulation regarding a hazardous substance. In 1976 OSHA called upon the National Fire Protection Association (NFPA) to develop an industry consensus standard for electrical safe work practices. In 1979 the first edition of NFPA 70E was published. In 1990 OSHA issued a new standard (1910.331.335) on electrical safety- related work practices for general industry. The intent was for this regulation to complement existing electrical installation standards and included requirements for work performed on or near exposed energized and deenergized parts of electric equipment, use of electrical protective equipment, and the safe use of electric equipment. The 70E provided much of the basis for the new OSHA regulation, modifying the language to fit the regulatory requirements. Since that time the NFPA 70E has been updated to reflect the latest thinking and findings on the subject of electrical safe work practices. Where the OSHA regulations must use broad regulatory, nonprescriptive language, NFPA 70E can be very prescriptive and by design is such a document. As an example, 29CFR1910.335 states, “Employees working in areas where there are potential electrical hazards shall be provided with, and shall use, electrical protective equipment that is appropriate for the specific parts of the body to be protected and for the work to be performed.” This broad language does not actually identify any specific PPE, only that the PPE chosen be appropriate. Contrast that statement with NFPA 70E, Article 130, which provides very specific recommendations for what PPE the worker is to use and also provides requirements for the construction, wear and ratings of arc-rated and shock PPE. As the industry matures and new information is evaluated, NFPA 70E will also change to keep pace. The OSHA regulations take much longer to change, which they should, and since OSHA regulations are federal law, they should not be subject to trends, opinions or outside influences. OSHA has representation on the NFPA 70E technical committee. Currently it is David M. Wallis, Director, OSHA Directorate of Standards and Guidance, Office of Engineering Safety; Washington, DC. The OSHA representatives provide insight to the technical committee on OSHA’s views about proposals and comments being considered by the committee, as well as advising the committee when their actions don’t exactly line up with OSHA’s mandates. One such example was eliminated in the 2012 edition. Previous editions of NFPA 70E had a lockout/ tagout procedure called the “Individual Qualified Employee Control Procedure”.

22 Essentially, this procedure allowed for minor servicing, repair or adjusting without the placement of locks and tags if the disconnecting means is adjacent to the conductor or circuit parts, is clearly visible to the qualified individual performing the work and the work does not extend beyond one shift. OSHA did not think much of the Individual Qualified Employee Control Procedure. That being said, OSHA has posted on their website a Letter of Interpretation, General Duty Clause (5)(A)(1) Citations on Multi- Employer Worksites; NFPA 70E Electrical Safety Requirements and Personal Protective Equipment, dated 07-25-2003, that states “Industry consensus standards, such as NFPA 70E, can be used by employers as guides to making the assessments and equipment selections required by the standard. Similarly, in OSHA enforcement actions, they can be used as evidence of whether the employer acted reasonably.” OSHA uses the 70E as a guide for justification of its citations, as NFPA 70E is the industry safe work practices standard.

MOVING FORWARD NFPA 70E is on a three-year cycle, although it was delayed for a year from the 2004 to the 2009 edition. This delay was caused by some serious disagreement among the committee members concerning the Hazard/Risk Category Tables, similar to some of the discussions concerning the tables in the 2015 cycle. The issues in the 2015 cycle were settled among the committee members without any intervention by the NFPA, but in the 2009 cycle extra committee meetings had to be conducted to resolve the issues. NFPA 70E is a consensus standard, which means that two-thirds of its committee members must approve the changes before it can be approved. The makeup of the technical committee has changed some over the years, and the committee has grown somewhat. The NFPA is careful to appoint a technical committee that represents the different interests and a comprehensive overview within industry and to not let one interest become dominant. And while there have been strong differences of opinion between the various committee members, it is clear that all members have a common goal and interest at heart–protecting the electrical worker. Protecting the electrical worker is the single most important factor that makes the 70E technical committee the best we have served on. No member or interest seeks to use the 70E for monetary advantage; if it is the right thing to do, we all can agree to it. And while sometimes how to do the right thing is not completely agreed upon, the committee voting on proposals and comments this cycle shows almost unanimous agreement among its members on virtually every issue. That is not to say the proposals or comments were accepted carte blanche...quite the opposite! The committee discussed and debated the merits and shortcomings of each and every proposal, modified the language when necessary to meet the consensus, and then voted as a group.

Safety Vol. 2 SUMMARY Workplace fatalities from all causes have been decreasing steadily over the years, and like it or not, this is due to the formation of OSHA and the rules they mandate for the workplace. Although there is more to be done, electrically- related fatalities have dropped considerably. StricterenforcementofOSHAregulationsdefinitely helps. NFPA 70E has certainly played a huge role in the reduction of fatalities and injuries and will continue to do so as more companies and workers understand and adopt it. OSHA and the 70E – not a bad combination. Ron Widup and Jim White are NETA’S representatives to NFPA Technical Committee 70E (Electrical Safety Requirements for Employee Workplaces). Both gentlemen are employees of Shermco Industries in Dallas, Texas a NETA Accredited Company. Ron Widup is President of Shermco and has been with the company since 1983. He is a Principal member of the Technical Committee on “Electrical Safety in the Workplace” (NFPA 70E) and a Principal member of the National Electrical Code (NFPA 70) Code Panel 11. He is also a member of the technical committee “Recommended Practice for Electrical Equipment Maintenance” (NFPA 70B), and a member of the NETA Board of Directors and Standards Review Council. Jim White is nationally recognized for technical skills and safety training in the electrical power systems industry. He is the Training Director for Shermco Industries, and has spent the last twenty years directly involved in technical skills and safety training for electrical power system technicians. Jim is a Principal member of NFPA 70B representing Shermco Industries, NETA’s alternate member of NFPA 70E, and a member of ASTM F18 Committee “Electrical ProtectiveEquipment for Workers”.

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SAFETY TIPS FOR QUALIFIED PERSONS NETA World, Spring 2014 Issue Jim White, Shermco Industries

According to the U.S. Bureau of Labor Statistics, 52 percent of electrical fatalities from 2003 through 2010 occured in the construction industry (Figure 1). As electrical contractors, we face many safety challenges that other trades may not. The chance of electrical shock, arc-flash burns, arc blast, projectiles, and high acoustic levels are why electrical safety needs to be at the top of your list and the top of your supervisor’s list.

exposure. We have added resistance, due to our shoes and socks and carpet, tile, or dry concrete, dropping the amount of current that would flow through us.

Fig. 2: Fatalities by Voltage Range. Fig. 1: Electrical Fatalities by Industry. Courtesy Electrical Safety Foundation International. Companies are taking electrical safety much more seriously than they used to. Here are a few misconceptions and tips to help you understand and appreciate the importance of electrical safety training.

MISCONCEPTION ONE: LOW VOLTAGE IS NOT AS DANGEROUS AS HIGH VOLTAGE I once had a student who said “Low voltage doesn’t worry me. High voltage does.” I asked him the reasoning behind that statement and he replied “If you get hit with low voltage, everyone can come by your coffin and say how natural you look. With high voltage, they have to close the coffin.” I hope he was kidding, but he was correct in his assessment that low voltage can be just as deadly as high voltage. H. Landis Floyd and Danny Liggett once presented the slide in Figure 2 as part of their presentation. This slide was only for industrial plants and did not account for utility workers. It clearly shows that, even though 277/480 V caused the most fatalities, the number of fatalities caused by 120/208/240 V is right behind it. When we are shocked, it is usually a hand-to-foot

The only difference between being shocked at a higher voltage and a lower voltage is how long it takes for the voltage to kill you. Low voltage just takes a bit longer, but as Figure 2 shows, it is every bit as lethal. Dr. Charles Dalziel conducted a study in 1960 where he subjected student volunteers to electrical shocks of varying strength. Dr. Dalziel demonstrated that a 75-mA electrical shock to an average-sized man could cause him to go into ventricular fibrillation in about five seconds. That sounds like a long time, unless you cannot extract yourself. Dr. Dalziel also showed that women have a greater risk of injury from electrical shock due to their lower body resistance. Lower body resistance equals more current flowing through the body. One example of this is the no-let-go threshold (where a person cannot release an electrically-energized conductor or circuit part). For the average woman, it would require a current of about 10 mA, while for the average man it would require a current of about 16 mA. 100 mA of current flowing through the body can cause fibrillation in three seconds, while a 2.5 A contact could cause fibrillation in about four milliseconds. Figure 3 shows a hand injury caused when a worker could not release a 110 V portable electric power tool due to muscular contractions and received a serious burn from the current flow.

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Safety Vol. 2 OSHA goes on to say “OSHA urges employers to be wary of relying solely on generic, ‘packaged’ training programs in meeting their training requirements. For example, training under HAZWOPER includes site-specific elements and should also, to some degree, be tailored to workers’ assigned duties.” OSHA applies this LOI to any hazardous job, including those for qualified persons.

Fig. 3: Hand Injury Caused by 110 V Tool. Courtesy OSHA eCat Website. Safety Tip 1: Do not be the guy that has to learn everything by experience. As my Dad would often say “Experience is what you get just after you need it.” Be smart; accept new safety practices; and change whatever bad habits you might have. Safety Tip 2: Be aware that a low-voltage electrical shock can be fatal.

MISCONSPECTION TWO: EXPERIENCE ALONE MAKES YOU A QUALIFIED PERSON “I’ve got 17 years on the job. Of course I’m qualified.” Certainly your years of experience are important, and the knowledge and skills you have developed are critical to being a qualified person, but technical skills are only half the equation. You have to meet OSHA’s definition of a qualified person: “Qualified person. One who has received training in and has demonstrated skills and knowledge in the construction and operation of electric equipment and installations and the hazards involved.” 29CFR1910.332 and .333 provide minimum required safety skills and knowledge, and NFPA 70E Section 110.2 gives more detail. There are three parts to being a qualified person; ● Training in the technical skills required ● Having knowledge of the construction and operation of electrical equipment (the technical side) and installations and the hazards involved (the safety side) ● Demonstrating those skills and knowledge (practical demonstrations) Companies may provide inadequate initial training for qualified persons by relying solely on video or computer-based training or one-day training sessions. These methods alone do not meet the requirement of OSHA/NFPA 70E requirements. OSHA, in a Letter of Interpretation (LOI) dated 11/22/94 says, “In OSHA’s view, self-paced, interactive computer-based training can serve as a valuable training tool in the context of an overall training program. However, use of computer-based training by itself would not be sufficient to meet the intent of OSHA’s training requirements….” Instructor-led training by a qualified instructor is required to meet this requirement.

Another excerpt from that same LOI states, “Equally important is the use of hands-on training and exercises to provide trainees with an opportunity to become familiar with equipment and safe practices in a non-hazardous setting.” Again, demonstration of skills is needed to become a qualified person. The minimum electrical safety training has to cover the following items: ● Demonstrating knowledge and skills in: ● Determining nominal voltage ● Determining what conductors or circuit parts are energized or not ● Minimum safe approach distances for shock (and arc flash) ● Use of special precautionary techniques ● Use of insulating materials and shielding ● Use of insulated hand tools Use of does not only mean picking up something and using it. Use of includes: ● Choosing the proper tool, clothing, or PPE ● Inspecting it to ensure it is safe to use ● Using the tool safely and wearing the protective clothing and PPE properly ● Storing tools and PPE safely so they do not get damaged ● Caring for tools and equipment, including any testing, calibration, and maintenance required NFPA 70E Article 110 provides more clarity on these requirements: ● Safety-related work practices and procedures necessary to protect workers while performing hazardous tasks ● Identify and understand the relationship between electrical hazards and possible injury ● Methods of release from contact with energized conductors or circuit parts ● First-aid and emergency procedures, such as CPR ● Decision-making process necessary to determine the degree and extent of the hazard, PPE, and job planning to perform the task safely ● Select the proper voltage detector and verify the absence of voltage, interpreting its indications, and the limitations of each specific device.

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Safety Vol. 2 Do you really think that can be done in a one-day session? Safety Tip 1: To be qualified you must have the technical skills and experience, as well as safety training and skills, necessary to perform the job. Safety Tip 2: Get training that meets OSHA and NFPA 70E minimum training requirements. If OSHA investigates an accident, the first thing they look at are the training records.

MISCONCEPTION THREE: YOUR JOB TITLE DETERMINES WHETHER OR NOT YOU MUST BE QUALIFIED “Your job title or job description does not have to include the word electrician before you are required to be a qualified person.” OSHA does not care what your job title is. OSHA looks at what you do on the job to determine whether or not you need to be qualified. Anyone who works on or near exposed, energized electrical circuits or conductor parts rated above 50 volts is required to be a qualified person. That could include instrumentation and control technicians, HVAC technicians, electrical engineers, or others who may not think of themselves as needing to meet that requirement. Safety Tip 1: The magic number is 50 volts, not 100 volts nor 120 volts. Safety Tip 2: If you have access to exposed energized conductors or circuit parts, you probably need to be qualified to 29CFR1910.332 and .333 and NFPA 70E Article 110.

MISCONCEPTION FOUR: PPE ELIMINATES RISK “I’m protected if I wear my PPE.” PPE does not eliminate the hazard, nor does it eliminate the risk. PPE can reduce the risk, but the hazard will remain the same whether PPE is used or not. OSHA does not accept that working with energized equipment with PPE is as safe as working with deenergized equipment. Safety Tip 1: Never trust your life to a mechanical device. My dad would say this when I would be under a car supported by a hydraulic jack. It’s good advice, especially when wearing PPE. Always wear your PPE, but work like you don’t have any on. Safety Tip 2: Turn it off! The only way to work safely is to work with deenergized equipment. Once the equipment or circuit is tested and found absent of voltage, no PPE is needed and the risk disappears. OSHA and NFPA 70E tell us to do just that. So the three most important rules of electrical safety are 1) turn it off, 2) turn it off and 3) turn it off.

MISCONCEPTION FIVE: ARC FLASH IS THE BIGGEST HAZARD FOR ELECTRICAL WORKERS “I hear so much about arc flash; it has to be the biggest hazard for electrical workers.” The Bureau of Labor Statistics (BLS) data reveals that shock is the greater hazard than arc flash by about a two-to-one margin. In some industries, it is higher.

Fig. 4: Shock vs Burn Injuries. From “Trends in Electrical Injury” James Cawley presented a paper titled, “Trends in Electrical Injury” at the 2006 IEEE/IAS Petroleum and Chemical Industry Committee (PCIC). Figure 4 is from that presentation. The Electrical Burns numbers include internal electrical burns caused by current flow through the body (contact burns), as well as arc-flash (non-contact) thermal burns. The injuries in Figure 4 also represent lost-time injuries, so the shock injuries were still very serious. Safety Tip: Arc-flash injuries often cause more serious injuries than electrical shock.

MISCONCEPTION SIX: ARC FLASH IS NOT A THREAT AT LOW VOLTAGES “I only work on low-voltage, low-energy lighting panels and the like, so arc flash isn’t a problem for me.” One rule-of-thumb for incident energy is that incident energy decreases by the inverse square of the distance. As you move away from an arc source, the heat created by an electrical arc flash decreases very quickly. The opposite is also true. Incident energy increases by the square of the distance as you move closer to an arc source. If I receive 1 cal/cm2 incident energy to my face and chest area (which is where incident energy is calculated), my hands, which are likely to be much closer to the source, will receive more. In some cases, my hands may only be one or two inches from an arc source. My hands could very easily be exposed to enough incident energy to cause severe second- and third-degree burns. Safety Tip 1: Don’t think that you cannot be seriously injured at lower voltages. There have been several reported incidents where workers received serious injuries to the hands and arms from safe voltages. Safety Tip 2: NFPA 70E recommends wearing leather gloves if hands will be exposed to an arc flash. Even lighting panels can cause severe burns to unprotected hands and fingers.

26 MISCONCEPTION SEVEN: EXPERIENCE WORKERS CAN SAFELY CUT CORNERS “I’ve done it this way for years and never had a problem.” We become accustomed to working on electrical equipment, and we feel comfortable. Our experience and field knowledge tell us how to evaluate those risks, and we tend to trust them. The problem is that one day, maybe years from now, something will not be as it seems. The insulation may be weakened. Someone may not have tightened the lug properly during the last maintenance cycle. The contractor who installed the equipment may have had a bad day. These are factors completely outside your control. Any one of these, not to mention dozens of other variables, can cause an accident. Safety Tip 1: Follow safety procedures and safe work practices, such as NFPA 70E not because you know something is going to happen, but because we do not know when it is going to happen. If not for yourself, think of the grief and loss your family would experience if you were seriously injured or killed. Think of the impact on your children. Safety Tip 2: Do not overestimate your skills. Being lucky is not the same as being skilled.

SUMMARY The vast majority of workers performing electrical tasks want to do what is right. But we get task-focused, losing sight of the fact that if there is an accident, not only could we (or someone close by) be injured or killed, but whatever we were working on will probably be damaged to the point that it must be replaced. Companies that are committed to working only on deenergized equipment have found that once the initial adjustment period is over, turning electrical equipment and circuits off does not have nearly the impact on operations that they had feared. Be smart: follow the OSHA regulations and NFPA 70E.

Safety Vol. 2 James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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Safety Vol. 2

ROTATING MACHINERY HAZARD AWARENESS NETA World, Summer 2014 Issue Scott Blizard and Paul Chamberlain, American Electrical Testing Co., Inc.

Performing a condition analysis or maintenance on rotating machinery is a hazardous task which requires an experienced individual capable of performing the duty and possessing an ability to identify potential hazards and mitigate risks. A number of tragic, inadvertent injuries can occur, such as crushed hands or arms, severed fingers, or blindness if extreme caution is not exercised when working with rotating machinery. The use of lockout /tagout, personal protective equipment (PPE), and other means of safeguarding will mitigate possible injuries. Condition analysis of rotating equipment may be performed by employing equipment designed to be used to access rotating equipment when operating, such as infrared camera, partial discharge detection equipment, and vibration analysis equipment. PPE should be appropriate and adequate for all tasks to be performed. Long sleeves, long hair, jewelry, and other loose articles are an invitation for disaster when one is around rotating machines. Make sure sleeves are tight, hair is pulled back and any other sources of entanglement are removed. Any machine part, function, or process which many cause injury must be safeguarded. When the operation of a machine or accidental contact with a machine can injure the operator or others in the vicinity, the hazards must be either controlled or eliminated. When performing a visual inspection of rotating machinery make sure that all guards are correctly installed according to the manufacturer’s instruction and that they comply with the Machinery and Machine Guarding OSHA Regulations 29 CFR 1910.212 - General Requirements for All Machines, and 29 CFR 1910.219 - Mechanical Power-Transmission Apparatus. Depending on the type of machinery being inspected, other OSHA regulations may apply. The following paragraphs identify and examine hazards and their means of safeguarding and mitigating the associated risks. As always, this article does not include every potential hazard of performing a task, but explores potentially hazardous situations. Additional hazards may exist, depending upon the type or condition of the equipment. Take all procedures seriously and verify that the instruction manuals used are specific to the equipment present. Check for and identify potential hazards prior to beginning every task by using a pre-job brief worksheet.

ELECTRICAL AND MECHANICAL HAZARDS Improper lockout/tagout is a major contributing factor to injuries caused by rotating machinery. Controlling the hazardous energy of the motor is essential, and there are many forms of energy that may be involved. Always refer to the appropriate OSHA regulation or required procedure, such as 29 CFR 1910.147 and .333, and the manufacturer’s instructions to determine the correct or required lockout/tagout procedures. The most obvious hazardous energy source that could cause injury is electrical. Electrically de-energize the rotating machinery from its primary energy source and ensure the equipment is disconnected from all sources of power, both ac and dc, if applicable. Once de-energized, verify that the equipment is at a zero energy state using the manufacturer’s approved method. Verify the accuracy of the detection or voltage measuring device against a known source, then check for zero energy on the de-energized equipment, and finally test the detection equipment against a known source again. This will verify that the detection meter used was functional during the check. Testing for voltage will require its own level of PPE depending upon the voltage and test procedure per NFPA 70E 2012 Table 130.7(C)(15)(a) - Hazard/Risk Category Classifications and Use of Rubber Insulating Gloves and Insulated and Insulating Hand Tools-Alternating Current Equipment (Formerly Table 130.7(C) (9) in the NFPA 2009). However, as previously stated, electrical energy is not the only energy that requires lockout/tagout. Rotating machinery may also contain a large amount of mechanical energy. This energy must be dissipated prior to servicing or serious injury could occur. Once the energy has been discharged or dissipated, it is also advisable to lockout/tagout the source of the stored energy, if feasible. Ensure that remote operating handles are tagged in a local or manual mode. This will prevent someone from inadvertently operating the machinery. Machinery operating mechanisms may also be pressurized. Ensure that the unit is depressurized and/or discharged and the source of the pressure is disabled. Ensure that any valves both upstream or downstream of the device are closed and lockout/tagout each valve. Once disabled this source must also be locked out and tagged out prior to performing maintenance.

28 CHEMICAL HAZARDS Chemicals can be a hazard, depending upon the type of rotating machinery and the process that the machine is associated with. Caution must be taken with gases, chemicals, and liquids. Many processes can produce gases that may be denser than air, so it displaces oxygen in lower lying areas. Ventilation must be used to avoid these gasses from being trapped. Some lubricants and cleaners may cause a respiratory and skin irritant if used in enclosed areas or on bare skin. Knowledge of the material, reading its label, and checking the Safety Data Sheet (SDS) is advised to identify any potential health effects from its use. Once again, use of proper PPE is necessary for using some cleaners and lubricant. For example, nitrile gloves, safety glasses, faceshield, and even in some cases respiratory protection may be needed.

OTHER PHYSICAL HAZARDS When performing the visual inspection, mechanical inspection, maintenance, or electrical tests on rotating machinery, gravity is an energy that may also need to be controlled. The size and weight of panel covers and inspection plates may make them difficult to handle. Should gravity be a potential energy source, through an inclined loaded conveyor belt for example, ensure that the energy is dissipated and any flywheels or other sources of energy or moving parts are chained or locked in position prior to performing lockout/ tagout and maintenance.

HUMAN ERROR HAZARDS Human error, simply put, is a person (or persons) making a mistake. To prevent an error, follow a procedure or checklist while performing the task. If one doesn’t exist, create one. Nomenclature should be verified, and reverified upon approaching a piece of equipment. Perform a self check and a peer check to ensure that the task is being performed on the correct component. Utilize markings such as flagging when working around similar looking pieces of equipment to identify the components that should not be touched. Flagging can take several forms depending upon the company’s or client’s policy and procedures. Do not forget to identify, mark, then lockout/tagout all associated equipment (i.e., associated cables and compartments). Flagging could be utilized to indicate a component that is not operating normally. Barricading off a safe work zone prevents other workers from inadvertently entering the work area. This will ensure that maintenance and testing is conducted in a controlled area; utilize a test stand in this area if applicable. Ensure that any control voltage required to operate the equipment during testing is within a secured area.

Safety Vol. 2 HAZARDS OF IMPROPER PERSONAL PROTECTIVE EQUIPMENT HAZARDS After verification that the rotating machinery is de-energized, the method of disconnecting the equipment may require a different form or class of PPE. Ensure that correct PPE is utilized for the class of disconnecting means. Refer to the NFPA 70E 2012 - Table 130.7(C)(15)(a) for the required PPE and hazard/risk class. It will indicate what level of protection that is required for the disconnecting means to be worked on. Identifying the correct level of PPE and gloves will aid in the mitigation of injury from a potential arc flash. However, this table provides information based upon known values of the short-circuit current available, the clearing time in cycles, and minimum working distance. If those factors are unknown, more information must be gathered prior to performing the work in order to ensure personnel safety. The following are examples of the PPE requirements per the NFPA 70E for some tasks involving one type of 600 volt class motor control centers (MCCs);

Tasks Performed on Energized Equipment

Hazard/Risk Category

Rubber Insulating Gloves

Insulated and Insulating Hand Tools

600 V class motor control centers (MCCs) Parameters: • Maximum of 65 kA short circuit current available; maximum of 0.03 sec (2 cycle) fault clearing time; minimum 18 in. working distance • Potential arc-flash boundary with exposed energized conductors or circuit parts using above parameters: 53 in. CB or fused switch or starter operation with enclosure doors closed

0

N

N

CB or fused switch or starter operation with enclosure doors open

1

N

N

Work on energized electrical conductors and circuit parts, including voltage testing

2

Y

Y

Table 1: NFPA 70E 2012 - Table 130.7(C)(15)(a) As can be seen in Table 1, depending on the task, various levels of protection may be required. This protection level includes some combination of the clothing indicated in Table 2, which is taken from NFPA 70E 2012 – Table 130.7(C)(16). Examination of Table 2 indicates that there are several notes. Always reference these notes when identifying PPE requirements. (See Table 3)

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Hazard / Risk Category Protective Clothing and PPE

AN: as needed (optional). AR: as required. SR: selection required. Notes:

0

Protective Clothing, Nonmelting or Untreated Natural Fiber (i.e., untreated cotton, wool, rayon, or silk, or blends of these materials) with a fabric weight of at Least 4.5 oz./yd2 • Shirt (long sleeve) • Pants (long) Protective Equipment • Safety glasses or safety goggles (SR) • Hearing protection (ear canal inserts) • Heavy duty leather gloves (AN) (See Note 1.)

1

Arc-Rated Clothing, Minimum Arc Rating of 4 cal/cm2 (See Note 3.) • Arc-rated long-sleeve shirt and pants or arc-rated coverall • Arc-rated face shield (see Note 2) or arc flash suit hood • Arc-rated jacket, parka, rainwear, or hard hat liner (AN) Protective Equipment • Hard hat • Safety glasses or safety goggles (SR) • Hearing protection (ear canal inserts) • Heavy duty leather gloves (See Note 1.) • Leather work shoes (AN)

(3) Arc rating is defined in Article 100 and can be either the arc thermal performance value (ATPV) or energy of break open threshold (EBT). ATPV is defined in ASTM F 1959, Standard Test Method for Determining the Arc Thermal Performance Value of Materials for Clothing, as the incident energy on a material, or a multilayer system of materials, that results in a 50 percent probability that sufficient heat transfer through the tested specimen is predicted to cause the onset of a second-degree skin burn injury based on the Stoll curve, in cal/cm2. EBT is defined in ASTM F 1959 as the incident energy on a material or material system that results in a 50 percent probability of breakopen. Arc rating is reported as either ATPV or EBT, whichever is the lower value.

Table 3

2

Arc-Rated Clothing, Minimum Arc Rating of 8 cal/cm2 (See Note 3.) • Arc-rated long-sleeve shirt and pants or arc-rated coverall • Arc-rated flash suit hood or arc-rated face shield (See Note 2) and arc-rated balaclava • Arc-rated jacket, parka, rainwear, or hard hat liner (AN) Protective Equipment • Hard hat • Safety glasses or safety goggles (SR) • Hearing protection (ear canal inserts) • Heavy duty leather gloves (See Note 1.) • Leather work shoes

Table 2: PPE Requirements

(1) If rubber insulating gloves with leather protectors are required by Table 130.7(C)(9), additional leather or arc-rated gloves are not required. The combination of rubber insulating gloves with leather protectors satisfies the arc flash protection requirement. (2) Face shields are to have wrap-around guarding to protect not only the face but also the forehead, ears, and neck, or, alternatively, an arc-rated arc flash suit hood is required to be worn.

IN CONCLUSION There are many things to be aware of when performing maintenance and testing on rotating machinery. ● Obtain all service bulletins, maintenance documents, arc-flash studies, and manuals prior to beginning work on that specific device ● Review all prints and one lines associated with the equipment ● Establish a safe work area, and barricade off the work area

INSTALLATION OF TEMPORARY PROTECTIVE GROUNDS

● Perform a pre-job brief with all employees on-site

Grounds are an excellent secondary means of protecting the worker from inadvertent energization. Refer to any applicable OSHA regulations such as 29 CFR 1910.269, NFPA 70E, and ASTM F855 for specific guidance on grounding locations and sizing of grounds required for the task. Grounds must always create an equipotential zone around the equipment and as close to the work as possible. Using correctly sized and applied grounds are an additional safeguard for employees should there be a form of electrical energy introduced into the system or equipment where the work is being performed. Induced voltage or back-feed are just two of the forms of energy that may be inadvertently introduced into a system that has been correctly locked out/tagged out.

● Disconnect the electrical feed and control circuit(s), verify mechanical interlocks are properly engaged and test equipment for absence of voltage before performing visual or mechanical inspections

● Wear proper PPE

● If applicable, verify that there is zero energy (test, check, test) and discharge all stored energy, including pressurized gasses and gravity ● If possible, lockout/tagout all energy sources ● Connect grounds where and/if applicable ● Identify, visually mark and/or flag the equipment being worked on Being aware of, and mitigating the hazards listed above can lead to a safer work environment while performing inspection, maintenance, and testing of rotating machinery.

30 Scott Blizard has been the Vice President and Chief Operating Officer of American Electrical Testing Co., Inc. since 2000. During his tenure, Scott acted as the Corporate Safety Officer for nine years. He has over 25 years of experience in the field as a Master Electrician, Journeyman, Wireman, and NETA Level IV Senior Technician. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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Safety Vol. 2

ELECTRICAL SAFETY— MYTHS AND RUMORS NETA World, Winter 2014 Issue David K. Kreger, Electrical Reliability Services

When it comes to electrical safety, much has changed over the past 10 years. The National Fire Protection Association has made a number of updates to NFPA 70E, including the most recent publication of NFPA 70E-2015. Occupational Safety and Health Administration (OSHA) also recently published its first-ever arc flash protection requirements for the electric power generation, transmission, and distribution industry, making significant changes to electrical safety requirements for utilities and industrial establishments. Unfortunately, many of the major misconceptions related to these standards have not changed. I’m still flabbergasted by comments and questions I hear from trainees and “qualified” electrical workers alike regarding requirements to maintain a safe work environment. Below is my attempt to debunk and demystify some of the most common myths about electrical safety standards, so that everyone can be on the same page when it comes to keeping electrical workers safe.

OSHA HAS A NEW REQUIREMENT TO PERFORM A HAZARD OR RISK ANALYSIS BEFORE BEGINNING EACH JOB. Technically speaking, this one is half true. In April 2014, OSHA did publish revisions to standard 1910.269 requiring high-voltage utilities and facilities to assess the workplace for potential flame or electric-arc hazards, to estimate the incident heat energy of those hazards, and to provide exposed workers with the appropriate personal protective (PPE) equipment. However, CFR 29, 1910.132(d)(1), which requires employers to assess the workplace for hazards and provide affected employees with PPE, has been in place for decades. What’s more, since OSHA’s inception in the early 1970s, the entire premise has been to ensure, as much as possible, a safe work environment for employees. Each employer has an obligation to determine what hazards an employee may face on the job. Once the hazard has been identified, the employer has further obligation to provide the appropriate training, PPE, or other work procedures that would allow the employee to perform the task safely. Several hazards are specific to the electrical industry—primarily shock and arc-flash burns. Qualified workers need to be aware of these hazards in order to be considered qualified. Therefore, the employer has always had an obligation to identify possible shock

hazards, identify possible flash-burn hazards, and provide the appropriate tools, PPE, or work procedures to mitigate these hazards. The new OSHA 1910.269 simply makes that official. I will add that, even though the appropriate tools and PPE are available, the supposedly qualified worker may not know what to do with them. For example, I once witnessed a 20-year veteran pull the insulating rubber gloves on over the leather gauntlets. When questioned, he responded, “I always wears them like that since the rubber part is the shock protection part and the leather inside keeps my hands from getting sticky.”

INSULATED GLOVES SHOULD NEVER BE WORN WHEN USING INSULATED LIVE-LINE TOOLS. IF THE INSULATION ON THE TOOL IS BAD, THE WORKER WOULD NEVER KNOW IT WHILE WEARING INSULATED GLOVES. This statement also was posed by a 20-year veteran. I had to think about that a moment. Hmm, would I want to find out the tool is bad by not wearing gloves? Those of you who have ever watched insulation break down when performing high-potential testing will testify that the breakdown happens quickly — faster than you could drop a bad switch stick!

WE WOULD LIKE TO ADOPT NFPA 70E AS OUR WORKING ELECTRICAL SAFETY POLICY, BUT IT IS ENTIRELY TOO CUMBERSOME. I have advocated NFPA 70E in its forms throughout the years and do admit, in some cases, the recommendations may be a bit cumbersome. However, realizing the intent of the publication should shed light on how to implement the appropriate policies. There is not, to my knowledge, a single safety document covering every possible scenario in the electrical industry, nor will there ever be, since ours is such a dynamic field. In the absence of specific rules from OSHA, the intent should still be to protect the workforce from hazards. Therefore, a site-specific or activity-specific policy would be appropriate, as long as it meets the intent of protecting the workforce. I keep a keen eye on the citations and violations of federal and many state OSHA organizations, and have yet to see a citation for not following an NFPA 70E recommendation verbatim. While OSHA continues to publish updates to its standards that do reflect specific NFPA 70E recommendations, such as the recent update to

32 OSHA 1910.269, NFPA 70E is not, in its entirety, an enforceable document. Yet. It is a guideline for developing a safe electrical work environment and has many practical applications the employer could use or modify, if necessary, to meet specific needs. If an employer were to adopt the new NFPA 70E-2015 in its entirety, I am certain it would be following all the OSHA rules.

IF I WERE ACTUALLY TO DEVELOP A RISK ASSESSMENT AND ENERGIZED ELECTRICAL WORK PERMIT BEFORE PERFORMING EVERY TASK, AS RECOMMENDED IN NFPA 70E, I WOULD SPEND ALL DAY DOING RISK ASSESSMENTS AND NEVER GET THE WORK DONE. If you are not already doing some form of risk assessment before performing electrical work, I would say you should find a different occupation. The recommendation to perform a risk assessment and develop a written energized electrical work permit plan for hazard mitigation applies to those tasks that are not routine in nature (not routine being less frequently than annually). The system will not be locked and tagged, and the system will be energized or possibly energized. If the task is performed frequently, an original risk assessment with successful mitigation techniques should already be in place in one form or another. Thus, another assessment is not required. To give an example, a qualified worker should already know the hazards involved in taking current measurements in a motor control center. Would the hazards change from one bucket to another? I would say no. Therefore, the same techniques found to be successful in one application of shock and flash protection would be successful in other similar applications. There is no reason to perform multiple (written) hazard assessments and mitigation procedures for basically the same task. Further, the newer versions of NFPA 70E limit areas where electrical work permits are required to those areas within the limited-approach boundary or arc-flash boundary. In addition, NFPA 70E, 2015, Article 130.2(B)(3) Exemptions to Work Permit says that an energized work permit is not required for work performed on or near live parts when qualified persons are performing tasks such as testing, troubleshooting, or voltage measuring; thermography and visual inspection up to the Restricted Approach Boundary; access/egress with no electrical work up to the Restricted Approach Boundary ; and general housekeeping up to the Restricted Approach Boundary , as long as appropriate safe work practices and PPE are provided and used in accordance with Chapter 1.

OSHA HAS A NEW REQUIREMENT TO PERFORM AN ARC-FLASH HAZARD ASSESSMENT AND TO MARK THE EQUIPMENT. Yes and no. The new OSHA 1910.269 requirements mandate that high-voltage utilities and facilities need to estimate the

Safety Vol. 2 incident heat energy of arc hazards and provide exposed workers with the appropriate protective clothing and equipment. However, for many years there has been an existing requirement to perform a hazard analysis for any hazard an employee may face on the job (see 1910.132(d)(1) in #1 above). The new requirement provides guidance on tools and methods that can be used to estimate available heat energy. The 2014 National Electrical Code (NEC) Article 110.16 requires the marking of flash hazards on electrical equipment. This is not an OSHA mandate, it is an NEC requirement.

ANYTHING THAT’S ELECTRICAL IN THE WORKPLACE NEEDS TO BE LABELED. Since the 2002 edition of the NEC introduced the requirement for marking flash hazards on electrical equipment in the field, the issue has been a hot and somewhat misunderstood topic. Adding to the confusion was the fact that NEC and NFPA 70E did not specify which electrical equipment needed to be labeled, but only that electrical equipment should be marked wherever the possibility of energized work exists. However, the intent of Article 110.16 has always been to arm the qualified worker with enough information to make an intelligent choice when selecting the appropriate PPE. The fine print note associated with NEC Article 110.16 says to refer to NFPA 70E for additional guidance. New updates to NFPA 70E-2015 and NEC shed light on the topic by spelling out the types of equipment that need to be labeled (i.e., switchboards, switchgear, panelboards, industrial control panels, meter socket enclosures, and motor control panels). Today’s requirements also make it clear that only electrical equipment that is likely to require examination, adjustment, servicing, or maintenance while energized needs to be field marked. Additionally, NFPA 70E section 130.5(B) includes an exception that permits continued use of labels applied prior to September 30, 2011, as long as those labels contain the available incident energy or required level of PPE. New language in 130.5 also says that labels need to be updated if the arc-flash hazard risk assessment shows that the labels are inaccurate and that the owner of the electrical equipment is responsible for documentation, installation, and maintenance of the field-marked labels.

IF THERE WERE A SIGN ON A PIECE OF EQUIPMENT THAT SAID, “DANGER — VOLTAGE,” WOULD THAT BE SUFFICIENT INFORMATION FOR A QUALIFIED WORKER TO SELECT THE APPROPRIATE INSULATED GLOVES OR TOOLS? I think not. The voltage level is what quantifies the hazard so the appropriate PPE and tools can be selected. The intent of the arc-flash protection program should be the same. Simply

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Safety Vol. 2 putting a sign on a piece of equipment that says, “DANGER — FLASH HAZARD” would not be sufficient information for a qualified worker to select the appropriate fire-retardant materials or flash-protection equipment. One of the requirements to be considered qualified to perform electrical work is the ability to identify exposed energized equipment and to identify the nominal voltage of that equipment. The purpose of this training requirement is twofold: provide the ability to determine when a shock hazard exists, and the ability to determine level of insulating tools or gloves required. There should also be a training requirement associated with arc-flash protection. Never have I seen so many blank stares from supposedly qualified electrical workers as when I show an example of an arc-flash warning sign indicating magnitude of hazard at a working distance. To help with this problem, changes to NFPA 70E-2015 make it clear what information needs to be included on field labels. Specifically, it states that the label should include: ● Nominal system voltage ● Arc flash boundary ● At least one of the following: ○ Incident energy and working distance ○ PPE category from NFPA 70E table ○ Minimum PPE arc rating ○ Site-specific level of PPE

THAT SIGN SAYS THERE ARE 11.4 CALORIES AT 18 INCHES. I ATE 10 TIMES THAT MANY CALORIES FOR BREAKFAST THIS MORNING! This is undoubtedly the most significant training challenge I continue to face. How do you take a group of electricians or instrument technicians from volts, amperes, and time to calories per square centimeter (or, worse yet, Joules per square centimeter) at a given working distance? Don’t blame it on the aptitude of the audience either. I once received much the same response from the audience at an IEEE meeting. A thorough explanation is needed of the transition from watt-seconds (which most understand) through Joules (which some understand) to calories applied to square centimeters of bare skin (which no one understands). Such an explanation usually results in positive head nods or the I get it! looks. Of course, showing the gory electrical burn victim movies helps to drive home the point. I would hope that those engineers performing incident energy studies will keep in mind the target audience for the results. Providing a report in Joules per square centimeter as well as recommendations for arc-rated PPE with ratings of calories per square centimeter will not help those that are already confused. Help them out — provide some training along with the results of the incident energy study correlating study findings with mini-

mum arc thermal protection values and maybe try to explain heat attenuation factor percentages too.

THE NFPA 70E ARC-FLASH PPE TABLES ARE CONFUSING AND MAKE IT DIFFICULT TO KNOW WHICH ARC-RATED CLOTHING TO CHOOSE. In the past, the NFPA 70E table method for choosing arc-rated clothing was somewhat cumbersome. In the 2015 version of the standards, new task-based tables have been added for determining when arc-flash PPE is necessary for AC and DC systems. For each task, the table indicates if there is an arc-flash hazard (yes or no). If yes, further engineering analysis must be performed to determine what level of arc flash protection will be required.

I HAVE LONGER ARMS THAN YOU. DOES THAT MEAN I CAN WEAR DIFFERENT FLAME RETARDANT CLOTHES? No, because I sweat more than you do… David K. Kreger has nearly three decades of experience with high, medium-, and low-voltage power generation, transmission, and distribution systems. His formal education includes a BS in physics from New York State University and an AA from the University of Maryland. He gained extensive experience as a field engineer through testing, troubleshooting, commissioning, and repairing power systems as well as through high-voltage work as a utility lineman. He is a licensed power engineer, NETA Level III Certified Technician,member of the NFPA (electrical section), and master instructor for the training group of Emerson’s Electrical Reliability Services.

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DETERMINING MAINTENANCE INTERVALS FOR SAFE OPERATION OF CIRCUIT BREAKERS PowerTest 2014 James R. White, Shermco Industries, Inc.

ABSTRACT NFPA 70E states in several sections in Articles 130, 200 and 205 that maintenance of overcurrent protective devices (OCPD) is critical to ensure a safe work environment. This paper discusses factors that may affect the operation of circuit breakers and other types of OCPDs and may cause misoperation when these devices are needed the most.

“(3) For the purpose of Chapter 2, maintenance shall be defined as preserving or restoring the condition of electrical equipment and installations, or parts of either, for the safety of employees who work where exposed to electrical hazards…...” Maintenance is defined in this section and notes that maintenance is performed for the safety of employees who work where exposed to electrical hazards. Electrical hazards are present anytime electrical equipment is energized.

NFPA 70E REQUIREMENTS

205.3 General Maintenance Requirements.

The 2012 edition of NFPA 70E makes some strong statements about how the condition of maintenance can affect the operation of OCPDs, and how that will cause the incident energy from an arc flash to increase. A summary of those sections is below:

“Electrical equipment shall be maintained in accordance with manufacturers’ instructions or industry consensus standards to reduce the risk of failure and the subsequent exposure of employees to electrical hazards.” This section very clearly states that failing to maintain electrical equipment and devices exposes employees to electrical hazards.

(1)

130.5 Arc Flash Hazard Analysis. “The arc flash hazard analysis shall take into consideration the design of the overcurrent protective device and its opening time, including its condition of maintenance.” Informational Note No. 1: “Improper or inadequate maintenance can result in increased opening time of the overcurrent protective device, thus increasing the incident energy.” Informational Note No. 4: “For additional direction for performing maintenance on overcurrent protective devices, see Chapter 2, Safety-Related Maintenance Requirements.” The chapter no one reads. Section 130.5 reflects the level of concern the 70E Committee has concerning how maintenance affects the arc flash study. IN No. 1 is very clear in stating the Technical Committee’s concern.

200.1 Scope. Informational Note: “Refer to NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, and ANSI/NETA MTS-2007, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems, for guidance on maintenance frequency, methods, and tests.” The 70E Technical Committee recognizes that the manufacturer’s instructions may not always be available, especially for obsolete equipment. The two primary industry standards are provided to give additional guidance. The 2015 edition of NFPA 70E will add IEEE Recommended Practice for the Maintenance of Industrial and Commercial Power Systems to the list. Figure 1 shows both the ANSI/NETA and NFPA documents.

Fig. 1: ANSI/NETA MTS-2011 and NFPA 70B – 2013

205.4 Overcurrent Protective Devices. “Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards. Maintenance, tests, and inspections shall be documented.” OCPDs are singled out in this section as they have a disproportionate impact on worker safety. Note that where OCPDs are concerned, the maintenance, tests and inspections must be documented. OSHA, where are you on this? In addition, 130.7(C)(15) states, “The assumed maximum short-circuit current capacities and maximum fault clearing times for various tasks are listed in Table 130.7(C)(15)(a). For tasks not listed, or for power systems with greater than the assumed max-

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Safety Vol. 2 imum short-circuit current capacity or with longer than the assumed maximum fault clearing times, an incident energy analysis shall be required in accordance with 130.5.” If OCPD’s aren’t being maintained, Table 130.7(C)(15)(a) won’t provide the level of protection needed and that expensive arc flash study won’t be much better. During the last three cycles of NFPA 70E, there have been prolonged discussions about how the condition of maintenance of OCPDs can be determined. This is not usually as much an issue for employees of a facility, but when contractors come in to operate or maintain electrical equipment, they may not have immediate access to the needed information. The testing and maintenance records need to be part of the pre-job planning

of maintenance is so prominent of NFPA 70E. Without proper maintenance, OCPDs won’t function in accordance with their manufacturer’s specifications, PPE selection becomes problematic and the electrical power system is unsafe.

2015 EDITION NFPA 70E During the 2015 cycle of NFPA 70E(2), due to be released in October of 2014, the NFPA 70E Technical Committee will add the following (note that section numbers may not be accurate):

SR4 – 110.1(B) “Maintenance. The electrical safety program shall include elements that consider condition of maintenance of electrical equipment and systems.” For the first time, condition of maintenance is required to be part of the electrical safety program (ESP).

SR5 – 110.1(A) “General. Informational Note No. 1: Safety-related work practices such as verification of proper maintenance and installation, alerting techniques, auditing requirements, and training requirements provided in this standard are administrative controls and part of an overall electrical safety program.” This section clarifies that condition of maintenance is considered to be a safety-related work practice. SR4 and SR5 integrate condition of maintenance into the ESP and puts emphasis on its importance.

SR32 – 130.5 “Arc Flash Risk Assessment. (3) Take into consideration the design of the overcurrent protective device and its opening time, including its condition of maintenance.” “Informational Note No. 1: Improper or inadequate maintenance can result in increased opening time of the overcurrent protective device, thus increasing the incident energy. Where equipment is not properly installed or maintained, PPE selection based on incident energy analysis or the PPE category method may not provide adequate protection from arc flash hazards.” Section 130.5 is rewritten so that the requirements for an arc flash risk assessment are in a list format, and rewords the requirement slightly from the 2012 edition. IN No.1 is expanded from the 2012 edition to alert the user that if electrical equipment is not properly installed or maintained, the methods for choosing arc flash protective equipment may not be accurate, leaving the worker underprotected. It’s no accident or quirk of fate that condition

Fig. 2: Partial PPE Selection Table 130.7(C)(15)(A)(a) From NFPA 70E, Standard for Electrical Safety in Employee Workplaces Second Revision Draft “*The phrase “properly installed”, as used in this table, means that the equipment is installed in accordance with applicable industry codes and standards and the manufacturer’s recommendations. The phrase “properly maintained”, as used in this table, means that the equipment has been maintained in accordance with the manufacturer’s recommendations and applicable industry codes and standards. The phrase “evidence of impending failure”, as used in this table, means that there is evidence of arcing, overheating, loose or bound equipment parts, visible damage, deterioration, or other damage.” For the first time in NFPA 70E, condition of maintenance is a part of Table 130.7(C)(15)(A)(a) and a footnote is added to clarify what is meant by the phrase “properly maintained”. Condition of maintenance is such an integral part of the electrical safety process that it cannot be separated from it. Figure 2 shows the proposed 2015 version of the PPE selection table, 130.7(C)(15)(A)(a).

205.3 “General Maintenance Requirements. Informational Note: Common industry practice is to apply test or calibration decals to equipment to indicate the test or calibration date and overall condition of equipment that has been tested and maintained in the field. These decals provide the employee immediate indication of last maintenance date and if the tested device or system was found acceptable on the date of test. This local information can assist the employee in the assessment of overall electrical equipment maintenance status.” The NFPA 70E Technical Committee grappled with how condition of maintenance could be verified and agreed that it would not be an easy thing to do. Maintenance records and test results could be reviewed prior to the start of work, if they are available. If the equipment was maintained, those records should be available.

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The other method used by some service companies, such as many NETA-member companies, is to place calibration and test labels on their equipment, as shown in Figure 4. NFPA 70B(3) “Recommended Practice for Electrical Equipment Maintenance” 2013 edition added section 11.27 ‘Test or Calibration Decal System. It states, “11.27.1 General. After equipment testing, device testing, or calibration, a decal on equipment, in conjunction with test records, can communicate the condition of electrical equipment to maintenance and service personnel. This can be important for assessing the hazard identification and risk assessment for electrical safety procedures as well as the condition of electrical equipment.” Such labels are shown in Figure 3. These labels are supposed to be color coded as red, yellow or white.

The Reliability Subcommittee of the IEEE Industrial and Commercial Power Systems Committee, in IEEE Standard 493(4) “Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems” (the Gold Book) conducted a survey that included 1,469 failures of electrical equipment. In the survey, respondents were asked to describe their opinion of the maintenance quality in their plant. Inadequate maintenance was blamed for 16.4% of the failures of electrical equipment overall. Table 5-2 (Figure 5) in Std. 493 shows the percentage of failures of electrical equipment vs. the time they had been in service without being maintained. Note that circuit breaker failures increased substantially after they had been in service for more than 24 months without being serviced.

Fig.3: Test or Calibration Decal System From NFPA 70B-2013, Recommended Practice for Electrical Equipment Maintenance The red label indicates the equipment has a major defect and should not be placed into service. The yellow label indicates a minor issue that does not affect operation or safety and the white label indicates equipment that is fully serviceable. Since NFPA 70B is printed in black-and-white, the colors are described in the text, but not shown in the figure. Figure 4 shows how the labels would be color-coded in the field.

Fig. 4: Test and Calibration Decal as Specified by NFPA 70B – 2013 Edition

STUDIES THAT INDICATE THE NEED FOR MAINTENANCE Numerous studies have shown that if circuit breakers are left in service without maintenance, their chances of operating correctly become less and less each year. Gary Donner with Tony Demaria Electric in Wilmington, CA., who is a friend and former Shell Oil Company employee, related to me that years ago, Shell had performed a study that indicated when circuit breakers sat undisturbed for years, they would not meet manufacturer’s specifications. After three to five years of service approximately 30% of the circuit breakers malfunctioned, after seven to ten years approximately 50% of the circuit breakers malfunctioned and after 17 to 20 years the number was in the high ninety percentile. Gary says that study was lost during some work site transitions and is no longer available. This does not negate the importance of the study, as it correlates to the next two studies very well.

Fig. 5: From IEEE Standard 493, Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems In the largest survey of its kind to date, NETA-member (interNational Electrical Testing Association) companies were asked to participate in a survey on the causes of circuit breaker failures. The survey data and conclusions were provided in a paper presented at the 2008 NETA PowerTest Conference and the 2011 IEEE PCIC Conference(5) . The survey contained 340,000 results. The NETA survey showed that 22% of the circuit breakers had an issue with the overcurrent protective device that would have affected its operation. 10.5% of the circuit breakers did not function at all! Of the circuit breakers that had performance issues, 42.8% had mechanical issues and over half of those were related to lubrication. All three surveys point in the same direction and support each other. How often should circuit breakers be maintained and what should be done to them? There are two sources for answers; ANSI/NETA MTS-2011(6), Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems and NFPA 70B-2013, Recommended Practice for Electrical Equipment Maintenance. Both make recommendations as to frequency and what maintenance is required of electrical devices, but ANSI/NETA MTS also provides specifics on what the results should be.

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Safety Vol. 2 Figures 6 and 7 show a portion of the ANSI/NETA MTS Maintenance Frequency Matrix in Annex B. By choosing the criticality and condition, a multiplier is derived from the table. As an example, equipment that has a low criticality and is in good condition would have a multiplier of 2.0. Using molded-case circuit breakers as an example (Figure 7) each of the recommended intervals in Figure 7 is multiplied by 2x. Be aware that there are other criteria that should be used to determine maintenance frequency, such as environment, loading, how the circuit breaker is being used, number of operations, etc.

Fig. 6: Frequency of Maintenance Matrix, Annex B ANSI/NETA MTS-2011

Fig. 7: Section 7.6.1.1 from ANSI/NETA MTS-2011

FACTORS THAT CAN AFFECT THE OPERATION OF OCPDS Circuit Breakers. There are several factors that have a detrimental effect on all types of circuit breakers. One of the most damaging factors is lack of lubrication. Since a circuit breaker, regardless of type or voltage rating, is primarily a mechanical device, it needs lubrication in pivots, latches and rollers. 80% of the circuit breakers that are serviced by Shermco’s Circuit Breaker Shops show signs of inadequate lubrication. This is caused by the heat created from electrical current flowing through the circuit breaker. Loading is another important factor to be considered when evaluating a circuit breaker’s condition of maintenance. Heavily-loaded circuit breakers produce more heating than lightly-loaded circuit breakers and require maintenance more frequently. Other factors that generally affect a circuit breaker’s condition of maintenance are: ● Specific manufacturer and model. Not all circuit breakers are created equal. Anyone who has serviced circuit breakers knows there are some that are excellent, and some that are quite a bit less than excellent. ● Environment. Circuit breakers that are in a climate-controlled environment fare much better than those outdoors. Humidity, heat, cold and dirt and other contaminants can seriously degrade a circuit breaker’s operation. Circuit breakers used in water, wastewater treatment or pulp and paper facilities may also be subjected to chlorine, H2S (hydrogen sulfide) or other corrosive or reactive atmospheres. ● Age/Construction. Organic insulating materials, such as epoxy-covered paper, ceramic, asbestos and phenolic plastics can absorb moisture, begin to weaken dielectrically and be subject to carbon tracking. Many people don’t realize that fiberglass redboard, once cut, will absorb moisture and after 5 to 7 years can begin to breakdown and track. Vacuum circuit breakers that have been in service for 20+ years are beginning to fail due to leakage into the bottle. These circuit breakers had an expected service life of 20 years and many of those breakers have exceeded that. There are now field tests that can determine the remaining life that can be expected from individual vacuum bottles.

Fig. 8: Table L.1, Maintenance Intervals, Partial From NFPA 70B-2013, Recommended Practice for Electrical Equipment Maintenance Figure 8 is an excerpt from NFPA 70B, Annex L, Maintenance Intervals. Generally, circuit breakers are recommended to have service performed annually and tested every three years. The actual service conditions will affect the frequency of maintenance and the MTS and 70B recommendations are only guidelines.

Molded-case circuit breakers can seize due to corrosion and wear to the trip latch. The NRC conducted a study at Davis-Besse Nuclear Power Plant (7) and found that 80% of the molded-case circuit breakers that had been in service for 5 years would not function according to the manufacturer’s specifications. My personal experience has been that, after 3 to 5 years, approximately 50% of molded-case circuit breakers would not meet manufacturer’s specifications. The NRC recommended operation of the Pushto-Trip or Twist-to-Trip mechanism (usually marked in red) every year or, if no such mechanism is available, toggling the breaker off and on several times twice a year. ●

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● Duty cycle. It’s a little like Goldilocks; too much is not good, and neither is too little. Circuit breakers must be exercised to keep the lubricants mixed, but constant operation will take its toll. Circuit breakers used as across-the-line starters are one example of severe duty-cycles that can cause rapid deterioration. ● Loose connections. Even properly-installed electrical equipment can suffer from loose connections. All AC electrical equipment is subjected to the vibration caused by the current alternating. This vibration, plus the expansion and contraction of the metal caused by load changes will loosen connections over time. This is one reason why all electrical equipment and systems require routine maintenance. ● Experience and training of the personnel operating it. Unqualified or careless workers account for a fair percentage of damaged and nonfunctional electrical equipment in industry. OSHA and NFPA 70E both state that a qualified worker must be trained in and demonstrate their ability to both operate and recognize the hazards associated with that piece of equipment. Each month (or more often) I hear of an electrical accident caused by a worker who did not understand the limitations of his/her equipment. Stupidity can also be lumped into experience and training. As the old saying goes, “You can’t fix stupid”, no amount of training will save some people from themselves. Some people seem to try to live stupid to its fullest. Figure 9 is an actual photo taken during a service call by Rick Eynon. In order to prevent this LVPCB from opening, a board was jammed into the breaker so the contacts could not open, no matter what. Production managers often reward this type of dangerous behavior, without understanding the consequences of their decisions.

point where arcing takes place between the fuse and the clips. Medium-voltage fuses can absorb moisture, causing misoperation. Probably the biggest offender is workers replacing fuses with the incorrect type or size. Here’s a hint – if a fuse blows it’s not the fuse at fault. Figure 10 shows a 100A replaceable-element fuse with a 400A element installed. This type of misapplication is a hazard to workers and will cause unplanned outages.

Figure 10: Why I Don’t Like Replaceable-Element Fuses

Protective Relays. Electromechanical relays can be affected by several factors including age and wear on bearings, corrosion, contaminants, vibration (damaging the bearings), covers being left off, glass being broken, defective seals, etc. Solid-state and digital protective relays are not as affected by those factors, but can have loose connections caused by vibration, damage to their power supplies from voltage spikes or lightning, sudden failure of components and misprogramming by inept technicians. Since protective relays are often used in conjunction with auxiliary relays, interconnecting wire and instrument transformer issues can cause misoperation, as well.

SUMMARY AND CONCLUSIONS It’s a harsh world for the devices and equipment we depend on to keep us safe and our power system functioning reliably. Regular maintenance and testing of electrical equipment and systems ensures they will function safely and will reduce unplanned outages.

REFERENCES 1. NFPA 70E – 2012, Standard for Electrical Safety in the Workplace Fig: 9: How to Prevent Nuisance Tripping Photo Courtesy Rick Eynon

Fuses. Many people think fuses are maintenance free. There’s no such thing as free in this life. Dirt and contaminants can cause tracking on the fuse surface. Moisture can degrade fuse components. Vibration can cause loose connections, just as in all other types of electrical equipment. Load cycling can loosen fuse clips to the

2. NFPA 70E – 2015, Second Revision ballot 3. NFPA 70B – 2013, Recommended Practice for Electrical Equipment Maintenance 4. IEEE Standard 493, Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems 5. Widup, R. and Heide, K., NETA Maintenance Testing Research On Electrical Power System Equipment Performance, PCIC-2011-40

Safety Vol. 2 6. ANSI/NETA MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems 7. NUREG/CR-5762, Comprehensive Aging Assessment of Circuit Breakers and Relays, Wylie Laboratories James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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REDUCE RISK WITH PESDS MAKING NFPA 70E COMPLIANCE SAFER PowerTest 2014 Philip B. Allen, Grace Engineered Products, Inc.

ABSTRACT Electrical safety does not mean zero risk, but rather it is a process of decreasing electrical risks and their probability of occurrence to acceptable level. Since the 2000 edition of the NFPA 70E was published, it has fundamentally transformed practices regarding troubleshooting and electrical/mechanical lock-out/tag-out procedures by focusing on ways to lessen electrical risks. Yet, many end-users are choosing to exceed and go beyond the minimum safety standard prescribed in NFPA 70E and they are opting to install Permanent Electrical Safety Devices (PESDs) to curtail risk even further. The byproduct is an electrically safer work condition. An electrically safer work condition is achieved by an automobile manufacturer and Cintas Corporation when they utilize Permanent Electrical Safety Devices (PESDs), which reduce risks and increase the likelihood that zero voltage exists. Permanent Electrical Safety Devices (PESDs) are an example of safety by design. They incorporate electrical safety functionality directly into electrical equipment. While PESDs cannot be used as the sole device to check for the absence of voltage, when partnered with a voltmeter, they create an electrically safer work condition. This allows for workers’ exposure to shock and arc flash hazards to be further diminished during LOTO procedures because workers have no susceptibility to voltage.

bels on a panel fed with three-phase 480VAC and 120V separate control. Proper implementation and selection of PESDs greatly increases the prospect that a worker performing LOTO will have no exposure to voltage, and in some cases, requires no additional personal protection equipment (PPE) beyond the normal 8 cal/ cm2 daily wear. A PESD mounted on the outside of the panel provides workers with the ability to see and check all possible voltage sources 1. Depending on which PESD is installed on the panel, the combination of visual, audible and physical action required by the worker creates an electrically safer work condition.

Understanding the unique properties, functionality and installation requirements of each kind of PESD is essential to empowering users in the process of selecting the most suitable device for their specific application.

Warning: Before working on an electrical conductor, verify zero electrical energy with proper voltage testing instrument and the proper procedure as per NFPA 70E 120.1 (5), 120.2 (F)(2)(f) (1-6), OSHA 1910.333(b)(2)(iv)(B). Index Terms: Permanent Electrical Safety Devices, PESD, NFPA-70E, Voltage detection, Safety Device, Voltage Portal, Test Point Assembly

INTRODUCTION Permanent Electrical Safety Devices (PESDs) are a family of electrical components hardwired to a source of voltages and installed into electrical systems. They enable workers to verify the voltage status of equipment without exposure to the hazard. PESDs reduce the likelihood of arc flash and shock hazard because they diminish voltage exposure, provide voltage labeling on all sources and allow for 24/7/365 visual and/or audible indication of voltage. Figure 1 shows an example of the voltage source la-

Fig. 1: Voltage Source Labels

TYPES OF PESDS Creating an electrically safer work condition can be achieved with either a single-or three-phase source, which can be extended to the outside of an electrical enclosure through an encapsulated non-conductive housing called a voltage portal. The voltage portal is designed for use with a non-contact voltage detector (NCVD) to sense voltages from 50-500/90-1000VAC when placed into an energized voltage portal. The NCVD is a battery operated voltage

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Safety Vol. 2 detector pen that senses AC (but not DC) voltage without actually touching an energized conductor. Figure 2 outlines the fundamental concept of a voltage portal and the associated NCVD.

● Designed and built solely to indicate the voltage status of a three-phase system. ● Always connected to the source and testing between L1-L2L3-GRD as per NFPA 70E 120.1(5) ● Powered from the line voltage (no batteries or maintenance) ● Wide operating AC/DC voltage range (20/40-750VAC/301000VDC) ● Senses stored energy as per NFPA 120.1(6) ● Meets 50-volt threshold as per NFPA 70E 110.6 (D)(1)(b), 110.7(E)5

Fig. 2: Cut away of three phase voltage portal NCVDs rely on a capacitive coupling to ground, which makes the NCVD less versitile than a phase-phase/phase-ground voltmeter test. However, with voltage portals installed and the panel energized, workers can test the voltage portal with the NCVD to ensure it works. This means a capacitive ground connection exists and will always exist because panels do not move and workers stand in the same place when they test. (Figure 3)2.

● Cat IV surge immunity and UL Certified to UL/ANSI 61010-1 as per NFPA 70E 120.1(5) Informational Note. Additionally, a zero-energy optical cable voltage indicator as shown in Figure 4 provides the same functionality as per above, but utilizes a non-conductive optical cable for transmitting the LED light. With no voltage to the outside of the electrical enclosure, this system meets the ANSI C37.20.1(7.1.3.7) switchgear specification limiting voltage to the outside of the enclosure to less than 254VAC.

Fig. 4: Zero Energy Voltage Indicator System

Fig. 3: Voltage portal to NCVD to GRD functionality Alternatively, a light emitting diode (LED) type of voltage indicator can be permanently hardwired to the phases and ground. This external device will illuminate when a voltage greater than 20-40VAC/30VDC is applied or when a voltage deferential exists between two lone inputs creating an electrically safer work condition. ● The risk reduction characteristics of a three-phase/four-wire voltage indicator include:

Figure 5 shows a three-phase test point device with built-in impedance on each phase, which provides another method of checking voltage with a standard voltmeter without exposing workers to the risk of an arc flash or electrocution. When a LOTO procedure includes both a three-phase test point device and a voltage indicator mounted into panel-mount housing, it increases the likelihood that the workers’ voltmeter test will yield only a zero voltage reading. The built-in impedance of 56K ohms on L1, L2, and L3 affects voltage readings by approximately 10% when using a typical digital voltmeter, however this is not applicable at the zero voltage range. Yet, the benefit of this approach is it limits the current outside of the enclosure to approximately 10mA. This reduces the propensity of a worker inadvertently causing a short circuit while performing a voltmeter test, which could result in an arc flash. The 10mA current threshold is below 17-99mA range that could cause death 3. In addition, depending on the installation and local codes, limiting the current to 10mA may eliminate the need for short circuit protection of a test point device.

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Fig. 5: Test Point with Energy Limiting Impedance A test point assembly with no impedance is a variation on this same concept with its own unique advantages and disadvantages. Without built-in impedance, the energy to the outside of the panel is limited only by the fuses and lead-wires to the test points. On the other hand, these test points provide a more direct connection to the source, which is an advantage. This is yet another example of creating an electrically safer work condition.

PESDS INSTALLATION REDUCES RISKS Because PESDs hardwire to the primary source disconnect and install on the exterior of the electrical equipment, they require an environmental type rating identical to the enclosure on which they are affixed and a minimum 600-volt component rating. When PESDs are installed on the enclosure flange in close proximity to the main disconnect, the installation eliminates the hazard of having 480 volt conductors on the door. The close proximity of a PESD to the main disconnect also reduces the lead wire length and minimizes potential electrical interference with other components inside the enclosure. Providing short circuit protection on PESDs is another choice users must make between electrical safety and electrical integrity of their installation. Short circuit protection means that 12 additional connections - or failure points - are added between the source voltage and the PESD as per Figure 6. These failure points increase the likelihood of a false positive voltage indication. In most cases, the only risk is the failure of the PESD lead-wires, not the PESD 4. In addition, manufacturers of electrical equipment are providing more reliable termination points for PESDs on their equipment. Article 430.72 of the National Electrical Code also allows for the omission of short circuit protection if opening of a circuit would create a hazard. One last minor point; some facilities decide to fuse PESDs because they believe workers should use them as a presence-of-voltage indication, while others believe PESDs should be used for absence-of-voltage. In the latter case, PESDs should be installed without fuses.

Fig. 6: Potential failure when fusing a PESD

EXAMPLES OF PESDS REDUCING RISKS A large automobile manufacturer had concern over the level of PPE and the presence of voltage on the line side of their switchgear. This concern encouraged a common practice of requiring workers first to locate then isolate the correct upstream source disconnect when necessary. Figure 7 shows a PESD installed on the line side of the equipment disconnect reduces risks in two ways. First, it provides an indication that the proper upstream source has been disconnected. Second, it statistically increases the likelihood that a zero electrical energy state exists inside the equipment electrical panel. Without a PESD, the worker must assume that voltage exists both on the line and load side of the equipment disconnect unless proven otherwise. In order to prove this without a PESD, the worker dons PPE and performs a voltmeter test on the conductors in question. Alternatively, with a voltage indicator installed, the worker verifies its proper operation and then witnesses a changeof-state immediately after opening the upstream disconnect. It is important to note that the worker is not exposed to voltage during this process.

Fig. 7: PESDs on the line and load side of equipment disconnect

Safety Vol. 2 The next step is to open the equipment disconnect. With the upstream source isolated and the equipment disconnect opened, the change-of-state on the voltage indicator (illuminated to non-illuminated) ensures a high probability for zero voltage to exists inside the equipment enclosure. It would require three device failures in close succession for voltage to be present, so a worker verifying with a voltmeter will likely show zero volts. Using a risk assessment procedure, the automobile manufacturer would conclude that there is a reduction in risk under this scenario that may allow workers to enter an equipment enclosure and verify zero electrical energy with a voltmeter while utilizing a reduction in PPE. In a similar example, Cintas Corporation installed PESDs to protect its employees and to increase productivity in their automated plants. In these types of plants, Cintas’ laundry equipment resides behind a restricted safety fence. Cintas’ procedures require that all the equipment within the restricted area be put into a safe state whenever a worker enters this area. After Cintas evaluated their maintenance-related downtime, they determined their electrical maintenance procedures disproportionality affected their productivity-especially in the automated plants. It took workers a significant amount of time to retrieve and suit up in PPE each time a maintenance task required access to the inside of an electrical panel. Once workers established zero energy inside the panel, they would remove their PPE to comfortably perform the maintenance task, which also added to the downtime.

43 Cintas developed a two-part PESD assembly that included a voltage indicator and fused hard-wired test points (no built-in impedance) in a clear-cover housing as shown in Figure 8. With the power on and the panel door closed, the worker has a visual indication that voltage exists and a test point to confirm the voltage indicator is functioning properly. Once the isolator is opened, the worker witnesses the voltage indicator change-of-state from illuminating to non-illuminating; this provides the first indication that the power has been disconnected, which reduces the likelihood that the test points have voltage. The test points are specifically designed to accept standard voltmeter probes, and the clear cover prevents inadvertent access to voltage by a non-qualified employee. Next, the worker uses the live-dead-live procedure with a voltmeter to verify zero voltage exists between L1, L2, L3 and GRD as per the procedure below and NFPA 70E 120.1(5). Like the automobile manufacturer example, a failure of the isolator, the test points with the meter, and the voltage indicator need to occur in close succession for voltage to exist inside the panel. Using this process, which includes the steps in NFPA 70E 120.1(1-6), is not only more efficient, but creates an electrically safer work condition. This process is inherently safer because it eliminates the likelihood for maintenance employees to test potentially live conductors inside an electrical enclosure using a voltmeter. The process is at the same more time efficient because maintenance employees do not have to take additional time to gather, don and remove electrical PPE. The far reaching result of this approach is the ability to achieve safety improvements along with productivity increases that benefit both Cintas and their employees. When a facility has properly maintained electrical equipment installed with available short circuit current ratings and interrupting times that do not exceed the maximum as described in NFPA 70E Table 130.7(C)(15)(a), they can use those tables for determining the PPE required for performing each specific task. In this case, smaller companies with a less skilled electrical maintenance staff can also benefit from PESDs. The mechanical maintenance workers receive a huge benefit with PESDs when these devices are used in mechanical LOTO procedures. Workers performing mechanical LOTO - work involving no contact with conductors or circuit parts - procedures must still isolate electrical energy. PESDs provide a means of checking voltage inside an electrical panel without exposure to that same voltage. Without these devices, a worker performing mechanical LOTO in some facilities would be required to work in tandem with an electrician using a voltmeter to physically verify zero voltage inside an electrical panel before work begins. In that case, the electrician is exposed to voltage. With PESDs, the mechanic can single-handedly check for zero electrical energy without any exposure to voltage, which makes the LOTO procedure safer and more productive.

Fig. 8: Test Point Voltage Indicator Assembly and Housing with Clear Cover

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Safety Vol. 2

SUMMARIZING THE RISK REDUCTION PROPERTIES OF EACH PESD Every time workers create an electrically safe work condition as per NFPA 70E 120.1, they subject themselves to multiple hazards. The risk exposure directly correlates with the procedures and devices used in their LOTO program. Each of the devices used – from a voltmeter to the varied PESDs - have their own unique risk characteristics that are both good and bad. Table 1 lists each risk characteristic compared to a voltmeter and assigns a rating that allows users to graphically see the risk factors for each type of PESD5. The goal is ensuring a worker’s voltmeter measures zero voltage once he accesses the inside of the enclosure. For example, “testing duration” is the first risk characteristic listed in Table 1. The voltage indicator is colored green for reduced risk because this device is hardwired to the source and constantly tests all three phases and ground simultaneously all the time. On the other hand a voltmeter is colored yellow for moderate risk because a worker with a voltmeter performs one test at a time by touching each conductor with the voltmeter leads and testing be-

Notes:

tween each phase and ground. Therefore, the “test duration” is a risk characteristic of a voltage indicator that increases the safety of a LOTO procedure as compared to a voltmeter. In the second row of Table 1, the risk characteristic “ability to test other circuit parts” gives the voltage indicator a red rating because it is hardwired to a single set of conductors and cannot test other circuit parts within the enclosure. In this example, the voltmeter is assigned a moderate risk because it can test other circuit parts but the worker may be exposed to voltage. Since PESDs are inexpensive, many times users choose selected combinations of PESDs to further reduce their risks. Table 1 also provides the ability for users to see and select the right PESD combinations, not only to meet the requirements of their electrical safety program, but also to accommodate different installation and environmental issues. For instance, a user would select a voltage portal over a test point assembly in a harsh environment because test jacks will eventually fail due to the corrosive atmosphere and a voltage portal would not.

Table 1: PESD Risk Assessment Chart

Note 1: Some voltage indicator designs have as much as 2mA ground leakage current that increases as more voltage indicators are installed. Note 2: Fuses add additional connections and failure points that increase the likelihood for a false negative voltage reading (voltage exists and not indicated on test instrument).

See: http://www.graceport.com/assets/files/Data%20Sheets/ SafeSide_OvercurrentProtection_2013(2).pdf Note 3: The likelihood that voltage exists after opening the isolator and/or used in conjunction with a voltage indicator is very low. Note 4: Mechanical LOTO has a lower burden of proof for electrical energy isolation.

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Safety Vol. 2

Characteristics

REFERENCES

Test Point Assembly (impedance limited in housing)

Voltage Portal

Voltmeter

Typical Industrial Multimeter

20-750VAC/30-1000VDC design specific

600V

0-1000VAC (50/901000VAC)

1000V (Typical)

2 Phases tested at a time

3 Phase with no Ground

2 Test leads

3 Phase & Ground

Number of Phases

CAT III/IV

CAT III/IV

Cat III/IV

Cat III/IV

Voltage Indication

Visual

Digital Readout

Visual and Audible

Digital

Batteries Required

NO

YES

Portal-NO, NCVD-YES

YES

Type 12/13/4/4X

Type 12/13/4/4X with housing door closed

Type 12/13/4/4X

N/A

<60μA to 1-2mA depending on circuit

None

None

N/A

UL 61010-01 certification

Enclosure UL Rating Ground leakage current (Note 1)

1

NFPA 70E, 2012 Standard for Electrical Safety in the Workplace 120.1(1)

2

Duane Smith, ”What Do You Know About Capacitive Voltage Sensors?” Electrical Construction and Maintenance, Aug. 1, 2005, (http://ecmweb.com/content/what-do-you-know-aboutcapacitive-voltage-sensors )

3

From OSHA.gov website: https://www.osha.gov/SLTC/etools/ construction/electrical_incidents/eleccurrent.html

4

http://www.graceport.com/assets/files/Data%20Sheets/SafeSide_OvercurrentProtection_2013(1).pdf

5

Red=inherent risk; Yellow=moderate risk; Green=reduced risk

Non-Contact Voltage Typical Industrial Detector (NCVD) Multimeter

Part of the Device

Test Instrument Requirement Voltage Range

Optical Cable Voltage Indicator

Voltage Indicator

Table 2: PESD Characteristic Comparison Table

WRITTEN LOTO PROCEDURES AND MECHANICAL LOTO A PESD becomes a safety device only after it is included as part of a written LOTO procedure. Without being included in written LOTO procedures, PESDs are nothing more than just another electrical component. The LOTO procedure must explain to the worker each step in the LOTO procedure that involves the PESD. At a minimum, workers will need to verify proper operation of the PESD before and after performing a LOTO procedure. The automobile manufactuer and Cintas Corporation applications would not have been possible without the addition of PESDs into their LOTO procedures.

CONCLUSION The end-goal when utilizing PESDs is to create a safer work condition by reducing risks and increasing the likelihood that the zero energy exists inside the panel when a worker enters to test for voltage with his meter. Permanent Electrical Safety Devices (PESDs) are an example of safety by design and they incorporate functionality directly into electrical equipment. This allows for the workers’ exposure to shock and arc flash hazards to be further diminished during LOTO procedures because workers have no susceptibility to voltage. The applications of PESDs are an example of how safety and economics benefit each other. Under NFPA 70E 120.1(1-6), creating an electrically safe work condition is done solely with a voltmeter, but by adding PESDs into this process a safer work condition is created.

Phil Allen is the President and owner of Grace Engineered Products, the leading innovator of permanent electrical safety devices. He holds two US Patents, a power receptacle design and a voltage detector test circuit. His passion is finding new and more efficient ways of bringing electrical safety to the forefront. Phil did his undergraduate work at California State University, San Luis Obispo and is a 1984 graduate with a BSIE.

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Safety Vol. 2

THE ELECTRICAL SAFETY TRIFECTA PowerTest 2014 Terry Becker, P.Eng., Owner, President TRIFECTA: “Can be used to describe a situation when three elements come together at the same time. With respect to electrical safety three elements: safe installations, safe work practices and adequate electrical equipment maintenance are The Electrical Safety Trifecta.” Workplace electrical safety has evolved in the United States and Canada with the application of NFPA 70E Standard for Electrical Safety in the Workplace and since the CSA Z462 Workplace electrical safety Standard published on December 28, 2008. With CSA Z462 now in its published second edition, with the third edition in the works, energized electrical work in Canada will never be the same. But is this enough? Have we missed a key variable in electrical safety? What about electrical equipment maintenance?

History, Culture & Behaviors:

There are really three key elements to electrical safety and ensuring risk related to energized electrical power systems is reduced to as low as reasonably practicable (ALARP): safe installations, safe work practices and adequate electrical equipment maintenance. This “Trifecta” when it comes together will result in achieving the lowest risk to workers and highest reliability for electrical power systems.

When we consider the history of energized electrical work it is hard to believe that we have neglected the electrical hazards of shock and arc flash. Specifically we have allowed electricians to use their bodies as voltage detectors. Hard to believe, but from 1942 until 1960 the American Electrician’s Handbook taught electricians to use pain as a means of detecting that voltage was present in electrical conductors and circuit parts. Workers accepted this and accepted completing repair and alteration of energized electrical equipment as “part of the job of an electrician.” Today this of course would not be acceptable. In the past we focused on safe electrical installations, this is how we controlled exposure of all workers to shock. But what about arcing faults and arc flash how can we eliminate them from occurring or control the probability?

Industry has been focused on only legal requirements in the past, safe installations. Yes OH&S Regulations in Canada and the OSHA Act & Standards in the United States focus on workplace safety, but until recently in Canada there was no specific focus on shock and arc flash. That has changed.

Worker behaviors have also been a problem and they still are. Change is required, but making the change and ensuring that it occurs and is sustained, is and will be a challenge. How can we put into place “controls” that will have a positive impact on worker behaviors?

Why do we need electrical safety? History, statistics, and the results of electrical safety audits tell us that employers and employees have a long way to go to achieve sustainable electrical safety and eliminate or reduce the risk of exposure to shock and arc flash. Electrical installations are not constructed or maintained to the CEC or the NEC. We see in the news incidents where equipment and workers make contact with overhead power lines. Electricians continue to be shocked and accept it, they do not wear rubber insulating gloves with leather protectors. Electrical safety audits identify that workers are not “electrical safety competent,” LOTO processes and procedures are not in place or practiced correctly, Engineering “Safety by Design” is not practiced or if it is there may be errors in incident energy analysis studies, electrical hazards are not identified and adequate controls put into place, no electrical safe work procedures are written and used, there is no Electrical Specific PPE, Tools & Equipment or if they have been procured they have not been managed effectively. Lastly we have accepted the condition of energized electrical power distribution equipment. We may not have implemented any electrical equipment maintenance practices or the electrical equipment maintenance that has been performed has not been appropriate or completed at acceptable frequencies. Without electrical equipment maintenance the probability of abnormal conditions

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Safety Vol. 2 occurring on energized electrical equipment increases, thus the “risk” increases.

Evolution & Change: How can we effect change? How can we ensure the “change” is sustainable? We need to use management systems and apply the tools in Standards/Guidelines within the management systems. We need to deploy the management systems, get them to work for the benefit intended, audit their performance, implement corrective actions and implement a continuous improvement philosophy. We will need to overcome the challenges that make change difficult: Change is fear! Change is overwhelming. Change is hard. Change is necessary. Change is good. Change is inevitable. We must commit to change. Without change we cannot improve. The Canadian Electrical Code, Part 1 and the National Electrical Code, NFPA 70 were developed to effect change in safe installations. The NFPA 70E Standard and the CSA Z462 Standard were developed to effect change in electrical safe work practices. NFPA 70B and the NETA MTS Standards were developed and have evolved to effect change in electrical equipment maintenance. In Canada the new CSA Z463 Guideline on Maintenance of Electrical Systems published in December of 2013 will effect change in Canada with respect to improvements in electrical equipment maintenance. A Trifecta for electrical safety is achievable. What do I mean by this statement? I’m not a gambler, and this is not a horse race, but I know that when it comes to electrical safety, it is within our power to achieve this level of success. This is the result of managing electrical safety to the highest levels. Doing everything possible to reduce the risk of exposure to workers to the electrical hazards of arc flash and shock. How can we achieve this result and reduce the risk to as low as reasonably practicable (ALARP), by using the Electrical Safety Trifecta: approved equipment and installed to the CEC Part 1 or NEC, establishing electrical safe work practices (e.g. De-energize, Test-Before-Touch), and implementing effective electrical equipment maintenance. All three of these elements should be implemented and maintained using appropriate management systems.

Approved Equipment Installed to CEC Part 1 or NEC This is a legal requirement and an expectation with respect to energized electrical equipment. The equipment is designed to perform as intended and installed so that it operates with inherent safety under normal operating conditions. Electrical Quality Man-

agement Programs can be developed and implemented to ensure we procure approved equipment and that it is installed to the CEC Part 1 or NEC and that jurisdictional requirements for permitting and inspections occur.

Establishing Electrical Safe Work Practices With the addition of the CSA Z462 Workplace electrical safety Standard to the tools we have available in Canada we can use it to implement electrical safe work practices. Applying CSA Z462 within an Occupational Health & Safety Management System approach, by developing and implementing an Electrical Safety Program, will guarantee measurable and sustainable electrical safety performance.

Effective Electrical Equipment Maintenance Traditionally electrical power distribution equipment has been maintained to guarantee some level of reliability and to protect electrical equipment from damage by ensuring electrical protective devices operate as intended. A refocusing of electrical equipment maintenance prioritization will focus on ensuring arcing faults do not occur, or limiting incident energy if an arcing fault and arc flash occurs and ensuring that the workers performing energized electrical equipment maintenance are protected. In Canada the new CSA Z463 Guideline for Maintenance of Electrical Systems released in December 2013 will be Canada’s electrical equipment maintenance guideline; it will realign electrical equipment maintenance priorities to: safety to workers, reliability and limiting damage to electrical equipment. By using CSA Z463 in Canada and NFPA 70B and NETA MTS Standards in Canada and the United States in developing Electrical Equipment Maintenance Programs we can ensure that energized electrical equipment is maintained to a “Normal” operating condition and achieve “The Electrical Safety Trifecta.” Terry Becker, P.Eng., is the owner of ESPS Electrical Safety Program Solutions Inc. in Calgary, Alberta, Canada. Terry has over 24 years experience as an Electrical Engineer, working in both engineering consulting and for large industrial oil and gas corporations. He is a Professional Engineer in the Provinces of Alberta, British Columbia, Saskatchewan, and Ontario. Terry is the past Vice Chair of the CSA Z462 Workplace Electrical Safety Standard Technical Committee, and currently an Executive Committee member, voting member, and leader of Working Group 8 Annexes, as well as a member of the IEEE 1584 Committee, the CSA Z463 Guideline for Electrical Equipment Maintenance Standard Committee, and a member of the NFPA 70E Annexes Working Group.

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PLANNING AND PERFORMING A POWER QUALITY SURVEY NETA World, Spring 2015 Issue Ross Ignall and Richard Bingham, Dranetz

INTRODUCTION The power quality survey is the first, and perhaps most important, step in identifying and solving power problems. Power problems can harm equipment performance and reduce reliability, lower productivity and profitability, and even pose personnel safety hazards if left uncorrected; however, the power quality survey is an organized, systematic way to resolve them. Whether the investigation involves a single piece of equipment or the facility’s entire electrical system, the survey process typically requires these five basic steps: ● Planning and preparing the survey ● Inspecting the site ● Monitoring the power ● Analyzing the monitoring and inspection data

cabinet door and use their tablet, smartphone, or computer to set up monitoring and review and download data remotely, greatly reducing their exposure to hazardous environments. Permanent monitors are typically installed for the lifetime of the facility and use screw terminal connections for voltage and split core or solid core CT’s for current measurements. Such monitors are usually safely mounted behind the closed doors of cabinets or switchgear and remotely monitored by server software using an Ethernet or fiber network. Oftentimes, multiple permanent PQ monitors are installed at key points within a facility creating a monitoring system such as at the PCC and at critical loads. Recorded trend and PQ event data is automatically transferred to the server software for use by facility personnel to proactively monitor the quality of supply or to reactively resolve PQ problems as they occur.

● Applying corrective solutions ● Verify corrective solutions

POWER QUALITY SURVEY TOOLS The basic tools of the power quality survey are the power quality monitor, circuit tester, multimeter, and an infrared scanner. Other useful tools include clamp-on (Hall effect) current probes, video camera, tape recorder, ground resistance meter, and insulation tester. Not all of these tools are necessary for every survey, but the power quality monitor is the mainstay. Power quality monitors of widely diverse functionality are available for the documentation of electrical conditions encountered during the physical inspection, as well as the gathering and storing of data for later analysis. Power quality monitors generally fall into two categories: Portable and permanently installed (fixed) systems. Portable monitors are typically used in temporary applications, and are installed for the duration of the survey and removed upon completion. Such monitors usually have safety (banana jack) connections for voltage and clamp on or Rogowski coil CT’s for current measurements. Survey results can be reviewed on the instrument’s local screen (if available) or uploaded to PC application software, or both. The latest generation of portable monitors enhances user safety and productivity by using Wi-Fi, Ethernet and Bluetooth communications to fully remote control the instrument after the physical installation. Users can close the

Fig. 1: Portable power quality monitor being installed by an electrician wearing PPE clothing Regardless of whether a portable or permanent solution is used, PQ monitors from various manufacturers can have different features and, more importantly, monitoring capabilities and technology. It’s important to make sure that the instrument being used can capture the full spectrum of power quality problems or at least the types of problems suspected. Otherwise, the survey results could be misleading and misreported, wasting valuable time and money. Modern power quality instruments should be Class A compliant with IEC 61000-4-30 which is an international standard for

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Safety Vol. 2 power quality measurement. Initially released in 2003 and updated in 2008 (next update is pending), IEC 61000-4-30 specifies the measurement techniques that should be employed to appropriately and accurately measure the quality of supply. Being Class A compliant means the instrument fully complies with the standard, is from a reputable manufacturer, and provides accurate and repeatable measurements. Although IEC 61000-4-30 is an international standard, in the United States, the IEEE is in the process of harmonizing to this well-established standard which will be included as part of new editions of IEEE 1159 (power quality) and IEEE 519 (harmonics). An example is the recently released IEEE 519:2014 that adopted the harmonic measurement techniques of IEC 610004-7, with added compliance limits for voltage and current.

PLANNING AND PREPARING THE SURVEY Like any good investigative reporter trying to get to the bottom of the story, the process essentially involves finding out the what, where, when, how, and why of the power related problem(s) at hand. Defining objectives not only keeps the project in focus, but also helps identify the specific equipment resources needed to get the job done. Where to monitor depends on where the problems are observed or suspected. If the problem is localized to one piece of equipment, then placing a monitor at the connection point where the equipment is powered is a good starting point. Sometimes equipment can be both a contributor to and a victim of powering and grounding incompatibilities in the power system. You can then work backward to the point of common coupling (PCC) with the utility if the source of the problem is not found at the equipment. Conversely, if the entire facility is being affected, or if you want to conduct a baseline survey to determine the quality of the supply from the electric utility, starting at the PCC is the logical choice. You can then work down through each feeder circuit to specific loads.

cording failure symptoms or hardware failures; noting any recent equipment changes, additions, or facility renovations; and logging the operating cycles of major electrical equipment in the facility.

INSPECTING THE SITE The site examination begins by visually inspecting outside the facility and around the vicinity in order to gain a better perspective of the utility service area. Things to look for include type of electrical service (for example, underground), utility power factor correction capacitor installations, neighboring facilities which might be backfeeding interference onto a shared utility feeder, nearby substations, and other potentially problematic conditions. Inspecting the facility helps to identify equipment that might cause interference. It will also surface electrical distribution system problems such as broken or corroded conduits, hot or noisy transformers, poorly fitting electrical panel covers, and more. An infrared camera can be very helpful with this. Major electrical loads such as large photo-copiers, UPS systems, air compressors, and so forth, should be reviewed. Give special attention to loads near trouble equipment. Any inspection should include a physical review of the wiring from the critical load to the electrical service entrance to identify any load which might cause power problems. All necessary safety precautions should be observed, such as NFPA 70E, and only qualified personnel should perform any required testing and maintenance work. As Table 1 shows, common wiring problems are a frequent cause of power quality problems. Loose connections and other discrepancies noted during inspection of the electrical distribution system should be corrected prior to monitoring. Particular attention should be paid to equipment power cords and plugs, receptacles, under carpet wiring, electrical panel-boards, electrical conduits, transformers, and the electrical service entrance.

The time when the problem occurs can also provide important clues about the nature of the power problem. If the problem only occurs at a certain time of day, then any equipment switched on at that time should be suspect. Utility operations, such as power factor capacitor switching should also be considered as a potential source of problems that occur regularly and at the same time each day. The monitoring period should last at least as long as a business cycle, which is how long it takes for the process in the facility to repeat itself. Some processes run identically for three shifts, seven days a week. Other operations are different each day of the week, in which case the minimum monitoring period would be one week.

Problem

Effect

Loose Connections

Impulses, voltage drop

Faulty (hot) breakers

Impulses, voltage drop

Neutral-to-ground tie

Ground Current

Neutral-to-ground-reversal

Ground Current

High impedance neutral (open) in polyphase circuit

Extreme voltage fluctuation (high or low), neutral-to-ground; voltage fluctuation

High impedance neutral-to-ground bond at transformer

Voltage fluctuation, neutral-to-ground; voltage fluctuation

High impedance neutral-to-ground bond at service entrance

Voltage fluctuation, neutral-to-ground; voltage fluctuation

As part of the planning and preparation process, it is necessary to obtain a site history for the facility or equipment being investigated. Asking questions of equipment operators or others familiar with operations is an important part of acquiring the site history. Typical site data of interest would include: determining the time, both occurrence and duration, of recurrent system problems; re-

High impedance open circuit grounding

Neutral-to-ground voltage fluctuation

Table 1: Typical PQ causes and events

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Safety Vol. 2

MONITORING THE POWER The power monitors should be placed at the locations determined during the planning and inspection activities. In general, to determine the overall power quality of the facility, place the monitor at the service entrance. To solve a power problem for a single piece of equipment, place the monitors as close to the equipment load as possible. It’s important to monitor both the voltage and current. Monitoring the voltage identifies the occurrence of a power quality problem, but by also monitoring the current you can determine the source of the problem as either originating upstream or downstream from the equipment load.

● Compare power events to equipment event logs and performance specs. ● Extract key power monitoring events which may cause equipment malfunction. ● Classify key power monitoring events into groups to simplify analysis. ● Correlate and validate power monitoring events with equipment symptoms. ● Identify cause in terms of voltage sag, ground or neutral event, transient or voltage distortion (Table 2).

APPLYING CORRECTIVE SOLUTIONS Adding new wiring, UPS systems, transformers, filters, or other mitigation devices as appropriate may resolve the problems identified during the survey. Moving an interference source to a different circuit sometimes also works. However, make sure that you or the power professional analyzing the survey results has the expertise to safely and properly resolve the problems found. Significant time and money can be wasted deploying inadequate solutions, only to replace them with more appropriate solutions in the future. It is also recommended to repeat the power survey after the problem has been mitigated to prove the problem has been properly resolved and that the power system is now operating as expected. Fig. 2: Instantaneous downstream Sag: the current increases causing the voltage to decrease The three-step monitoring process involves: (1) using the instrument’s scope mode to see voltage and current magnitudes and wave shapes, (2) using the time interval setting to record background events and slow changes, and (3) using the limits and sensitivity threshold setting to record disturbances or events that may affect the equipment or process being monitored. Periodically checking the captured data allows the user to tweak the thresholds to capture only those events that are critical to the equipment’s performance. (Why capture the entire ocean, when all you want are the fish?)

ANALYZING THE MONITORING AND INSPECTION DATA

A more proactive approach is to permanently install a power quality monitoring system at the PCC, each distribution panel, UPS, and each critical load. Monitoring the system in this way produces a more complete, continuous picture of the entire system’s performance. Such systems record power quality (and usually demand and energy) continually and will be online should any problem occur, large or small. Proactive power monitoring can not only be used for continual system improvements and management, but also for automatic notification of a deterioration or change in the power systems, preventing future interruptions, downtime, and lost productivity from occurring.

OBSERVE THE RULES There are five simple rules to keep in mind while performing a power quality survey:

To identify equipment problems, it is key to analyze data in a systematic manner. First, look for power events that occurred during intervals of equipment malfunction. Next, identify power events that exceed performance parameters for the affected equipment. Also, review power monitor data to identify unusual or severe events. Finally, correlate problems found during the physical inspection with equipment symptoms. A number of additional procedures must also be performed, including:

● Apply the test of reasonableness to all data and information. Basic laws of physics cannot be temporarily repealed to make something believable.

● Review all inspection records, site data, and equipment event logs to plot key event summaries.

● Don’t fall victim to paralysis by analysis. Set reasonable monitor thresholds, concentrate on the larger events, and then work your way down.

● Know the performance as well as the safety limitations of monitoring and test equipment. ● Look for the obvious. Most power problems are solved like peeling onions – one layer at a time.

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Safety Vol. 2 To find the symptoms, causes, and solutions for the various power events in upper left column, match the adjacent code numbers to the corresponding descriptions in the chart. Power Event

Equipment Symptoms

Typical Causes

Solutions

Impulse

1, 2, 3, 4, 5, 6, 7, 8

1, 2, 3, 4, 5, 6, 7, 8

1, 2, 3, 4, 5

Neutral Ground Voltage

2, 9, 10, 11, 12

3, 5, 9, 10, 11, 12

1, 4, 6, 7

Outage

1, 3, 9, 12, 13, 14, 15

3, 13, 14, 15

2, 4, 8

Voltage Sag

9, 12, 14, 15, 16, 17, 18

3, 3, 13, 16, 17

1, 2, 4, 7

Voltage Distortion

19, 20, 21, 22, 23

1, 2, 17, 18, 19, 20

1, 4, 9, 10

Nonsinusoidal Phase Current

16, 24, 25, 26

2, 17, 21, 22, 23

4, 9, 11

Repetitive Disturbance

2, 5, 8, 9, 11, 17, 27, 28, 29, 30

1, 2, 17, 24, 25

4, 5, 12

Neutral Current

24, 25, 26

1, 26, 27

4, 7, 13, 14

Equipment Symptoms

Typical Causes

Solutions

1. Hard disc crash 2. Parity errors 3. Power supply failure 4. Component failure 5. Lock up 6. Memory scramble 7. SCR-failure 8. Speed/setting drift 9. Dropped Calls 10. Erratic equipment operation 11. Poor resolution 12. Reset/reboot 13. Depleted batteries 14. Low voltage inhibit 15. Process interrupt 16. Circuit breaker trip 17. Soft errors 18. Undervoltage detection 19. Excessive heat 20. Lack of phase synchronization 21. Undervoltage circuit activation 22. Motor failure 23. Nuisance tripping 24. Excessive heat in wiring 25. Excessive heat in transformers 26. Excessive neutral currents 27. Circuit board failure 28. Audible noise 29. Measurement errors 30. Surge suppressor failures

1. SCR-controlled loads 2. Variable speed drives 3. Faulty wiring and /or circuit breakers 4. Contact and relay closure 5. Load startup or disconnect 6. Power factor correction 7. Lightning 8. Photocopiers/laser printers 9. Loose or missing N-G bond 10. Excessive ground current 11. Faults to ground 12. Excessive neutral current 13. Utility power fault 14. Alternative power source failure 15. Local circuit breaker trip 16. Faults and shorts 17. UPS/motor generator instability 18. Switchmode power supplies 19. High impedance sources 20. High impedance electrical wiring 21. Computers 22. Electronic ballast 23. Electronic phone systems 24. Light dimmers 25. Arc welders 26. Phase-Neutral powered rectified loads 27. Phase imbalance

1. Repair/replace faulty wiring 2. Repair/replace faulty breakers 3. Add snubbers to contacts and relays 4. Add power treatment devices (surge suppressors, filters, conditioners, isolation transformers, UPS, etc.) 5. Move source of disturbance or load 6. Correct faults to ground 7. Increase gauge of wiring 8. Repair power source 9. Decrease impedance of power source 10. Use RMS, not peak sensing circuitry 11. Decrease nonsinusoidal load 12. Isolate the source 13. Balance Phase 14. Harmonically balance loads

Table 2: Symptoms, causes, and solutions for various power events ● Probably the most important rule: start with the simple things first. People are always amazed to find out how often power problems are caused by nothing more mysterious than loose wiring connections. (Table 1). Richard P. Bingham retired in 2008 as the VP of Product Development and Marketing for WPT, which includes Dranetz-BMI, Electrotek Concepts, and Daytronic. He presently works as a consultant for Dranetz and PowerCET providing project management, power quality audits, and expert witness. Following

completion of his BSEE at the University of Dayton, he joined the company in 1977, and has held positions as project engineer, chief technologist, VP of Engineering, and, VP of Strategic Planning at Dranetz. Richard also has an MSEE in Computer Architecture and Programming from Rutgers University. He is a member of IEEE Power and Energy Society, and the Tau Beta Pi (the Engineering Honor Society). Richard also serves as the chairperson of the IEEE PQ Subcommittee and formerly chair of the NFPA 70B Electrical Equipment Maintenance committee, as well as a principal member of Code Making Panel 20 of NEC on HomeLand Se-

52 curity. He also serves as secretary/vice-chair/chair and member of the numerous other IEEE PQ power quality related committees. He holds one patent. Ross Ignall graduated from Trenton State College (now The College of New Jersey) in 1986 with a Bachelor of Science in Electronics with a minor in Computer Science. Ross has more than 20 years of experience in the design, development, marketing and application of test and measurement instrumentation. Ross joined Dranetz in 1990 as a Design Engineer, ultimately working as a Group Leader and Senior Engineer leading new product development projects. Ross is presently the Director of Product Management working on the specification, development and application of portable and permanently installed power monitoring instruments and systems. Ross is a frequent domestic and international speaker and has written many seminars, papers and articles on power instrumentation, power quality, energy monitoring and their applications. Ross is also a contributing author for several books on power quality and power monitoring and is co-inventor of a US patent titled Electrical Parameter Analyzer used as the foundation for Dranetz’ Power Platform family of products.

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HAND PROTECTION NETA World, Summer 2015 Issue Paul Chamberlain, American Electrical Testing Co., Inc.

Workers’ hands are the most commonly injured part of their bodies. Whether the hazard comes from spinning blades, pinches between two materials, heat, chemicals, or electricity, working hands are under constant attack. In most work environments, utmost care should be taken to protect workers’ hands. This article identifies the common hazards and risks to a worker’s hands and the means to mitigate injury and promote safety.

CHEMICALS Many commonly used chemicals in the workplace can cause chronic illness through dermal absorption and may go undetected by the worker; as such, direct contact must always be avoided. Some chemicals can cause painful and debilitating burns on the skin that may take a long time to heal. Both burns and dermal absorption can potentially result in serious or even fatal injuries. Employers and employees must ensure the proper use of gloves that are specific to the type of chemical being handled.

There are many materials available for glove construction; some are better suited than others for resistance to breakthrough or permeation. Breakthrough time is determined using an ASTM standardized test for the elapsed time between initial contact of the chemical on one side of the glove material and the analytical detection of the chemical on the other side of the glove material. If there is no breakthrough, this is marked as ND (none detected) for the test. These times generally reflect how long a glove can be expected to provide resistance when totally submerged in the chemical. The permeability of the material, or permeation rate, is how long it takes for a chemical to pass through the glove on a molecular level. Glove thickness can affect the permeability of a material. Again, there is an ASTM test for this, and the glove manufacturer must rate the permeability of the glove on its fact sheet. When determining the correct glove for handling a chemical, always refer to the manufacturer’s fact sheet, such as the one excerpted from Ansell. (See Figure 1)

Fig. 1: Ansell Permeation/Degradation Resistance Guide NOTE: The actual table is several pages in length; more information can be found at: http://www.ansellpro.com/download/Ansell_8thEditionChemicalResistanceGuide.pdf

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LACERATION / ABRASION / CRUSHING

ERGONOMIC / REPETIVE

Cutting a finger while removing insulation, scraping a hand on a sharp panel door edge, or slamming a finger with a tool, can be hard to avoid. Human beings are fallible; however, we can minimize the impact of these injuries by using protection like leather, cotton, or rubberized gloves. In extreme circumstances, Kevlar or metal gloves may be necessary. Leather gloves are usually the preferable means of protection from all of these injuries and are relatively inexpensive. A good rule-of-thumb is that if a tool is necessary to do the job, it is likely that gloves are also needed.

Carpal tunnel syndrome is one of the most common hand injuries in the United States. It is even harder to prevent when activites outside of the workplace contribute to these injuries. Other common types of repetitive motion injuries are tendinitis and bursitis, which are injuries to tendons and bursae, respectively. Carpal tunnel syndrome is not an occupational hazard exclusive to those using a computer; it is also a hazard to anyone who performs repetitive hand motions, mechanical gripping, small part assembly, or encounters vibration in fields such as mechanics, factory work, or an electrical trade. Education is the best method of prevention for repetitive motion injuries. To avoid these injuries, perform frequent range-of-motion exercises (Figure 3) to warm up and alleviate injury. Many tools are available that promote proper ergonomics and posture, such as a wave-style keyboard, or a track-ball mouse. Hand tools such as right-angle power drills and t-handle drivers also help prevent hand and wrist strain and proper hand positioning. Padded palms and fingers can help prevent repetitive motion injury while using vibratory tools such as a hammer drill or jig saw, or while using impact tools such as a hammer.

Fig. 2: Moby Safety Box Knife A job hazard analysis, along with good, old-fashioned common sense, will also help determine if an employee could get lacerated or otherwise injured performing a task. Much like other forms of personal protective equipment (PPE), gloves must be inspected for wear and tear and replaced as necessary. Different work methods can also go a long way toward reducing preventable hand injuries. Instead of using a knife to strip insulation, for example, use a wire stripping tool. Use safety knives (Figure 2) to open letters and boxes instead of a razor blade or scissors. Ensuring correct guarding on tools like rotating carpenters saws or right angle grinders will also reduce the likelihood of injury. Inspect workers’ tools regularly to ensure that the guarding has not been removed or compromised. Removing the guard may aid in getting a job done quicker or easier, but it could cost a finger — or worse.

Fig. 4: Microsoft Ergonomic Keyboard 4000 Additionally, it is suggested that for every hour sitting and working on a keyboard, take a minute or two to get up, move around, and stretch. Several manufacturers of ergonomic mice and keyboards have companion software to remind the worker to stretch and can even show the worker more effective stretching exercises depending on use. (See Figure 4)

ELECTRICAL SHOCK Electrical shock injuries to the hands are common in the electrical testing industry. With regard to PPE, the best prevention for this type of shock is to wear the correct hand protection. Workers must wear voltage-rated gloves that are correctly rated for the task. The gloves must be tested in accordance with an ASTM standard to ensure they sufficiently protect the worker. See the chart from Salisbury for the approved voltage levels for each glove design. (Figure 5) The cuff length must also be adequate to protect the forearm from electric arc.

Fig. 3: Stretching Exercises to Minimize or Eliminate Carpal Tunnel Syndrome

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Fig. 5: Salisbury’s ASTM Rubber Glove Labeling chart Available here https://www.salisburybyhoneywell.com/en-US/press/product_support/Case%20Studies/Salisbury%20ASTM%20 Label%20Chart.pdf Gloves must be re-tested to the ASTM specification regularly. There are two OSHA standards that indicate the appropriate test intervals: ● OSHA 1910.137 (Personal Protective Equipment, Electrical Protective Devices). This regulation states that gloves must be electrically tested before first issue and every six months thereafter. ● OSHA 1910.268 (Special Industries, Telecommunications). This regulation states that natural rubber insulating gloves must be electrically tested before first issue, 12 months after first issue and every nine months thereafter. It is also required that any un-issued glove that has not been tested within 12 months is re-tested before issued to an employee. The date of last inspection must be marked on the glove or tracked by another means to confirm that the expiration date has not been exceeded. OSHA regulation 1910.137(b) (2)(xii) states that the employer shall certify that equipment has been tested in accordance with the requirements of paragraphs (b)(2)(viii), (b)(2)(ix), and (b)(2)(xi) of this same regulation. The certification shall identify the equipment that passed the test and the date it was tested. Individual marking of the glove (i.e. equipment identification numbers) and entering the results of the tests and the dates of testing onto a tracking log is an accepted means of meeting this regulatory requirement.

Users of the protective equipment must also inspect them before each use and after any action that may cause damage. This inspection does not need to be tracked, but it does need to be conducted by users to ensure their safety. The user must visually inspect the gloves for any physical damage like punctures, cuts, nicks, cracks, scratches, or abrasions. The user must also inspect the glove for any chemical deterioration of the material by looking for Fig. 6: swelling, softness, stickiness, or hardness. Salisbury Rubber Ozone may also cause rapid deterioration of Glove Inflator rubber goods. The glove must be inflated to no more than twice its normal size to ensure that the rubber stretches, and the glove must be inspected for breaks in the material by listening and looking for the defect. (See Figure 6) If a portable inflator is not avaiable, then the glove can be manually inflated by rolling the cuff towards the fingers and then spreading the fingers to look and listen for escaping air from holes. To ensure a thorough inspection, this test should also be repeated with the glove turned inside out. More detailed inspection guidelines and procedures can be found under ASTM F1236.

56 CONCLUSION With so many bones, ligaments, tendons, and joints keeping hands and wrists working, there is ample opportunity for injury in the workplace and during everyday activities. Correct protection, training, equipment, and techniques go a long way to protect these important assets. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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COMMISSIONING PROGRESS COMMUNICATION PowerTest 2015 Michael Lewark, P.E., Power Group SNC-Lavalin Inc.

ABSTRACT An often-overlooked aspect of the commissioning process is the need to document, quantify, and communicate project progress and issues to non-technical team members for a variety of reasons. The initial development of this method was driven by a need for invoice backup, and has expanded to become a useful tool for managing the commissioning process. This method can be tailored to suit the needs of the service provider and client. A key to its successful implementation is determining the structure of the needed communication in the early stages of the project. The project setup becomes an integral part of the overall execution plan. The planning stage establishes the tracking and reporting mechanisms. Spreadsheets are developed for the necessary phases in the commissioning process. Spreadsheets tend to be the most useful aid in progress calculation. The frequency of updates depends on the duration of the project and the criticality of tracking the commissioning progress. For longer projects, weekly updates and reports are easier to maintain. The method in this paper is built upon three layers of information. The drawings and test sheets that typically capture the technical information on the commissioning process comprise layer one. Layer two consists of the tracking spreadsheets summarize and quantify the progress in the technical documentation. The last layer is a report with a narrative of the work executed during the update period, and high-level totals of the spreadsheets tracking the different phases of commissioning. The layered approach provides compactly the various levels of information needed by the different team members. The method presented in this paper is based on a commissioning program that has evolved over many projects, and is considered to be fully encompassing. This method may not properly address the quality assurance process required for different projects or industries.

INTRODUCTION There are many papers that cover the technical aspects of commissioning execution, but few that cover the process and even fewer that cover the communication. This paper deviates from the typical subject matter in that it discusses some of these fundamentals of the commissioning process and communication. At the time of writing this paper, there is no industry-accepted reference available for the commissioning of electrical power equipment and systems. This paper attempts to provide sufficient background information so that the method of commissioning progress commu-

nication, and how it fits into an overall project, is clear. This paper does not explain every example used, but does use examples and terminology that are common in the industry.

BACKGROUND Commissioning is a methodical and documented process of ensuring that a system performs according to the intent. Commissioning breaks each system into the simple components and subsystems, and verifies the functionality of each prior to testing the system as a whole. The process involves overlapping tasks performed in a specific order with operational verification being the final step. Documentation of the process is used to demonstrate that the system was properly commissioned. A properly executed commissioning process provides a high level of confidence that a complete system will function as intended and be reliable. Commissioning validates that the design meets the intent, that the equipment functions within manufacturer’s tolerances, and that the construction is built per the design and meets applicable quality standards. The completed project will operate safely, protecting personnel and equipment. The deliverables from the commissioning process will become the basis for the owner’s operation and maintenance program. A well-defined process will ensure a consistent approach to delivering projects that meet the needs of the owner.

MOTIVATION The goal of this paper is to present an approach to quantify a quality process in general terms so that it applies to all electrical industries. It may seem counterintuitive to expend effort that does not directly advance the commissioning process, but it is necessary in modern project delivery programs for coordinating commissioning activities with the other scopes of work to meet project milestones. Because the bulk of commissioning activities occur near the end of a project, and typically while some construction activity is still taking place, it is important to note and document construction activities that are impeding commissioning progress. Depending on the contracting strategy of the project, project activities, which have adverse impacts on the project schedule, could also have commercial implications. Therefore, it is extremely important to capture and quantify these project activities as close to discovery

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as possible. Doing so protects the commissioning agent in the event of delays caused by construction, and helps communicate the urgency of completing the task so that commissioning of those items can commence. Commissioning often has to absorb schedule slips from other phases of the project due to the potential impacts of missing an in-service date (ISD). ISDs can have cost impacts in the form of liquated damages or loss of ability to recover the investment through consumer rates. Missed ISDs can introduce schedule delays because of required and lengthy outage application leadtimes. Accurately tracking progress and keeping the entire project team apprised of the status is critical to mitigating the risk of missing an ISD.

The execution stage involves following the procedures and documenting the work according to the requirements established in the planning stage. The commissioning progress communication methodology outlined in this paper is used during the execution stage of a commissioning project. The commission execution stage can be broken into the following, but not necessarily chronological, steps: Commissioning Execution Steps ● Circuit Proving ● Component Testing ● System Function Testing ● Placing into Service ● Operational Verification

SEQUENCE Before presenting the method for communicating the progress, it is necessary to describe the sequence of a typical project. Establishing the sequence places the quantifying and reporting progress into the context of an overall project. There are two basic types of projects: addition and removal. An addition project involves the commissioning of a new component or system. A removal project involves decommissioning an existing component or system. Decommissioning is simply the reverse of the commissioning concept already established in this paper. Each type of project consists of five phases: Addition Project Phase

Removal Project Phases

● Design

● Design

● Procurement

● Procurement

● Construction

● Decommissioning

● Commissioning

● Demolition

● Closeout

● Closeout

For simplicity purposes, the remainder of the paper will refer to only commissioning. The commissioning phase of a project consists of three stages: planning, execution, and reporting. The planning stage establishes the procedures to be followed and lists the documentation requirements for the subsequent stages. These requirements include the development of high-level documents that cover the whole project, or very detailed documents for specific tasks. Examples of aspects that require high-level plans include: commissioning, safety, quality, lockout, outage, and energization. Specific task plans can detail lifting a wire, performing an inspection, or testing an apparatus. The planning stage continues through execution. The basis for the commissioning progress communication should be established in the planning stage to maintain consistency throughout the project.

The reporting stage is typically defined as the point where the commissioning deliverables are provided to the necessary stakeholders. This paper introduces the concept of adding progress reports, which track the project execution up to the final deliverables submittal. Below is an overview of the commissioning phase of a project: Commissioning Project Overview Design

Planning

Procurement

Detailed Circuit Proving Component Testing

Construction Commissioning

High Level

Execution

Closeout Reporting

System Function Testing Placing Into Service Operational Verification Progress Deliverables

More complex projects may contain smaller, possibly concurrent projects that could be in different phases, stages, or steps of the process. It is important to be able to identify these aspects and ensure that they are properly handled with reference to one another. This section of the paper established the commissioning process sequence and how the commissioning progress communication fits into the evolution of the project. The following section will outline the development and implementation of the commissioning progress communication.

APPROACH Commissioning progress communication is based on three levels of information. The layered approach presents the information in such a manner that points of interest are clearly communicated, and in a format that addresses the needs of all project team members. All of the information must be organized and available to allow specific issue investigation, or to audit the process at a particular point. Each successive layer summarizes the information from the lower layer up to the top layer, all of which provides a

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Safety Vol. 2 snapshot of the project status. As detailed in the previous section of this paper, establishing the templates and expectations in the planning stage of the commissioning process is crucial to the successful implementation of the progress communication.

First Layer – Commissioning Documents The first layer of information is based on documents that directly capture the commissioning execution. These documents exist regardless of whether or not the commissioning progress communication method is used. The examples presented in this paper do not represent a comprehensive list. It is the responsibility of the project team to determine the appropriate requirements. Examples of commissioning documents: ● As-left / Marked Up Drawings ● Component Testing Data Sheets ● System Function Testing Plans

Tracking List Minimum Requirements ● Identification (Drawing, Circuit, Component, System) ● Percentage of Completion ● Level of Effort ● Comments Tracking List Enhancements ● Preliminary Evaluation ● High-Level Activities ● Impacts from Other Scopes of Work Commissioning project controls are not required for this methodology, but are necessary to properly document issues and changes to the project. The control logs are important tools for summarizing the issues encountered during commissioning; their minimum requirements and suggested enhancements are listed below:

● Operational Verification Plans

Control Log Minimum Requirements

● As-left Device Settings ● Marked up Operation guides

● Identification (Request for Information, Deficiency, Engineering Change Notice)

Examples of commissioning project control documents:

● Brief Summary

● Requests for Information

● Date Submitted

● Deficiency Reports

● Date Resolved

● Engineering Change Notices

Control Log Enhancements

Other documents not captured in commissioning progress communication method, but important nonetheless:

● Assigned Resources ● Level of Priority

● Equipment manuals

● Impacting Outages or Energization

● Test Equipment Calibration Documentation

● Level of Effort

Second Layer – Tracking Lists and Control Logs The second layer of information is used to summarize the items in the first layer. The templates for these documents will have been established in the planning stage of the commissioning process. The success of this second layer is dependent on the accuracy and accessibility of the information contained within the documents from the first layer. Proper organization is not only expected from commissioning professionals, but it is also necessary for facilitating the reviews during document updates in the second layer. The second layer introduces the use of spreadsheets in the form of tracking lists and control logs. The intent is to summarize the first layer documents into a single line on one of these second layer spreadsheets. The exact contents of the single line will vary according to the project requirements. There are some minimum content requirements listed below in order to implement the commissioning progress communication method, as well as suggested enhancements.

There are a variety of ways to summarize the work of the underlying layer and to track the level of work complete. Progress can be tracked based on drawings, circuits, components, or systems as long as the method selected is clear and established early in the project. Depending on the approach used, the determination of completion for certain tasks could be straightforward or difficult to estimate. As long as the approach is clearly defined and used consistently, improvements can be made to ensure accuracy with the reporting.

Third Layer – Progress Report The third layer of information, called the progress report, summarizes the items in the second layer and is preferably one page in length. The key sections of the progress report are outlined below, along with a description of the information that should be included in each section. Note that all lists and logs in the second layer should be provided with the progress report. Documents from the first layer should only be provided as needed to support issue resolution. The most beneficial format for reviewing the progress

60 report is in a meeting with the appropriate project team members. The progress report also provides the agenda for the update meeting. Weekly meetings tend to support the execution stage while not impacting the advancement of work significantly. The project team should determine the frequency of the progress updates and update meetings at the planning stage. The progress report must contain completed work, planned work, percentage completed, support needed, and schedule risk.

Safety Vol. 2 Note that, depending on the contractual arrangement, this method does provide useful commercial tools to the commissioning agent, such as justification for additional work, invoice backup with documented work completed, and tracking of progress impediments. Simplified commissioning phases: ● Plan All Work Appropriately

Completed Work

● Execute the Work Safely and Efficiently

● This portion of the progress report consists of a narrative of work completed since the last update.

● Report Findings Accurately and Timely

Planned Work ● This portion consists of a narrative of the proposed work to be completed by the next update. The report provides a high-level review of activities and planned work for the next report interval. The report can be used to coordinate future work with other scopes of work. Percentage Completed ● Estimated levels of completion included in the progress report should directly correlate to the tracking lists. Utilizing spreadsheets makes calculating the percentage completed for each scope of work fairly easy, given that the individual level of effort with each percentage completed is provided. The overall tracking of the percentage completed is based on the project requirements, but coordinating them with the commissioning execution steps helps show the progression through the process. Support Needed / Schedule Risk ● This portion of the progress report brings attention to items that are impeding the commissioning agent in the execution of the process. Generally, support is needed from engineering or construction team members to resolve issues. This report should not be the only point of communication regarding these issues, but instead a place to remind the project team on a frequent basis of the need to resolve items in a timely manner.

CONCLUSION The purpose of this paper is to present one method to document, quantify, and communicate the progress of the commissioning process to project team members. Commissioning is the most critical phase of the quality process, as it is the last chance to find and address any issues prior to placing the project into operation. The concept and examples presented in this paper may not fully address the quality requirements of every project; it is the responsibility of the project team to review the quality requirements of its project, and establish the level of quality control that is required from the commissioning agent. The project team must also determine the value of utilizing the commissioning progress communication method.

Michael Lewark received B.S. and M.S. degrees in Electrical Engineering from the University of Maine at Orono, in 2003 and 2006, respectively. He has been a Commissioning Manager with SNC-Lavalin’s Transmission & Distribution project execution team since 2012. Michael currently supports the Iberdrola USA electrical capital delivery programs at Central Maine Power, New York State Electric and Gas, and Rochester Gas and Electric. Prior to joining SNC-Lavalin, Michael held various positions in the electrical design, construction, and commissioning fields. He is a member of the IEEE and the IEEE Power & Energy Society. Michael is also a registered Professional Engineer in the State of Maine.

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EXTENSION CORD SAFETY PowerTest 2015 Dennis K. Neitzel, CPE, CESCP, AVO Training Institute, Inc.

INTRODUCTION

TYPES AND SIZES OF EXTENSION CORDS

Extension cords have been in use as conveniences since the mid-1940s. They provide a convenient method of bringing temporary AC power to a device or power tool that is not located near a power outlet (receptacle). Extension cords are available in various lengths, gauges and service duties that fit most temporary power needs. The National Electrical Code (NEC), NFPA 70E, and the Occupational Safety and Health Administration (OSHA) requires the use of a Ground-Fault Circuit-Interrupter (GFCI) whenever connected to a temporary source of power such as a temporary pole, generator, or connected to the permanent wiring of a building. If used improperly, extension cords can become a fire and shock hazard, and may also cause equipment damage. A general rule of thumb is the more power needed to operate an appliance, device, or tool, the larger gauge (AWG) the extension cord should be. In addition, improper cord selection can lead to use of an undersized extension cord, resulting in an overheated cord and insufficient voltage delivered to the device. This condition can result in damage to the insulation and the outer jacket of the extension cord, resulting in exposed wires, which in turn can result in an electric shock and fire hazard.

Extension cords are generally available in two- or three-wire varieties. Two-wire extension cords are best used to operate one or two small appliances at a time, such as lamps, clock/radios, etc. Three-wire cords are best suited for outdoor electric power tools and equipment. The third wire in the cord is the equipment grounding conductor, or the “ground” wire. It should never be plugged into an ungrounded electrical outlet using an adapter. This practice would defeat the equipment ground and therefore remove that protection. Only grounded extension cords are to be used with power tools unless the tool is double-insulated. Extension cords used at construction sites, for example, must be specified for hard or extra hard usage by the National Electric Code. Approved cords are typically identified by the word “Outdoor” or the letter “W” on the cable jacket. Type “W” cords are suitable for use in wet (weather and water) locations and are sunlight resistant.

The U.S. Consumer Product Safety Commission (CPSC) estimates that each year, about 4,000 injuries associated with electric extension cords are treated in hospital emergency rooms. About half the injuries involve fractures, lacerations, contusions, or sprains from people tripping over extension cords. CPSC also estimates that about 3,300 residential fires originate in extension cords each year, killing 50 people and injuring about 270 others. The most frequent causes of such fires are short circuits, overloading, damage, and/or misuse of extension cords. A case history, as recorded in NFPA 70B, paragraph 4.4.3, describes a situation that occurred at 2:00am, January 16, 1967: McCormick Place, Chicago, Illinois, was completely destroyed by fire. Investigations revealed that the cause of the fire was the temporary power (extension cord) supplying power to one of the exhibit booths. Direct property and facility loss was estimated at $60 million and an additional $100 million in estimated economic loss to the Chicago area. Essentially this defective extension cord cost $160 million U.S. dollars. How important is extension cord safety?

There are a lot of extension cords available, and sometimes it’s hard to know which one to use. Too often people use the same extension cord for every purpose, which is not always the safest choice. The wires in the cord are required to carry the current of the load for the length of time required and if the load current is greater than the rating of the wires, it will overheat and possibly damage the wire insulation, cord outer jacket, plugs, and the electrical equipment that is plugged into it, and may cause a fire. Not only is the conductor size important, but the length is also a major factor. All electrical conductors have resistance; the larger the conductor the lower the resistance and the longer the wire the greater the resistance. With resistance comes voltage drop and with voltage drop comes increased current, which will cause overheating of the conductors. Extension cords must be of sufficient current-carrying capacity to power the device(s) it will be used with. Longer extension cords require increased conductor size to compensate for voltage drop. NEC Article 400 is titled Flexible Cords and Cables and provides valuable information on the types of extension cord outer jacket properties and applications in Table 400.4. The maximum allowable ampacity for various conductor sizes, insulation temperature ratings, and types of the extension cord outer jacket are found in Tables 400.5(A)(1) and 400.5(A)(2) based on an ambient temperature of 30ºC (86ºF). Figure 1 illustrates the recommended wire gauge for typical extension cord lengths and load current. Note: The American Wire Gauge (AWG) is the size of the individual conductors within the flexible cord. The smaller the AWG number the larger the conductor.

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Cord Length

Load Ampere (Current) Rating 0-2

2-5

5-7

7-10

10-12

12-15

25 feet

16 AWG

16 AWG

16 AWG

16 AWG

14 AWG

14 AWG

50 feet

16 AWG

16 AWG

16 AWG

14 AWG

14 AWG

12 AWG

100 feet

16 AWG

16 AWG

14 AWG

12 AWG

12 AWG

150 feet

16 AWG

14 AWG

12 AWG

12 AWG

200 feet

14 AWG

14 AWG

12 AWG

10 AWG

Fig. 1: Recommended wire gauge for typical extension cord lengths and load current The cords recommended here are based on the minimum thickness cords permitted for each application by the NEC. These are generally used for cord- and plug-connected power tools such as drills, saws, grinders, etc., as well as lawn and garden power tools such as trimmers, edgers, blowers, electric lawn mowers, etc. When selecting an extension cord for any of these applications, the current (amps or amperes) of the tool must be known, as well as the distance from the receptacle where the cord will be plugged in to where the tool will be used, which will establish the length of the cord needed. Always use a ground-fault circuit-interrupter (GFCI) for these applications. Extension cords are not suitable for appliances such as refrigerators, freezers, microwaves, etc. If an extension cord must be used with an appliance, it must be approved (listed and labeled by UL or other approving agency) for appliance use. The best practice with appliances is to place the appliance close enough to a receptacle so that an extension cord will not be needed. An appliance extension cord is generally a shorter and thicker, larger gauge (lower AWG number) cord. Dangerous situations can arise when substituting a longer or thinner cord with a lower gauge (higher AWG number), cord than the one recommended by the listing and labeling. Caution: Space heaters were not discussed here because it is not safe to use them with an extension cord. Space heaters are portable; move them closer to an outlet. A space heater draws a lot of current; 1,500w = 13 amperes; 2,000w = 17 amperes. Most people, especially home owners and office workers, use light-duty extension cords that are 18 AWG (7 to 10 amperes depending on the insulation) with a two-prong plug. Sometimes they will plug them into a plug strip or use a 16 AWG (10 to 13 amperes depending on the insulation) extension cord. As can be seen, both of these cords would be much too small for the application and would overheat and could cause a fire, it has happened too many times to ignore this issue. If the space heater were to run for 3 hours or more it would be considered a continuous load and the NEC requires the circuit to be rated at 125% of the full load current, therefore the 13 amperes becomes 16 amperes and the 17 amperes becomes 21 amperes for rating the conductor size. Questions are often asked concerning the size of extension cords that are needed for various applications. Below are several applications where an extension cord will, or may, be used, along with

the recommended rating of the extension cord. These are only typical examples and do not represent all applications. Always verify the ampere rating of the power tool or equipment and use an extension cord rated for the application. ● Leaf blower, trimmer, or edger. These tools will generally draw about 12 amperes or less. Use a 16 AWG light-duty cord for up to 50 feet from the receptacle; increase to a 14 AWG medium-duty cord for up to 100 feet; and a 12 AWG for up to 200 feet from the receptacle. Also, make sure the extension cord is rated for outdoor use. Always use a GFCI for this application. ● Circular saw or power drill. It is best to use a 12 AWG heavy-duty outdoor cord, which will be sufficient for up to 100 feet from the receptacle. Always use a GFCI for this application. ● Outdoor or shop vacuum cleaner. A three-prong, 12 AWG cord works best. Always use a GFCI for this application. ● Portable air compressor. A 12 AWG heavy-duty extension cord will work for putting air in a car tire up to 100 feet away from an outlet, or a 10 AWG extra-heavy-duty extension cord if a spray or nail gun is going to be used. Always use a GFCI for this application. ● Workshop. There are never enough outlets in a workshop and running multiple extension cords can be a hassle and a tripping hazard. Go with a 14 AWG cord, which will power most tools, and look for a model with multiple outlets so you can plug in more than one tool. Always use a GFCI for this application. ● Table lamp or clock/radio. It is generally safe to use an 18 AWG, two-prong, light-duty extension cord, which can handle up to 7 amperes for up to 25 feet; use of a 10 foot cord would be better. These are perfect for running to a nightstand from the outlet behind the bed or table next to a sofa. NEVER hide the cord by putting a rug over it, running it under the carpet, or tucking it in at the baseboard; these are extreme fire hazards. ● Holiday lights. Use a 16 AWG cord for 25 feet or less, or 14 AWG for more than 25 feet. Get the length you need, DO NOT daisy-chain two extension cords together to get the length you need; get a longer cord. Always confirm that that the extension cord is rated for outdoor use. DO NOT run extension cords through windows or doors to plug in the holiday lights; OSHA and the NEC forbid this practice. Always use a GFCI for this application. ● Countertop small appliances. Heat-producing appliances like toasters, irons, toaster ovens, and coffee pots draw at least 10-12 amps of current, which is beyond the limits of most indoor extension cords, so don’t use them. A kitchen layout is required by the NEC to permit the small, portable appliances to live near an outlet, far from the sink. The NEC requires

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Safety Vol. 2 at least two, 20 ampere small-appliance branch circuits in a kitchen. All receptacles that serve the countertop are required to be GFCI protected. ● Hair Dryers. Forget about using an extension cord with these. You’ll have to let your hair air dry if you can’t plug in the hair dryer directly to an outlet. Hair dryers typically draw 15 amps, which can cause an extension cord to get hot enough to start a fire. Always use a GFCI for this application. ● Indoor vacuum cleaner. If an extension cord is needed, use an off-the-shelf 16-AWG cord, or buy a specialty one designed for use with a vacuum cleaner. It is best not to use an extension cord with a vacuum cleaner. DO NOT run the vacuum cleaner cord through open doors to plug it in; OSHA and the NEC forbid this practice unless the door can be blocked to prevent it from closing against the cord. The NEC requirements for conductor amperage is used to determine the gauge (AWG) of the wire that you want to use, and remember resistance determines the length. All wire has resistance which will lower the voltage over the distance, so if the run is long, step up the gauge. Examples of amperage limits, per the NEC, are... ● 16 AWG = 10 amperes ● 14 AWG = 15 amperes ● 12 AWG = 20 amperes ● 10 AWG = 30 amperes (Chances of finding a 10 AWG extension cord are slim, however, many home improvement and hardware stores may carry a limited number of lengths in stock, but it will be REALLY expensive) Another question that is generally asked is “Why would I need a 12 AWG cord if I’m plugging into a 15 ampere receptacle?” This is due to voltage drop, based on the resistance of the wire. Most tools or equipment that will be plugged into an extension cord need full voltage to run properly (the tool or equipment may be damaged by overheating if it doesn’t receive full voltage). When using equipment that is going to have a load current close to the max capacity of the cord then full voltage will not be available over a longer distance, therefore the need to step up in size must be considered. A good rule is step up the cord size for every 25 feet if the load is at maximum capacity or every 50 feet if the load is around 75% capacity. The next question that is asked is “Why can’t I plug multiple cords together (daisy chain)?” There are a couple of reasons for that: 1) each connector (plug) adds its own resistance to the circuit, so the cords can end up with more voltage drop at the end of the line than was expected; and 2) if there is going to be a failure in the circuit it is typically going to be at a connection point (plug), so by adding more connections (plugs) the risk of failure increases. Another factor in this is the fact that connections (plugs) are also the most worn part on the extension cord set and therefore the most likely to fail.

GROUND-FAULT CIRCUIT INTERRUPTER (GFCI) The requirements for using a GFCI have been mentioned several times in this paper. There are specific NEC and OSHA requirements for installing permanent GFCIs in various locations in dwelling and non-dwelling locations. It is not the intent of this paper to address those requirements. However, the requirements for GFCIs that have a direct impact on the safe use of extension cords, as well as cord- and plug-connected hand held tools and other equipment, will be addressed. OSHA 29 CFR 1910.304(b)(3), NFPA 70E Section 110.4(B), and NEC Section 590.6 require GFCI protection for all “temporary wiring installations that are used during maintenance, remodeling, or repair of buildings, structures, or equipment or during similar construction-like activities.” These requirements apply to “all 125volt, single-phase, 15-, 20-, and 30-ampere receptacle outlets that are not part of the permanent wiring of the building or structure and that are in use by personnel shall have ground-fault circuit-interrupter protection for personnel.” There are two notes that further clarifies these requirements: ● 1) “A cord connector on an extension cord set is considered to be a receptacle outlet if the cord set is used for temporary electric power.” ● 2) “Cord sets and devices incorporating the required groundfault circuit-interrupter that are connected to the receptacle closest to the source of power are acceptable forms of protection.” NEC 590.6 also states that the GFCI requirement applies to power derived from the electric utility or from on-site generators. The NEC requires GFCIs to be used with: all 125-volt, single-phase, 15-, 20, and 30-ampere receptacle outlets not part of permanent wiring; all 125-volt, single-phase, 15-, 20, and 30-ampere receptacle outlets existing or installed as permanent; and all 125-volt and 125/250-volt, single-phase, 15-, 20-, and 30-ampere receptacles on 15-kW or less portable generators. The use of GFCIs in all potentially wet or damp locations, indoor and outdoor, when using portable cord- and plug-connected tools and equipment, as well as the use of extension cords, can save lives. A GFCI should always be used for both grounded and double-insulated hand-held power tools and equipment, along with extension cords and plug strips. When a person becomes the path for current, due to moisture or damaged equipment, the GFCI senses the difference in current (5+1 mA) from the energized (hot) conductor and the neutral conductor and it opens the circuit to prevent injury or death.

INSPECTION GUIDELINES Only use extension cords that are listed/labeled by Underwriter Laboratories (UL) or another nationally recognized testing laboratory.

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OSHA 1910.334, along with NFPA 70E Section 110.4(B) provides inspection requirements for portable cord- and plug-connected electric equipment and flexible cord sets (extension cords). The following is quoted from OSHA: 1910.334 Use of equipment. ● Portable electric equipment. This paragraph applies to the use of cord and plug connected equipment, including flexible cord sets (extension cords) ○ Handling. Portable equipment shall be handled in a manner which will not cause damage. Flexible electric cords connected to equipment may not be used for raising or lowering the equipment. Flexible cords may not be fastened with staples or otherwise hung in such a fashion as could damage the outer jacket or insulation. ○ Visual inspection. – Portable cord and plug connected equipment and flexible cord sets (extension cords) shall be visually inspected before use on any shift for external defects (such as loose parts, deformed and missing pins, or damage to outer jacket or insulation) and for evidence of possible internal damage (such as pinched or crushed outer jacket). Cord and plug connected equipment and flexible cord sets (extension cords) which remain connected once they are put in place and are not exposed to damage need not be visually inspected until they are relocated. – If there is a defect or evidence of damage that might expose an employee to injury, the defective or damaged item shall be removed from service, and no employee may use it until repairs and tests necessary to render the equipment safe have been made. – When an attachment plug is to be connected to a receptacle (including an on a cord set), the relationship of the plug and receptacle contacts shall first be checked to ensure that they are of proper mating configurations. ○ Grounding type equipment. – A flexible cord used with grounding type equipment shall contain an equipment grounding conductor. – Attachment plugs and receptacles may not be connected or altered in a manner which would prevent proper continuity of the equipment grounding conductor at the point where plugs are attached to receptacles. Additionally, these devices may not be altered to allow the grounding pole of a plug to be inserted into slots intended for connection to the currentcarrying conductors. – Adapters which interrupt the continuity of the equipment grounding connection may not be used.

○ Conductive work locations. Portable electric equipment and flexible cords used in highly conductive work locations (such as those inundated with water or other conductive liquids), or in job locations where employees are likely to contact water or conductive liquids, shall be approved for those locations. ○ Connecting attachment plugs. – Employees’ hands may not be wet when plugging and unplugging flexible cords and cord and plug connected equipment, if energized equipment is involved. – Energized plug and receptacle connections may be handled only with insulating protective equipment if the condition of the connection could provide a conducting path to the employee’s hand (if, for example, a cord connector is wet from being immersed in water). – Locking type connectors shall be properly secured after connection. Inspection of portable electric equipment and extension cords is vital to the safety of personnel using them. All personnel who use cord- and plug-connected equipment and extension cords are required to receive training on this inspection process and the identification of potential hazards. This training includes qualified electrical workers, as well as all unqualified or non-electrical personnel. OSHA training requirements can be found in 1910.332(a) which states that the training requirements apply to “employees who face a risk of electric shock” which includes qualified and unqualified persons as identified in Table S-4 of the standard. It also states that “other employees who also may reasonably be expected to face comparable risk of injury due to electric shock or other electrical hazards must also be trained.” The use of portable cord- and plug-connected tools and equipment, as well as extension cords, present a “risk of injury due to electric shock” therefore training must be provided to all potentially exposed personnel.

NINE THINGS TO NEVER DO WITH AN EXTENSION CORD Extension cords are a convenient way to bring power to electrical devices. Used without proper caution, however, they can become a fire hazard and pose a risk to your personal safety. Follow these nine tips to help keep your business or home safe: ● Don’t remove the grounding pin to fit a two-prong outlet. ● Don’t power multiple devices with one cord. ● Don’t use indoor extension cords outdoors. ● Don’t plug multiple extension cords together. ● Don’t run extension cords under rugs or furniture. ● Don’t tape extension cords to floors. ● Don’t attach cords to surfaces with staples or nails.

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Safety Vol. 2 ● Don’t use if kinked or while looped or coiled. This could potentially be a fire hazard. ● Don’t use extension cords that feel hot to the touch. And remember that extension cords are intended as temporary wiring solutions. If you find you’re using them on a permanent basis, consider updating your electrical system to include additional outlets.

SELECTING EXTENSION CORDS There should be a certain amount of thought and consideration when selecting an extension cord. This paper has focused on many different considerations. Below is a list of seven very important considerations that should be used when selecting an extension cord: ● Purchase only cords that have been approved by an independent testing laboratory, such as Underwriters Laboratories (UL) or the Canadian Standards Association (CSA). ● For outdoor projects, use only extension cords marked for outdoor use. ● Read the instructions (if available) for information about the cord’s correct use and the amount of power it draws when running. ● Select cords that are rated to handle the wattage or amperage of the devices with which they’ll be used. A cord’s gauge (AWG) indicates its size: The smaller the number, the larger the wire and the more electrical current the cord can safely handle. ● Consider the length you’ll need. Longer cords can’t handle as much current as shorter cords of the same gauge. ● Choose cords with polarized or three-prong plugs. ● For use with larger appliances, thick, round, low-gauge (large size) extension cords are best. For smaller appliances and electronics, the thin or flat cords can be used.

CARING FOR EXTENSION CORDS Extension cords, and for that matter all portable electrical equipment, must be properly cared for in order to remain safe to use. ● Always store extension cords indoors, away from potential physical damage or moisture. ● Unplug extension cords when they’re not in use. ● Make sure that extension cords are used and stored free of kinks, twists or knots. ● Throw away damaged cords, DO NOT tape them as a repair; it is not. ● Pull the plug—not the cord—when disconnecting from the outlet.

ADDITIONAL CONSIDERATIONS There are a number of other consideration that must be addressed as they relate to extension cord safety. ● Cords should not be repaired with electrical tape or any other type of tape. This may conceal damage the cord has received and it does not provide the integrity of the original jacket. ● Never use extension cords as a replacement for rope or a handline. It is not designed for securing or hauling equipment and/ or materials. ● Do not use extension cords that are frayed, cut, or damaged, especially if the inner conductors show, or that have outer sheaths which have pulled loose from their molded plugs exposing the inner conductors. In particular, do not use a cord that has a bare conductor exposed. In addition do not use extension cords missing the third post (ground post). ● Extension cords should not run through doors, ceilings, windows, holes in walls, or through hinged door openings in enclosures to prevent “pinch” damage to the cord. If it is absolutely necessary to run an extension cord through a doorway or open window for short-term use, the cord must be protected from damage should the door or window slam shut; it must be removed immediately when no longer in use; and must not be a trip hazard. ● Avoid running vehicles or equipment over uncovered extension cords. This can lead to splitting or internal damage to the extension cord. ● When running an extension cord along the ground it is best to use a protective covering or duct of some kind or tape to help prevent creating a trip hazard. ● Extension cords should not be used in place of permanent facility wiring. Cords are not allowed to be attached to building surfaces, structural members or permanently concealed in walls, ceilings, under floors or carpeting. ● Check the plug and the body of the extension cord while the cord is in use. Noticeable warming of these plastic parts is expected when cords are being used at their maximum rating, however, if the cord feels hot or if there is a softening of the plastic, this is a sign of a problem and the cord should be de-energized and discarded.

SUMMARY Extension cords provide a convenient method of bringing temporary AC power to a device or power tool that is not located near a power outlet. Extension cords are available in various lengths, gauges (AWG) and service duties that fit most temporary power needs. If used improperly extension cords can become a fire and shock hazard, and may also cause equipment damage. As a general rule of thumb, the more power needed to operate an appliance, equipment, or tool, the larger gauge (AWG) the extension cord

66 should be. In addition, improper cord selection can lead to use of an undersized extension cord resulting in an overheated cord and insufficient voltage delivered to the equipment. This condition can result in damage to the insulation and the outer jacket of the extension cord, resulting in exposed wires, which in turn can result in an electric shock and fire hazard. Extension Cord safety is no accident. Be safe. Take note of the topics and recommendations discussed in this paper. Every person is encouraged to put them into practice – doing so helps ensure personnel safety.

BIBLIOGRAPHY U.S. Consumer Product Safety Commission National Fire Protection Association, NFPA 70, National Electrical Code, 2014 Edition National Fire Protection Association, NFPA 70E, Standard for Electrical Safety in the Workplace, 2015 Edition National Fire Protection Association, NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, 2013 Edition Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910, Subpart S, “Electrical Standards”, Friday, February 14, 2007 Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.331-.335, Electrical Safety-Related Work Practices, August 6, 1990 Dennis K. Neitzel, CPE, Director Emeritus of AVO Training Institute, Inc., Dallas, Texas, has over 45 years experience in Electrical Utility, Industrial facility, and shipyard/shipboard electrical equipment and systems maintenance and testing experience, with an extensive background in electrical safety and power systems analysis. He is an active member of IEEE, ASSE, AFE, IAEI, and NFPA. He is a Certified Plant Engineer (CPE) and a Certified Electrical Inspector-General. Mr. Neitzel earned his Bachelor’s degree in Electrical Engineering Management and his Master’s degree in Electrical Engineering Applied Sciences. He is a Principle Committee Member and Special Expert for the NFPA 70E, Standard for Electrical Safety in the Workplace; member of the Defense Safety Oversight Council, Electrical Safety Working Group – DoD Electrical Safety Special Interest Initiative; Working Group Chairman of IEEE 3007.1-2010 Recommended Practice for the Operation and Management of Industrial and Commercial Power Systems, 3007.2-2010 Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, & 3007.3-2012 Recommended Practice for Electrical Safety of Industrial and Commercial Power Systems; Working Group Chairman of IEEE P45.5 Recommended Practice for Electrical Installations on Shipboard - Safety Considerations; and co-author of the

Safety Vol. 2 Electrical Safety Handbook, McGraw-Hill Publishers. Mr. Neitzel has also authored, published, and presented numerous technical papers and magazine articles on electrical safety, maintenance, and training. For more information, contact Mr. Neitzel by e-mail at [email protected].

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SIGNIFICANT CHANGES TO OSHA’S 1910.269 AND 1926 REGULATIONS PowerTest 2015 James R. White, Shermco Industries, Inc.

ABSTRACT OSHA has made major changes to these regulations, both of which concern work on or near high-voltage electrical power systems. Some of these changes were to be implemented on the date the Final Rule was issued, others are to be implemented in 2015. This paper covers the major changes to these regulations, when they are due to be implemented and how they differ from current regulations.

NEED FOR REVISION Borrowing from the summary of the Final Rule, “OSHA last issued rules for the construction of transmission and distribution installations in 1972. Those provisions are now out of date and inconsistent with the more recently promulgated general industry standard covering the operation and maintenance of electric power generation, transmission, and distribution lines and equipment. OSHA is revising the construction standard to make it more consistent with the general industry standard and is making some revisions to both the construction and general industry requirements.” 1910.269 was adopted in 1994 and covered electric power generation, transmission and distribution. During the 22 years between the two standards, much has changed. Mr. David Wallis recently retired from OSHA. Mr. Wallis was OSHA’s Director, Office of Engineering Safety and was OSHA’s principle representative to the NFPA 70E Committee. One of Mr. Wallis’ goals before he retired from OSHA was to see the revisions to 1910.269 and 1926 completed and put into service. As stated above, the two standards were inconsistent with each other and Mr. Wallis had spent several years working the changes through the regulatory process. OSHA estimates the new requirements will prevent 20 fatalities and 118 serious injuries each year. In addition, OSHA estimates that $62,000 will be saved by employers for each injury avoided and $8.7 million dollars for each fatality, for a total savings of $129.7 million dollars.

OVERVIEW OF THE 1910.269[1] AND 1926 SUBPART V[2] CHANGES The 1910.269 regulation applies to utilities and “utility-like installations at industrial facilities”. This generally refers to industrial outdoor substations, but can also apply to metal-clad switch-

gear set up as a distribution system. The 1926 regulation applies to the construction of electrical power systems, including overhead lines. Changes made to 1910.269 were also included in the 1926 regulation to provide the consistency needed between the two regulations.

Protecting Employees from Electric Arcs [1910.269(l) (8) and 1926.960(g)] One of the most important changes to the two regulations was the requirement to protect the employee from the effects of an electric arc and the process to determine what arc-rated clothing and PPE would be required. The employer is to assess the workplace to identify those employees who may be exposed to electric arcs, make a reasonable estimate of the incident energy exposure and ensure that the employees who are exposed to the hazard have arc-rated clothing and PPE that is adequate to protect them. In the past OSHA relied on the National Electrical Safety Code Rule 410 to provide the necessary requirements for arc-rated PPE. There was some confusion in the workplace on how to properly estimate incident energy for overhead lines and rule 410 had issues. To ensure adequate protection for employees, OSHA jumped in and set requirements. The new arc flash requirements are set to become effective in three stages: ● Employers must have assessed the workplace for arc flash hazards no later than when the Final Rule was implemented (July 10, 2014). ● Employers must ensure employees do not wear clothing that could melt into the skin by the time the Final Rule was implemented. ● The employer must make reasonable estimates of the incident energy their employees would be exposed to by January 1, 2015. ● The employer must provide employees exposed to the arc flash hazard adequate arc-rated clothing and PPE no later than April 1, 2015. The first two requirements were existing requirements from the previous 1910.269 regulation, but are new to 1926. The third requirement presented some issues, due to the various methods that could be used to estimate incident energy. To assist in sorting through these methods, OSHA provided Annex E, Table 3, shown

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as Table 1. OSHA reviewed four methods of determining incident energy and rated them as to their appropriate application. Generally, they fell into three major groupings; 600 V and less, 601 V to 15 kV and More than 15 kV. Additionally, the three groupings were further broken down into single-phase (1Φ), three-phase open-air (3Φa) and three-phase in an enclosure (3Φb).

about the energy exposure distribution throughout the system and provided the estimates represent the maximum employee exposure for those areas. For example, the employer could estimate the heat energy just outside a substation feeding a radial distribution system and use that estimate for all jobs performed on that radial system.”

OSHA found the IEEE 1584 method acceptable for all arc calculations up to 15 kV. For arcs above 15 kV, though OSHA found only one acceptable calculation method, which is a commercial product developed originally by Ontario Hydro, circa 1985. The rights have since been sold to another company which markets it. Actually, methods such as 1584 were only intended for specific circumstances and not for all uses, so it is not entirely surprising they are narrow in their application. The Ralph Lee equations were intended for open-air faults and were the only method available for many years. The Doughty, Neal and Floyd equations were intended for 600 V or less equipment. IEEE 1584 was designed specifically for three-phase arc-in-a-box equipment rated up to 15 kV. That leaves ArcPro® for voltages above 15 kV, which needs to have a multiplier when used for three-phase arcs-in-a-box.

In addition to the above requirements, as of April 1, 2015 the outermost garment of clothing must be arc-rated if the nominal voltage is above 600 V, if an arc could ignite a worker’s clothing, if molten metal could ignite a worker’s clothing or if the incident energy is greater than 2.0 cal/cm2. If the estimated incident energy exceeds 2.0 cal/cm2, arc-rated clothing equal to or greater than then expected incident energy must be worn. A worker’s hands must be protected from the hazard of electric arc flash, and if a worker is wearing heavy-duty leather work shoes, additional protection for the feet is not required. The requirements for face protection are somewhat confusing, as they seem to be less than adequate at first glance. A hard hat is considered adequate protection [for the back of the head] for exposures up to 9 cal/cm2 for single-phase arcs in open air, or 5 cal/cm2 for other exposures. 1910.269(l)(8)(C) does not specifically state it this way (wording in the brackets was added by the author), but 1910.269(l)(8)(D) does state that for exposures less than 13 cal/ cm2 an arc-rated face shield can be used (minimum arc rating of 8 cal/cm2) for single-phase exposures and 9 cal/cm2 for other exposures. When taken together, the intent seems clear. For exposures involving single-phase open-air arcs the head and face protection can be 4 cal/cm2 less than the estimated incident energy. These requirements are also effective April 1, 2015. Minimum Approach Distances (MAD) [1910.269(l)(3) and 1926.960(c)(1)

Table 1: Selecting a Reasonable Incident Energy Calculation Method. Table 3 From Annex E, 1910.269 Final Rule In order to use the software effectively, a reasonable estimate must be made of the distance from the arc and a reasonable estimate of the arc gap. Tables 4 and 5 in Annex E provide estimates, if that information is not known. In order to make the new arc flash estimation requirements less onerous, OSHA added Note 2 to paragraph (l)(8)(ii), “This paragraph does not require the employer to estimate the incident heat energy exposure for every job task performed by each employee. The employer may make broad estimates that cover multiple system areas provided the employer uses reasonable assumptions

The second biggest change, in my opinion, is the new requirements for the minimum approach distances (MAD). Annex B of the Final Rule provides guidance on determining minimum approach distances. Up to 72.5 kV, Table R-6 can be used, shown as Table 2. This is the lazy man’s method and is appropriately conservative. More accurate minimum approach distances can be calculated using the formulae in Table R-3 (under 72.5 kV), shown as Table 3a. This is fairly simple up to the 5 kV level, but above 5 kV to 72.5 kV Table 2 (electrical component), an inadvertent movement factor (0.61m) and Table R-5 (altitude correction factor) must be used. Above 72.5 kV things become a bit more involved. Table R-3 (above 72.5 kV) is used, shown as Table 3b. At these voltages the maximum anticipated per-unit transient overvoltage must be determined through an engineering analysis or, as an alternative Table R-9, (shown as Table 4 below) can be used, as well as a calculated saturation factor. Tables R-7 (AC) or R-8 (DC), (Table R-7 is shown as Table 5) can also be used, instead of calculating the minimum approach distances. These provisions are effective no later than April 1, 2015.

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Table 4 (Table R-9): Assumed Maximum Per-Unit Transient Overvoltage, From 1910.269/1926 Subpart V Final Rule

Table 2 (Table R-6): Minimum Approach Distances Up to 72.5 kV, From 1910.269/1926 Subpart V Final Rule

Table 5 (Table R-7): Minimum Approach Distances Greater than 72.5 kV, From 1910.269/1926 Subpart V Final Rule Although many people do not take the time to read through the annexes for the regulations, it would be in their best interests to do so now. The annexes provide information required to properly interpret and implement the new regulatory requirements.

Fall Protection [1910.269(g)(2) and 1926.954]

Table 3a (Table R-3): Calculated Minimum Approach Distances Up to 72.5 kV, From 1910.269/1926 Subpart V Final Rule

Table 3b (Table R-3): Minimum Approach Distances Above 72.5 kV, From 1910.269/1926 Subpart V Final Rule

If a worker is exposed to the hazard of flames or electric arcs, the fall arrest equipment he or she uses must be capable of passing a drop test as specified in .269(g)(2)(iii)(L) after exposure to an arc equivalent to 40 cal/cm2. Body belts and positioning straps and their associated hardware, such as D-rings and snap hooks have a host of new requirements. Positioning straps have to pass a dielectric test, a tension test and a flammability test. Table 6 shows the requirements of the flammability test.

Table 6 (Table 2): Flammability Test, From 1910.269/1926 Subpart V Final Rule

70 D-rings and snap hooks must be made of drop-forged steel, pressed steel or equivalent. They must have a corrosion-resistant finish and be free of sharp edges. All hardware must withstand a tension test with specific requirements for buckles, D-rings and snap hooks. Fall arrest or restraint systems are to be used in aerial lifts and anytime a worker is 4 feet or more above ground on poles, towers or similar structures. If railings or other types of fall protection are provided, fall arrest equipment is not required. If the employer can demonstrate that using fall arrest equipment is infeasible or creates a greater or additional hazard, it is not required. However, Note 2 to paragraphs (g)(2)(iv)(C)(2) and (g)(2)(iv)(C)(3)states, “Until the employer ensures that employees are proficient in climbing and the use of fall protection under paragraph (a)(2)(viii) of this section, the employees are not considered “qualified employees” for the purposes of paragraphs (g)(2)(iv)(C)(2) and (g)(2)(iv)(C)(3) of this section. These paragraphs require unqualified employees (including trainees) to use fall protection any time they are more than 1.2 meters (4 feet) above the ground.” These provisions are effective as of April 1, 2015. As of April 1, 2015 work positioning equipment must be rigged so a worker can fall no more than 2 feet and has to be capable of supporting twice the potential impact load or 3,000 pound-force, whichever is greater. There are other requirements for fall arrest and positioning equipment in 1910.269(g) that are not covered in this paper, so the reader should review that section to complete their understanding of it.

Training [1910.269(a)(2) and 1926.950(b)] 1910.269(a) has several revisions, some of which could affect an employer’s training plan. 1910.269(2)(i) is now in three parts, 1910.269(2)(i)(A), (B) and (C). (A) and (B) are unchanged from the previous regulation, but 1910.269(2)(i)(C) has been changed to add a requirement that “Each qualified employee shall also be trained and competent in:”. Adding the word “competent” would now require a demonstration of skills and knowledge for the five requirements: ● The skills and techniques necessary to distinguish exposed live parts from other parts of electric equipment, ● The skills and techniques necessary to determine the nominal voltage of exposed live parts, ● The minimum approach distances specified in this section corresponding to the voltages to which the qualified employee will be exposed and the skills and techniques necessary to maintain those distances, ● The proper use of the special precautionary techniques, personal protective equipment, insulating and shielding materials, and insulated tools for working on or near exposed energized parts of electric equipment, and

Safety Vol. 2 ● The recognition of electrical hazards to which the employee may be exposed and the skills and techniques necessary to control or avoid these hazards. (E) is a new requirement and was added to clarify that the skills and knowledge to recognize electrical hazards and the methods to avoid injury or death are a required part of a qualified employee’s training. Initial training for qualified workers is required to have a hands-on portion that documents the demonstration of the above skills and knowledge. This was covered in a Letter of Interpretation dated 11/22/1994, but was not widely known, especially within the industrial sectors of the industry. Note 2 to paragraph (a)(2)(viii) was added to clarify when previous training can be considered, “For an employee with previous training, an employer may determine that that employee has demonstrated the proficiency required by this paragraph using the following process:” ● Confirm that the employee has the training required by paragraph (a)(2) of this section, ● Use an examination or interview to make an initial determination that the employee understands the relevant safety-related work practices before he or she performs any work covered by this section, and ● Supervise the employee closely until that employee has demonstrated proficiency as required by this paragraph.” 1910.269(a)(2)(iii) contains new training requirements for tree trimmers who are not qualified workers. As written, tree trimmers will have to have virtually the same training as qualified workers and must also demonstrate competency in those same skills and knowledge.

Information Transfer (Host-Contractor) [1910.269(a) (3) and 1926.950(c)] This is a new section in 1910.269(a)(3) titled “Information Transfer” and closely resembles the requirements of NFPA 70E, Article 110. 1910.269(3) was effective on issuance of the Final Rule. The purpose is to ensure communication between the company hiring the contractor (Host) and the contractor to prevent unsafe work conditions from affecting the safety of the workers. Before work is begun, the Host employer must inform the contractor of the following: ● The following characteristics of the Host employer’s installation when they are related to the safety of the work to be performed: ○ The nominal voltages of lines and equipment ○ The maximum switching-transient voltages ○ The presence of hazardous induced voltages ○ The presence of protective grounds and equipment grounding conductors

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Safety Vol. 2 ○ The location of circuits and equipment, including electric supply, communication lines and fire-protective signaling circuits ● The following conditions when they are related to the safety of the work and are known to the Host employer ○ The condition of protective grounds and equipment grounding conductors ○ The condition of poles ○ The environmental conditions relating to safety ● Information about the design and operation of the Host employer’s installation that the contract employer needs to know in order to make the assessments required by 1910.269 ● Other information about the design and operation of the Host employer’s installation that is:

● Table numbers have been changed [Table I-1 was not used previously]. There are no changes to the tables. ○ Table I-2 is now Table I-1 ○ Table I-3 is now Table I-2 ○ Table I-4 is now Table I-3 ○ Table I-5 is now Table I-4 ○ Table I-6 is now Table I-5 ● In-service dielectric testing is to be in accordance with Table I-4, shown as Table 7. Gloves being given a dielectric test are to adhere to the requirements of Table I-3, Glove Tests – Water Level. For companies performing their glove testing in-house, these are the guidelines to use. Table 8 shows Table I-3.

○ Known by the Host employer ○ Requested by the contract employer ○ Related to the protection of the contracted employer’s employees OSHA adds the following note to paragraph (a)(3)(i)(B), “For the purposes of this paragraph, the host employer need only provide information to contract employers that the host employer can obtain from its existing records through the exercise of reasonable diligence. This paragraph does not require the host employer to make inspections of worksite conditions to obtain this information.” This note makes clear that extraordinary efforts are not required by the Host to discover any and all dangerous conditions. Before work is begun, the contracted employer has to inform the Host employer of any unique hazardous operations caused by the contractor’s work, as well as any unanticipated hazardous conditions found during the course of the work that the Host employer did not mention. This information has to be conveyed to the Host within 2 working days after the hazard has been discovered. The Host and contractor are to determine whose work rules they will follow to avoid potentially dangerous work situations. This is especially important for safe and proper lockout/tagout of equipment.

Table 7 (Table I-4): Rubber Insulating Equipment, Voltage Requirements, From 1910.137

Changes to 1910.137[3] and 1926.97[4] 1910.137 covers rubber insulating personal protective equipment, such as rubber insulating gloves, sleeves and blankets. Below is a brief listing of the changes: ● Class 00 gloves are now included in the regulation ● Ozone-resistant (non-rubber) insulating equipment is now included [1910.137(a)(2)(iv)]. ○ Ozone-resistant insulating equipment must be able to pass an ozone test with no visible signs of deterioration.

Table 8 (Table I-3): Glove Test – Water Level, From 1910.137

72 SUMMARY The recent changes to OSHA’s 1910.269 and 1926 Subpart V regulations eliminates much of the differences between them. The regulations are now consistent, more comprehensive and should provide a level of safety that previously did not exist. Although the 1926 Subpart V regulation applies to the construction of overhead lines and other utility equipment, many of the safety issues are the same as those posed by workers who repair and maintain that same equipment. These revisions were long overdue, in my opinion. The changes to 1910.137 and 1926.97 adds consistency between the two regulations, strengthening both. OSHA’s estimates of the number of lives or the money that will be saved are open to debate. What cannot be debated is that this revision is long overdue and worth the wait.

REFERENCES 1. 1910.269, Final Rule, Occupational Safety and Health Administration, April 11, 2014 2. Subpart V, Final Rule, Occupational Safety and Health Administration, April 11, 2014 3. Electrical Protective Devices, Occupational Safety and Health Administration, July 10, 2014 James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

Safety Vol. 2

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Safety Vol. 2

THE IMPACT OF ELECTRICAL SAFETY TO MAINTENANCE: NFPA 70B AND CSA Z463 PowerTest 2015 James R. White, Shermco Industries, Inc. and Jarret Solberg, Shermco Industries, Inc.

WHY PERFORM MAINTENANCE? There are many reasons to perform maintenance on electrical power systems and equipment: ● ● ● ● ● ● ●

Warranty issues Manufacturer’s recommendations Preventing unscheduled downtime Preventing equipment damage Insurance requirements Standard’s recommendations and requirements Personnel safety

Warranty Issues The concept of warranty issues is pretty easy to understand. Almost everyone has bought a new car or truck (or one that is under the manufacturer’s warranty) sometime in their life. The manufacturer of such a vehicle requires certain maintenance be performed at specified intervals. If such maintenance is not performed and the vehicle has no issues all is well. However, if the vehicle requires repair and is taken to a dealer for warranty service, that neglected maintenance could become an issue. The same is true for new electrical power system equipment. If warranty work is required and the required maintenance has not been performed the costs for those repairs could be borne by the equipment owner, not the manufacturer. The good news here is that manufacturer’s warranties are usually so short that the probability of this happening is small. I guess that’s good news.

Manufacturer’s Recommendations Manufacturers require some minimum levels of maintenance to be performed on their equipment in order for it to perform to their specifications. The problem is, their requirements are often very vague and not specific about time frames and needed maintenance. It’s almost as if they don’t want a competing manufacturer to be able to state their equipment requires less maintenance than theirs. The following is fairly typical of factory recommendations: “In general, the circuit breaker requires only moderate lubrication at regular intervals. The use of a special lubricant is required in a few places, and must be applied with care. Only small quantities are needed. All excess must be removed with a clean cloth to prevent any accumulation of dust or dirt. Avoid getting any lubricant on insulation or other electrical parts. Care must be taken to prevent any of the molybdenum lubricant from reaching any current carrying contact surface.

Under normal operating conditions, refer to Table 5 for the recommended lubrication frequency for DSII circuit breakers by frame size. Special conditions, such as contaminated environments, high temperatures and excessive humidity, might dictate that a different schedule be considered.

NOTE: Any circuit breaker that has been stored should be operated a minimum of five times before it is placed in service. NOTE: All parts of the levering mechanism have sufficient lubrication, and should not require any further attention (see Figure 52 on page 59).” All that is fine and good, but very few companies actually track the number of operations on low-voltage circuit breakers. Such information is almost useless unless the number of operations is tracked. Conversely, manufacturers often point out special needs or requirements for equipment specific to that particular device; information that might otherwise not be available from any other source.

Preventing Unscheduled Downtime Maintenance is expensive. Not performing maintenance is even more expensive. Between equipment damage, lost production, securing replacement equipment at premium, overtime to install new equipment and possible OSHA fines if workers are injured the costs add up very quickly. As an example, one company suffered over $750,000 in costs for a failure in an underground 15 kV feeder. Their circuit breakers had not been maintained for several years and the fault cascaded through six circuit breakers, damaging the entire lineup beyond repair. Another company accrued $5.2 million in costs from a 100 A circuit breaker that nuisance tripped undetected. Shermco sees dozens of these types of failures each year.

Preventing Equipment Damage Electrical power system equipment costs thousands of dollars, not including the cost of installation. When there is an electrical failure this equipment is often damaged and either has to be taken out of service for repair or for replacement. Often, electrical failures don’t damage just one piece of equipment, but several pieces

74 ramping up costs quickly. As in the examples above, loss of production can be a major cost factor.

Insurance Requirements Companies often insure themselves against loss due to unscheduled production outages. Insurance companies are in the business to make money, not pay claims. This sets up a possible conflict between the two parties. In the event of a loss of production due to equipment failure, insurance companies will want to see that the maintenance they have specified has been performed at the intervals they specify. If proof of such maintenance cannot be produced the claim will be denied. At a slag-strip mill in Georgia I was testing the protective relays on a 15 kV power distribution system. The relays had metal dust in them. The covers were either off or the glass in the covers was broken. Almost every relay tested was inoperative. When the manager of the mill walked by I stated, “These relays don’t work. I’m going to need more time to repair them.” His reply – “The insurance company didn’t say they had to work; just that they had to be tested”. What are the chances the insurance company would pay a claim?

Standard’s Recommendations and Requirements There are two levels of requirements; recommended practices and standards. Recommended practices will not contain “mandatory” language. They will use words such as “should” or “might”, instead of “shall” or “must”. Standards will use mandatory language, but even then a standard is a voluntary document. The only truly mandatory “standards” are from OSHA or MSHA, which are really Federal regulations, and therefore law.

Safety Vol. 2 According to recent studies, electrical arc flash is only responsible for approximately 3 to 4 fatalities per year. However, arc flash injures thousands each year and the injuries these workers receive tend to cause disabilities that the worker cannot overcome. Disabling injuries have extremely high total costs; by some estimates, between $4 million to $23 million per incident. Subjecting workers to such horrendous injuries and the subsequent life-changes is unnecessary and short-sighted by companies. Following safe work practice and maintaining electrical power systems and their equipment can virtually eliminate these incidents and the costs to the victim and company.

STUDIES INDICATING THE NEED FOR MAINTENANCE Several studies have been conducted that indicate the need for maintenance on electrical power systems and equipment. The IEEE Gold Book (IEEE standard 493) details 1469 reports of failures of electrical equipment, including circuit breakers, motors, transformers and open wire. One of the metrics used in this study was “percentage of failure caused from inadequate maintenance vs. month since maintained”. The results of that metric was shown as Table 5-2, shown here as Figure 1.

Still, recommended practices and standards provide minimum acceptable requirements for maintaining electrical power system equipment. Some standards and recommended practices that are pertinent to this paper are: ● NFPA 70E Chapter 2 ● NFPA 70B ● ANSI/NETA MTS-2011 ● IEEE 3007.2 ● CSA Z462 ● CSA Z463

Personnel Safety Safety of personnel working on or near energized electrical power systems or equipment should always be of paramount importance. Unfortunately, the press of business and the need to stay profitable can intrude into this concept. In the US workplace there were 163 electrical shock fatalities in 2010, in 2012 there were 156 and in 2013 there were 139. The number of fatalities from electrical shock has been decreasing since 1995, when there were approximately 350 fatalities. Approximately half of these electrocutions were non-electrical workers, such as painters, agricultural workers and laborers.

Fig. 1: Table 5-2 from IEEE Standard 493 Of special note is the column for circuit breaker failures, because circuit breakers are an overcurrent protective device (OCPD) and are crucial to worker safety. As the time period increases, the percentage failure also increases. When the time period reaches “More than 24 months ago” the percentage failure is 77.8%. The problem with this table is that we don’t know how much longer than 24 months that period may be. It could have been 25 months or 25 years. It does illustrate the fact that failures increase with time between maintenance cycles. NETA did a more comprehensive study on circuit breaker issues found during maintenance. Surveys went out to all NETA-member companies and 340,000 responses were tabulated. This study found that 22% of the overcurrent devices on low-voltage power circuit breakers did not meet manufacturer’s specifications, 43% of the circuit breakers surveyed had mechanical issues that affected their operation and 11% did not function at all. These findings should be considered

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Safety Vol. 2 when budgets are being formulated. The costs of equipment failure are high, and when workers are injured due to the failure to maintain equipment, it could become an issue in court if there is a lawsuit. Shell Oil Company conducted a system-wide analysis of their circuit breakers. The paperwork for that study has been lost, but one of participants has provided the following information. For all types and voltage classes the analysis found that after being in service undisturbed for three to five years 30% of the circuit breakers would not meet manufacturer’s specifications; after seven to ten years 50% and after 17 to 20 years over 90%. All three of these studies indicate that as maintenance intervals increase, failures also increase. In the case of OCPDs this can have severe consequences for electrical power system operation and worker safety.

STANDARD’S RECOMMENDATIONS AND REQUIREMENTS US Standards Recommendations and Requirements ANSI/NETA MTS-2011 Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems ANSI/NETA MTS-2011 has very specific requirements for every piece of equipment in the electrical power system. The MTS specifies what maintenance and tests should be performed, along with the expected outcome of that maintenance or test. There are several tables giving specifics on test voltages or currents, or other test quantity, as well as minimum acceptable results. It is a very concise, focused standard. Annex B “Frequency of Maintenance Tests” provides a matrix comparing the equipment’s reliability requirements and condition and providing a multiplier. This multiplier is used with the base maintenance requirement to further fine-tune maintenance needs for a given piece of equipment. Figures 2a and 2b show the ANSI/NETA MTS Annex B matrix. Using an average equipment condition vs. a high reliability need produces a multiplier of 0.5. That 0.5 is multiplied against the base maintenance frequency given in Figure 2b.

Fig. 2a: Maintenance Frequency Matrix, From ANSI/NETA MTS-2011 As can be seen from Figure 2b, circuit breakers generally have a 1 month visual inspection, 12 month visual and mechanical inspection and 36 month visual, mechanical inspection and test requirements.

Fig. 2b: Inspection and From ANSI/NETA MTS-2011

Test

Frequency

(Partial),

Multiplying 0.5 against the base maintenance requirements provides the following: Visual inspection – 2 week intervals Visual and mechanical inspection – 6 month intervals Visual and mechanical inspection and electrical tests – 18 month intervals The opposite is also true. Equipment having a lower than normal reliability requirement and average condition provides a 2.0 multiplier. That would result in: Visual inspection – 2 month intervals Visual and mechanical inspection – 24 month intervals Visual and mechanical inspection and electrical tests – 72 month intervals NFPA 70E Standard for Electrical Safety in the Workplace NFPA 70E Chapter 2 provides minimum acceptable maintenance requirements for many of the electrical power system’s components. Some general requirements include: “Section 205.3 General Maintenance Requirements. Electrical equipment shall be maintained in accordance with manufacturers’ instructions or industry consensus standards to reduce the risk of failure and the subsequent exposure of employees to electrical hazards.” “Section 205.4 Overcurrent Protective Devices. Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards. Maintenance, tests, and inspections shall be documented.” These two sections require maintenance of OCPD and electrical power systems, as well as documentation of maintenance, tests and inspections. Most larger companies already comply with these requirements, but smaller companies may struggle to meet them. Looking at the larger picture, trending of test results, which provides the most accurate analysis of condition of maintenance is impossible without documentation. Figure 3 is an example of trending several maintenance cycles to more accurately determine the condition of electrical power equipment. Also, in the case of an accident resulting in serious injury or a fatality is likely to result in a demand to produce such documentation. It would be almost impossible to recreate this documentation, if needed.

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Safety Vol. 2 IEEE 3007.2 IEEE Recommended Practice for the Maintenance of Industrial and Commercial Power Systems IEEE 3007.2 is one of the new IEEE “dot standards that took the place of the color bbook series and provides recommendations that are more generalized than ANSI/NETA MTS and NFPA 70B. Like NFPA 70B, it also describes various maintenance phil osophies, such as RCM (reliability-centered maintenance) and PM (periodic or phased maintenance). No specific maintenance periods are provided.

Canadian Standard’s Recommendations and Requirements

Fig. 3: Maintenance Intervals Are a Valuable Tool for Determining Equipment Condition NFPA 70B is another excellent reference for the maintenance of electrical power systems and equipment. Unlike ANSI/NETA MTS, the 70B is a recommended practice. Also, the 70B contains additional information not in the ANSI/NETA MTS, such as maintenance philosophies and explanatory information, forms and tables of recommended maintenance intervals. There are two primary tables for maintenance intervals, Table L.1, “Maintenance Intervals” and K.2 through K.4, “Maintenance of Equipment Subject to Long Intervals Between Shutdowns”. Table L.1 is used when the equipment can be shut down for periodic inspections, while Tables K.2, K.3 and K.4 are used when the equipment has to remain in service until a system-wide shut-down or turnaround. Figure 3a shows a portion of Table L.1, while Figure 3b shows a portion of Table K.2.

Obviously, the standards previously listed are also available above the 49th parallel and do not stop at the US-Canada border. NETA and NFPA standards have been used in Canada for many years as references for maintenance professionals as well as seed documents for Canadian Standards. There are a number of standards development organizations in Canada but the one that is typically referenced is the CSA Group. The CSA Group is an independent, not for profit organization that develops standards and codes. They currently have over 3000 published standards that cover a wide variety of topics. All CSA codes or standards are voluntary unless legislated by government or mandated by industry or trade associations. Although many CSA codes are cited in legislation at federal, provincial, state, and municipal levels across North America they need to be individually reviewed and referenced by the authority having jurisdiction for each region. There are two CSA documents that reference maintenance activities on electrical equipment. These are CSA Z462 Workplace Electrical Safety and CSA Z463 Guideline on Maintenance of Electrical Equipment. CSA Z462 is a standard that is written in normative language which means that it should be taken as a requirement while Z463 is a guideline that is written in advisory language. CSA Z462 Workplace Electrical Safety

Fig. 3a: Table K.2 (Partial), From NFPA 70B

Fig. 3b: Table L.1 (Partial), From NFPA 70B

Clause 5 of CSA Z462 is titled “Safety Related Maintenance Requirements” and specifies practical safety related maintenance requirements for electrical equipment and installations while performing installation, inspection, operation, maintenance, and demolition of conductors and equipment as well as any work in proximity to energized equipment. Many of the clauses and notes in Z462 are worded the same as NFPA 70E. This is due to the fact that Z462 was derived from NFPA 70E and has members on its committee. This is to maintain some consistency between the two standards, while allowing Z462 to meet Canadian-specific needs. Clause 5.2.3 which discusses equipment maintenance states that “Electrical equipment shall be maintained in accordance with the manufacturer’s instructions or industry consensus standards to

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Safety Vol. 2 reduce the risk associated with failure. The equipment owner or the owner’s designated representative shall be responsible for the maintenance of electrical equipment and documentation. Maintenance, tests, and inspections shall be documented.” Although there are clauses dealing with the maintenance of overcurrent and protective devices, substations and switchgear assemblies, as well as fuses and circuit breakers the statements made are general and are made to ensure that worker safety is the main goal and do not give you specific guidelines regarding how or when to perform maintenance on electrical equipment. CSA Z463 Guideline on Maintenance of Electrical Systems Z463 Purpose

● Reactive maintenance Proactive maintenance allows for servicing equipment before it breaks down and allows for predicting and prevention of failures before occurrences. Reactive maintenance or “run to fail” is operating the system with little or no maintenance. This allows for low budgets for maintenance, but can result in catastrophic failure, major disruptions within a facility, and possible injury to personnel that may be in the vicinity of the equipment at time of failure. Clause 5.2.3 states “Electrical equipment shall be maintained in accordance with manufacturer’s instructions or industry consensus standards to reduce the risk of failure and the subsequent exposure of employees to electrical hazards”.

The Z463 guideline was developed to improve worker safety and protect property through the application of maintenance strategies for electrical equipment. The primary goal of Z463 is to reduce number of failures in service or during operation. Failure to implement proper maintenance strategies can result in extreme equipment damage and downtime

Clause 5.2.4 states “Overcurrent protective devices – Overcurrent protective devices shall be maintained in accordance with the manufacturer’s instructions or industry standards”.

Z463 Contents

Clause 6 - Electrical Maintenance as part of Workplace Safety

The following are the Sections or Clauses that are included in Z4563 that give the more specific details around developing and maintaining a proper electrical maintenance program:

Many commercial and industrial facilities have a good safety program, but, tend to be deficient in the area of an electrical safety program. One of the basic requirements of a safe electrical power system is that of maintaining electrical power systems and equipment so they will function according to the manufacturer’s specifications. In order to reduce injuries, a workplace safety program should include an electrical maintenance program, as well as an electrical safety program. The ability of arc rated PPE to protect workers depends entirely on protective systems operating as they are designed.

● 4.0 - Electrical maintenance as part of quality management system ● 5.0 - Maintenance Strategy ● 6.0 - Electrical maintenance as part of workplace safety ● 7.0 - General maintenance practices Clause 4 - Electrical Maintenance as part of a Quality Management System Clause 4 introduces the principles for establishing an effective electrical maintenance program as part of a quality management system. Some examples of safety-related maintenance clauses found in Z463 are: 4.3.5.1 Note - (1) Improper or inadequate maintenance can result in increased opening time of the overcurrent protective device, thus increasing the incident energy. (4) For maintenance on overcurrent protective devices, see also Clause 5.2.4 and Annex B. Clause 5 - Maintenance Strategy Clause 5 details the pros and cons of each maintenance philosophy and other information that may be useful in determining the philosophy that your facility may want to adopt. There are two general approaches in Clause 5: ● Proactive maintenance

Clause 5.3.5 Note states “Protective devices - Failure to maintain protective devices can have an adverse effect on the arc flash hazard analysis incident energy values.”

Electrical power systems that are operated are poorly maintained present a higher risk for personnel if exposed to electrical shock and arcing faults. Any defects with OCPDs will cause them to operate slower, thereby increasing the incident energy a worker would be exposed to. In order to be safe to operate and maintain, electrical power distribution systems need to be tested and inspected during the acceptance phase and following final installation to ensure that they are operating in accordance with design criteria. Clause 7 - General Maintenance Practices Clause 7 specifies maintenance guidelines for energized and deenergized electrical distribution equipment. It would be safest for qualified workers of the electrical power system could be deenergized for all tasks. Some tasks require the electrical system remain energized, such as during troubleshooting activities. Most maintenance tasks can be performed in a deenergized or “off-line” status. Deenergized or offline maintenance means putting the equipment in an “electrically safe work condition”. After the equipment is safe to work on the guidelines set out in the

78 NETA MTS would be completed based on the type of equipment. Clause 8 - Equipment Specific Maintenance Practices Each piece of equipment is specifically addressed with general recommended maintenance practices. Detailed tests and inspections can be found in the NETA Maintenance Testing Specifications. Clause 8 follows this specification and generalizes the details of the tests for the following equipment, among other items: ● Switchgear ● Transformers ● Power Cable ● Switches ● Circuit Breakers ● Relaying Protection ● Rotating Machines

Maintenance Considerations Lubrication This is the number one cause of failure in circuit breakers. Shermco’s Circuit Breaker Shops report that 80% of the circuit breakers that come into the shop show signs of lack of lubrication. This can result in slow operations, missed operations and hung openings, all of which could cause a serious arc flash incident. Installation Errors These are not common, but are especially difficult to detect, especially in enclosed equipment. At the power plant I had worked at, one transformer (2,500 kVA, 13.8 kV to 480 V) blew the terminal chamber cover off the 13.8 kV side. The cover sheared twenty-one ½” bolts and went through a concrete-block wall. The cause was determined to be a defective termination that was installed over 20 years prior. The transformer had been tested every three years and showed no signs of failure. I often hear “That equipment is new. It was tested by the factory and doesn’t need to be tested again.” Believe it or not, new equipment can be defective. This piece of information seems to be a surprise to some managers. This type of failure is often referred to as “infant mortality”. If new equipment doesn’t fail, why is there a specific term for it? Sometimes people just aren’t up to the task. They are distracted, ill, medicated or otherwise unable to perform their tasks effectively. They may not mean to, but they are negligent in their work and the installation goes bad. The result is often failure of the equipment after a period of time, similar to the first example. Willful damage is another issue in some facilities. Workers who feel slighted, possibly because of a missed promotion, pay raise or other work-related issue have been known to sabotage equipment to even the score in their mind. At one nuclear power plant I visited they had to install fencing and security cameras around

Safety Vol. 2 newly-installed equipment to keep workers from damaging it. The reason? They didn’t want the construction project to end. Maintenance philosophy. How maintenance is planned and carried out has a huge effect on the operational status and safety of the equipment. “Run to failure” can be a valid maintenance plan, if there are primarily small, easily-replaced motors or other types of low-energy common types of devices. One such example may be a manufacturing facility that uses large conveyor systems. They may run the small factional horsepower motors to failure, as it is cheaper to replace them as they fail than to test them. This maintenance plan comes up short, though when larger, more critical types of electrical equipment or devices are considered. Regular “physicals” are required to maintain operational status and to ensure worker’s safety. NFPA 70E has several Informational Notes and sections that relate to the relationship between maintenance and safety: ● 130.4(A)(4) Normal Operation states in part, “The phrase properly maintained means that the equipment has been maintained in accordance with the manufacturer’s recommendations and applicable industry codes and standards ….” ● 130.5(3) Arc Flash Risk Assessment states, “An arc flash risk assessment shall be performed and shall: (3) Take into consideration the design of the overcurrent protective device and its opening time, including its condition of maintenance. ● 130.5 IN No. 1 states, “Improper or inadequate maintenance can result in increased opening time of the overcurrent protective device, thus increasing the incident energy. Where equipment is not properly installed or maintained, PPE selection based on incident energy analysis or the PPE category method may not provide adequate protection from arc flash hazards.” There are several other examples within NFPA 70E, and CSA Z462 contains similar clauses, although the wording may be slightly different. These statements indicate the importance of maintenance to worker safety. If a worker is seriously injured or killed, the maintenance history of the equipment could become an issue in court. Environment Electrical equipment that is located indoors will often require less maintenance than equipment outdoors. Even though the equipment may be designed for outdoor use, environmental factors, such as heat, rain, dirt/dust, humidity, etc. are constantly attacking the insulation. An example is the filtration commonly used in outdoor unit substations. Filters are installed at each end in the doors, but are rarely changed. Often they are removed and not replaced or they disintegrate from age and weathering. Routine maintenance should include maintaining such equipment in

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Safety Vol. 2 the manner specified by the manufacturer or industry consensus standards. Standards that are named in NFPA 70E Article 200.1 Scope are: ● NFPA 70B, Recommended Practice for Electrical Equipment Maintenance ● ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems ● IEEE 3007.2, IEEE Recommended Practice for the Maintenance of Industrial and Commercial Power Systems Time Allowed for Maintenance It seemed like a good idea at the time. Bring in all the contractors at one time and limit the amount of time the facility is out of production. It can be an effective method with proper planning and coordination between the host and each contractor, and a reasonable amount of time to accomplish the tasks at hand. Without the needed planning, coordination and required time, worker safety and the reliability of the electrical power system can become compromised. Be certain to: ● Conduct pre-job meetings that include all the affected parties. ● Document these meetings to ensure there are no misunderstandings and to meet NFPA 70E Section 110.3(C), which states, “(C) Documentation. Where the host employer has knowledge of hazards covered by this standard that are related to the contract employer’s work, there shall be a documented meeting between the host employer and the contract employer.” ● Develop a work plan to ensure there are no overlapping tasks that could cause an incident, such as one crew maintaining a switch, while another crew tests the conductors to that switch. Such incidents occur when proper planning has not taken place and people are rushed to finish. ● Allow adequate time for completion of the tasks safely. Trying to accomplish too much in too little time only can lead to a bad end. It is better to schedule two or even three shutdowns if the work cannot be accomplished within the allotted time period. Worker safety should always be a consideration. ● Ensure that each contractor is communicating with the host and the other contractors to ensure a safe work environment. Manufacturer’s Recommendations Considering they designed and manufactured the equipment, OEM’s recommendations should be considered whenever a maintenance plan is being developed. They will often issue service advisories that detail newly-found issues or recommendations for specific types and models of equipment. They will also have recommendations for specific requirements, such as operating temperatures, lubricants or adjustments needed. As stated earlier,

some of the newer instruction books can be fairly vague concerning maintenance intervals, but industry consensus standards can fill in the gaps. The operational history can also be used as a guide to determine maintenance intervals. Manufacturers also produce service advisories and product recalls. It is important to be aware of such advisories and recalls, as quite often they are linked to equipment performance and/or operation, most of which will affect the serviceability, or continued serviceability, of that particular device.

SUMMARY A properly designed, properly installed and properly maintained electrical power system is considered to be safe to operate and work on or near. In order to accomplish proper maintenance requires careful planning and research of the electrical power system history. Often, failures and unscheduled outages can be attributed to the lack of maintenance. No one would purchase a $60,000 vehicle and run it until it failed, but sometimes managers fail to consider the fact that many electrical devices, such as circuit breakers and switches are, in fact mechanical devices that require routine maintenance just as a vehicle does. Everyone wants to save money. There are effective ways to save, and there are ways that seem to work at first, but often lead to more failures later. Some of Shermco’s best customers have tried the “let’s delay maintenance or skip a shutdown” mode and have found their unscheduled outages and lost production costs far exceeded the costs involved in performing proper maintenance. It is a false economy, at best. James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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PROTECTIVE DEVICES MAINTENANCE AND THE POTENTIAL IMPACT ON ARC FLASH INCIDENT ENERGY PowerTest 2016 Dennis K. Neitzel, CPE, CESCP, AVO Training Institute, Inc.

ABSTRACT This paper provides insight into the maintenance requirements for overcurrent protective devices and the potential impact on the arc flash incident energy when maintenance is not performed. It provides valuable information for electricians, technicians, and engineers who operate and maintain the electrical equipment. Electrical preventive maintenance and testing is one of the most important functions to be performed in order to maintain the reliability and integrity of electrical distribution systems, as well as for the protection of equipment and people. However, preventive maintenance of electrical systems and equipment, specifically with regard to overcurrent protective devices is often overlooked, or is performed infrequently or inadequately. An unintentional time delay in the operation of a circuit breaker, due to a sticky operating mechanism, can cause the incident energy of an arc flash to rise, sometimes dramatically. KEY WORDS: Hazards; safety; electrical; PPE; arc flash; maintenace; qualified.

INTRODUCTION This paper provides insight into the electrical safety considerations, as they relate to maintenance of overcurrent protective devices, along with the potential impact on the arc flash energy, for industrial and commercial electrical equipment and systems. It provides valuable information for the electricians, technicians, and engineers who operate and maintain this equipment. Electrical preventive maintenance and testing are some of the most important tasks to be performed in order to assure the reliability and integrity of electrical distribution equipment and systems, as well as for the protection of personnel. However, preventive maintenance of electrical systems and equipment, specifically with regard to overcurrent protective devices, is often overlooked or performed infrequently. The National Electrical Code (NEC) states that overcurrent protection for conductors and equipment is provided to open the circuit if the current reaches a value that will cause an excessive or dangerous temperature in conductors or conductor insulation. With regard to circuit breakers the only way to accomplish this is through proper maintenance and testing of these devices.

MAINTENANCE AND TESTING The first step in properly maintaining electrical equipment and overcurrent protective devices is to understand the requirements and recommendations for electrical equipment maintenance from various sources. Examples of sources include, but are not limited to, the Manufacturer’s instructions, ANSI/NETA MTS, NFPA 70B, IEEE Std. 3007.2, NEMA AB-4, and NFPA 70E. The second step in performing maintenance and testing is to provide adequate training and qualification for employees. NFPA 70E-2015, Standard for Electrical Safety in the Workplace, Section 205.1 states, “Employees who perform maintenance on electrical equipment and installations shall be qualified persons… and shall be trained in and familiar with, the specific maintenance procedures and tests required.” The Occupational Safety and Health Administration (OSHA), defines a qualified person as “One who has received training in and has demonstrated skills and knowledge in the construction and operation of electric equipment and installations and the hazards involved.” It is important that employees are properly trained and qualified to maintain electrical equipment in order to increase the equipment and system reliability, as well as enhance employee safety. Electrical Preventive Maintenance Program: NFPA 70E, Section 205.3 states “Electrical equipment shall be maintained in accordance with manufacturers’ instructions or industry consensus standards to reduce the risk of failure and the subsequent exposure of employees to electrical hazards.” Section 205.4 further states that “Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards. Maintenance, tests, and inspections shall be documented.” It goes on to state in Section 225.3 that “Circuit breakers that interrupt faults approaching their ratings shall be inspected and tested in accordance with the manufacturers’ instructions. Therefore, the third step is to have a written, effective Electrical Preventive Maintenance (EPM) program. NFPA 70B-2013, Recommended Practice for Electrical Equipment Maintenance, makes several very clear statements about an effective EPM program as follows: “Electrical equipment deterioration is normal, but equipment failure is not inevitable. As soon as new equipment is installed, a

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Safety Vol. 2 process of normal deterioration begins. Unchecked, the deterioration process can cause malfunction or an electrical failure. Deterioration can be accelerated by factors such as a hostile environment, overload, or severe duty cycle. An effective EPM program identifies and recognizes these factors and provides measures for coping with them. “ “In addition to normal deterioration, there are other potential causes of equipment failure that can be detected and corrected through EPM. Among these are load changes or additions, circuit alterations, improperly set or improperly selected protective devices, and changing voltage conditions.” “Without an EPM program, management assumes a greatly increased risk of a serious electrical failure and its consequences.” “A well-administered EPM program will reduce accidents, save lives, and minimize costly breakdowns and unplanned shutdowns of production equipment. Impending troubles can be identified — and solutions applied — before they become major problems requiring more expensive, time consuming solutions.” IEEE Std 3007.2-2010, Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, states: “In planning an electrical preventive maintenance (EPM) program, consideration must be given to the costs of safety, the costs associated with direct losses due to equipment damage, and the indirect costs associated with downtime or lost or inefficient production.” All maintenance and testing of electrical protective devices addressed here must be accomplished in accordance with the manufacturer’s instructions. In the absense of the manufacturer’s instructions, the latest edition of the ANSI/NETA, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, 2015 Edition, is an excellent source of information for performing the required maintenance and testing of these devices. However, the manufacturer’s time-current curves would valuable information for properly testing each protective device. Molded-Case Circuit Breakers: The need for inspection of molded-case breakers (MCCBs) will vary depending on operating conditions. Suggested inspection and testing is defined in NEMA AB 4, Guidelines for Inspection and Preventive Maintenance of Molded Case Circuit Breakers Used in Commercial and Industrial Applications. MCCBs receive initial testing and calibration at the manufacturers’ plants. These tests are performed in acco rdance with UL 489, Standard for Safety, Molded-Case Circuit Breakers, Molded-Case Switches and Circuit Breaker Enclosures. MCCBs, other than the riveted frame types, are permitted to be reconditioned and returned to the manufacturer’s original condition. In order to conform to the manufacturer’s original design, circuit breakers must be reconditioned according to recognized standards. An example of a recognized standard is the Professional Electrical Apparatus Recyclers League (PEARL) Reconditioning Standards. In order to ensure equipment reliability, it is highly recommended that only authorized and qualified professionals recondition MCCBs.

Circuit breakers installed in a system are often forgotten. Even though the breakers have been sitting in place supplying power to a circuit for years, there are several things that can go wrong. The circuit breaker can fail to open due to a burned out trip coil or because the mechanism is frozen due to dirt, dried lubricant, or corrosion, or it can fail due to inactivity or a burned out electronic component. Many problems can occur when proper maintenance is not performed and the breaker fails to open under fault conditions. This combination of events can result in fires, damage to equipment, or injuries to personnel. The manufacturers’ literature, or approved industry concensus standards, must be used when maintaining circuit breakers. Most manufacturers, as well as NFPA 70B, recommend that if an MCCB has not been operated, opened or closed, either manually or by automatic means, within as little as six months time, it should be removed from service (the load removed) and manually exercised several times. This manual exercise helps to keep the contacts clean, due to their wiping action when opening and closing, and helps ensure that the operating mechanism moves freely and helps keep the lubrication fluid. This exercise does not necessarily operate the mechanical linkages of the tripping mechanism (see Figure 1). Generally, the only way to properly exercise the entire breaker, including the operating and tripping mechanisms, is to remove the breaker from service and test the overload and short-circuit tripping capabilities. A stiff or sticky mechanism can cause an unintentional time delay in its operation under fault conditions. This could dramatically increase the arc flash incident energy level to a value in excess of the rating of personal protective equipment.

Fig. 1: Principle Components The maintenance procedures and tests, regularly performed on MCCBs, generally includes visual inspection; lubrication where possible; cleaning; insulation resistance tests; contact resistance tests; and overcurrent tests. Visual inspection and cleaning of an MCCB are some of the simplest tests and therefore are sometimes overlooked. Yet, they are a vital part of breaker maintenance. These basic tests don’t take much time to do, yet they can point out and help avoid catastrophic

82 problems. When performing a visual inspection, look for signs of overheating, excessive arcing, bent linkages, cracked insulation, tracking, etc. For a 3-phase breaker, this inspection is simplified because the condition of one phase can be compared with the other two phases. MCCBs should be kept clean for proper ventilation of the breakers. These types of breakers are usually tripped by a thermal element that senses an increase in temperature due to excessive current draw. However, if dirt accumulates on the surrounding of the breaker, the heat build-up may not be permitted to dissipate properly and result in nuisance tripping. Clean the breaker housing and inspect it for cracks or signs of overheating. Tighten all connections. Exercise the breaker several times to ensure the mechanism has freedom of movement and to allow contact wiping. In addition, larger duty circuit breakers (225 amps or above) should be electrically trip tested to ensure proper operation of the trip elements and trip linkages. If possible, test contact resistance to ensure quality of breaker contacts. All molded-case circuit breaker panels should be cleaned of all dirt, dust, and debris using a vacuum. This should only be performed with the equipment in an electrically safe work condition. If it is required to be performed while energized, only qualified workers, applying all required safe work practices and PPE. Loose connections result in higher resistances and high resistance connections create heat, which is one of the biggest causes of electrical fires. If the connection is very loose, you may see charred or melted thermoplastic insulation on the conductors with the naked eye. But not always. Another area of concern in circuit breakers and switches is high-contact resistance caused by wear of the contact surfaces. As contacts open and close, especially during fault conditions, the contact faces are eroded. This material is sprayed into the arc chutes, along with carbon and other arc by-products. Insufficient contact pressure is often the result of wear and erosion. IR scanning can identify these conditions. For MCCBs, the visual inspection is sometimes difficult if not impossible. Some MCCBs come from the factory sealed – breaking the seal jeopardizes manufacturer’s warranty. This means the only inspection that can be carried out is on the enclosure and cable terminations. If the MCCB is not sealed, the cover can be removed. This will allow inspection of current-carrying conductors and the mechanism. Again, there are some MCCBs that have arc chutes sealed in place. This makes the inspection of the moving and stationary contacts difficult. Another visual inspection that should be performed regularly is infrared thermography (IR). IR scanning is recommended as a regular maintenance procedure. The IR scanning must be accomplished with the MCCB energized, closed, and loaded with normal full-load current. IR scanning and analysis have become an essential diagnostic and predictive maintenance tool throughout all industries and have been used to detect many serious conditions requiring immediate corrective action. Many forced outages

Safety Vol. 2 have been avoided by early detection and correction of problems before the equipment fails. IR scanning is nonintrusive and is accomplished while equipment is in service. Since the equipment is in service and the equipment doors are opened or covers removed, potential electrical hazards exist and all required personal protective equipment (PPE) must be used, where applicable, for shock and/or arc flash. Loose connections result in higher resistances and high resistance connections create heat, which is one of the biggest causes of electrical fires. If the connection is very loose, you may see charred or melted thermoplastic insulation on the conductors with the naked eye. But not always. IR scanning will identify this condition. Another area of concern in circuit breakers and switches is high-contact resistance caused by wear of the contact surfaces. As contacts open and close, especially during fault conditions, the contact faces are eroded. This material is sprayed into the arc chutes, along with carbon and other arc by-products. Insufficient contact pressure is often the result of wear and erosion. Insulation resistance, contact resistance, and overcurrent tests require specialized testing equipment for proper testing. Low-Voltage Power Circuit Breakers: Low-voltage power circuit breakers are manufactured under a high degree of quality control, of the best materials available, and with a high degree of tooling for operational accuracy. Manufacturer’s tests, per UL 1066 Low-Voltage AC and DC Power Circuit Breakers Used in Enclosures, show these circuit breakers to have durability beyond the minimum standards requirements. All of these factors give these circuit breakers a very high reliability rating when proper maintenance is performed, per the manufacturer’s instrctions. However, because of the varying application conditions and the dependence placed upon them for protection of electrical systems and equipment, as well as the assurance of service continuity, inspections and maintenance must be made on a regular basis, as recommended by the manufacture. Maintenance of these breakers will generally consist of keeping them clean, adjusted, and properly lubricated. In addition, it is also necessary to periodically check the circuit breaker contacts for wear and alignment and inspect the arc chutes, especially after the breaker has opened under a fault condition. The frequency of maintenance will depend to some extent on the cleanliness and environmental conditions of the surrounding area. If there is very much dust, lint, moisture, or other foreign matter present then more frequent inspections and maintenance may be required. Industry standards and manufacturer’s instructions recommend a general inspection and lubrication after a specified number of operations or at least once per year, whichever comes first. If the breaker remains open or closed for a long period of time, it is recommended that arrangements be made to remove the breaker from service and to open and close it several times in succession. Mechanical failure would include an unintentional time delay in

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Safety Vol. 2 the circuit breakers tripping operation due to dry, dirty, or corroded pivot points or by hardened or sticky lubricant in the moving parts of the operating mechanism. Figure 2 provides an illustration of the numerous points where lubrication would be required and where dirt, moisture, corrosion or other foreign matter could accumulate causing a time delay in, or complete failure of, the circuit breaker operation.

● 23% of all circuit breakers failures were suspected to be caused by manufacturer defective component. ● 23% of all circuit breaker failures were suspected to be caused by inadequate maintenance. ● 73% of all circuit breaker failures required round-the-clock all-out efforts. Another survey was conducted specifically on low-voltage power circuit breakers and the results concluded: ● 19.4% of low-voltage power circuit breakers with electromechanical trip units had unacceptable operation. ● 10.7% of low-voltage power circuit breakers with solid-state trip units had unacceptable operation.

RELIABILITY AND INTEGRITY

Fig. 2: Power-Operated Mechanism

FAILURE STATISTICS Several studies on electrical equipment failures have been completed over the years by IEEE. These studies have generated failure statisics on electrical distribution system equipment and components. IEEE Std. 493 (the Gold Book) “IEEE Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems” contains the information and statistics from these studies and can be used to provide faliure data of electirical equipment and components, such as circuit breakers. The results of these studies were based upon low- and medium-voltage power circuit breakers (drawout and fixed) as well as fixed mounted molded-case circuit breakers. The results of the study indicated: ● 32% of all circuit breakers failed while in service. ● 9% of all circuit breakers failed while opening. ● 7% of all circuit breakers failed due to damage while successfully opening. ● 42% of all circuit breakers failed by opening when it should not have opened. ● 77% of fixed mounted circuit breakers (0-600V including molded case) failed while in service. ● 18% of all circuit breakers had a mechanical failure ● 28% of all circuit breakers had an electric-protective device failure.

In reviewing the data from these studies, it can be seen that nearly 1/3 of all circuit breakers failed while in service and thus would not have been identified unless proper maintenance was performed. In addition, 16% of all circuit breakers failed or were damaged while opening. The fact that 42% of all circuit breakers failed, by opening when they should not have opened, suggests improper circuit breaker settings or a lack of selective coordination. This type of circuit breaker failure can significantly affect plant processes and could result in a total plant shutdown. Also of significance is that a very large percentage of fixed mounted circuit breakers, including molded-case had a very high failure rate of 77.8%. This is most likely due to the fact that maintenance of this style of device is often overlooked, but certainly is just as important. The fact that 18% of all circuit breakers had a mechanical failure and 28% had an electrical protective device failure suggests that both the mechanical linkages, as well as the trip units, need to be maintained. Furthermore, although mechanical maintenance is important, proper testing of the trip unit is much more critical. Also of importance, is the realization that maintenance and testing is needed because nearly ¼ of all circuit breaker failures were caused by a manufacturer’s defective component and nearly another ¼ of all circuit breaker failures were due to inadequate maintenance. Thus, if proper maintenance and testing is performed, potentially 50% of the failures could be eliminated or identified before a problem occurs. But perhaps the most important issue for an end user is downtime. With regard to this concern, the study indicated 73% of all circuit breaker failures required roundthe-clock all-out efforts. This could most likely be greatly reduced if preventive maintenance was performed on a regular basis. As can be seen by the statistics above, failures can and do occur, therefore maintenance and testing is crucial to the reliability and safety of all circuit breakers.

84 RESETTING CIRCUIT BREAKERS AFTER AUTOMATIC OPERATION Another issue associated with the failure of circuit breakers is resetting a circuit breaker that has tripped by automatic means due to an overcurrent condition (overload, short-circuit, or ground-fault). OSHA 29 CFR 1910.334(b)(2) addresses this situation very clearly: “Reclosing circuits after protective device operation. After a circuit is deenergized by a circuit protective device, the circuit may NOT be manually reenergized until it has been determined that the equipment and circuit can be safely reenergized. The repetitive manual reclosing of circuit breakers or reenergizing circuits through replaced fuses is prohibited. NOTE: When it can be determined from the design of the circuit and the overcurrent devices involved that the automatic operation of a device was caused by an overload rather than a fault condition, no examination of the circuit or connected equipment is needed before the circuit is reenergized.” The safety of the employee manually operating the circuit breaker is at risk if the short-circuit condition still exists when reclosing the breaker. OSHA no longer allows the past practice of resetting a circuit breaker one, two, or three times before investigating the cause of the trip. This previous practice has caused numerous burn injuries that resulted from the explosion of electrical equipment. Before resetting a circuit breaker, it, along with the circuit and equipment, must be tested and inspected by a qualified person to ensure a short-circuit condition does not exist and that it is safe to reset the breaker. Any time a circuit breaker has operated and the reason is unknown, the breaker, circuit, and equipment must be inspected and tested for a short-circuit condition. Melted arc chutes will not interrupt fault currents. If the breaker cannot interrupt a second fault, it will fail and may destroy its enclosure and create a hazard for anyone working near the equipment. This could result in an arc flash incident. To further emphasize this point the following quote is provided: “After a high level fault has occurred in equipment that is properly rated and installed, it is not always clear to investigating electricians what damage has occurred inside encased equipment. The circuit breaker may well appear virtually clean while its internal condition is unknown. For such situations, the NEMA AB4 ‘Guidelines for Inspection and Preventive Maintenance of MCCBs Used in Commercial and Industrial Applications may be of help. Circuit breakers unsuitable for continued service may be identified by simple inspection under these guidelines. Testing outlined in the document is another and more definite step that will help to identify circuit breakers that are no longer suitable for continued service.” A circuit breaker may require replacement just as any other switching device, wiring or electrical equipment in the circuit that has been exposed to short-circuit current. Questionable circuit breakers must be replaced for continued, dependable circuit

Safety Vol. 2 protection. The condition of the circuit breaker must be known to ensure that it functions properly and safely before it is put it back into service.

ARC FLASH HAZARD CONSIDERATIONS Maintenance and testing are essential to ensure proper protection of equipment and personnel. With regard to personnel protection, NFPA 70E requires an arc flash risk assessment be performed before anyone approaches exposed energized electrical conductors or circuit parts that have not been placed in an electrically safe work condition. NFPA 70E, Section 130.5 states that the arc flash risk assessment must take into consideration the design of the overcurrent protective device and it’s opening time, including its condition of maintenance. In addition it requires an arc flash boundary to be established. All calculations for determining the incident energy of an arc and for establishing an arc flash boundary require the arc clearing time of the overcurrent protective device. This clearing time is derived from the settings on the divice along with the time-current curves. This information can also be obtained from a current engineering protective device coordination study, which is based on what the protective devices are supposed to do. If, for example, a low-voltage power circuit breaker had not been operated or maintained for several years and the lubrication had become sticky or hardened, the circuit breaker could take several additional cycles, seconds, minutes, or longer to clear a fault condition. The following are specific examples: Two incident energy analyses will be performed using a 20,000amp short-circuit with the worker 18 inches from the arc: ● Based on what the system is supposed to do: ○ 0.083 second (5 cycles) arc clearing time ● Due to a sticky mechanism the breaker now has an unintentional time delay: ○ 0.5 second (30 cycles) arc clearing time The example calculations use the NFPA 70E equations found in Annex D of the 2015 edition. Example #1: EMB = maximum 20 in. cubic box incident energy, cal/cm2 DB = distance from arc electrodes, inches (for distances 18 in. and greater) tA = arc duration, seconds F = short circuit current, kA (for the range of 16 kA to 50 kA) (1) DA = 18 in. (2) tA = 0.083 second (5 cycles) (3) F = 20kA EMB = 1038.7DB-1.4738 tA [0.0093F2 - 0.3453F + 5.9675]

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Safety Vol. 2 = 1038 x 0.0141 x 0.083[0.0093 x 400 - 0.3453 x 20 + 5.9675] = 1.4636 x [2.7815] = 3.5 cal/cm2 NFPA 70E, 130.5(C)(1) requires arc-rated clothing and other PPE are to be selected based on this incident energy level exposure. Therefore the arc-rated clothing and PPE must have an arc rating of at least 3.5 cal/cm2. Example #2: EMB = maximum 20 in. cubic box incident energy, cal/cm

2

DB = distance from arc electrodes, inches (for distances 18 in. and greater) tA = arc duration, seconds F = short circuit current, kA (for the range of 16 kA to 50 kA) (1) DA = 18 in. (2) tA = 0.5 second (30 cycles) (3) F = 20kA EMB = 1038.7DB-1.4738 tA [0.0093F2 - 0.3453F + 5.9675] = 1038 x 0.0141 x 0.5[0.0093 x 400 - 0.3453 x 20 + 5.9675] = 7.3179 x [2.7815] = 20.4 cal/cm2 NFPA 70E, 130.5(C)(1) requires arc-rated clothing and other PPE are to be selected based on this incident energy level exposure. Therefore the arc-rated clothing and PPE must have an arc rating of at least 20.4 cal/cm2. If the worker is protected based on what the circuit breaker is supposed to do (0.083 second or 5 cycles) and an unintentional time delay occurs (0.5 second or 30 cycles), the worker could be seriously injured or killed because he/she was under protected. As can be seen, maintenance is extremely important to an electrical safety program. Maintenance must be performed according to the manufacturer’s instructions in order to minimize the risk of having an unintentional time delay in the operation of the circuit protective devices.

CONCLUSION In order to protect electrical equipment and personnel, proper electrical equipment preventive maintenance must be performed. Several standards and guides exist to assist users with electrical equipment maintenance. When the overcurrent protective devices are properly maintained and tested for proper calibration and operation, equipment damage and arc flash hazards can be limited as expected. Unfortunately many in industry think that just because the lights are on or the machines are running that everything is okay and that maintenance is not needed, because the circuit breaker is working just fine. No, the circuit breaker is not working, it is

closed. Working is when an overload, ground-fault, or short-circuit occurs and the circuit breaker opens automatically in the time specified or when it is manually opened or closed. Maintenance of overcurrent protective devices is critical to electrical equipment and systems reliability, as well as for safety of personnel.

REFERENCES NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, 2013 Edition IEEE Std. 3007.2-2010, IEEE Recommended Practice for the Maintenance of Industrial and Commercial Power Systems NEMA Standard AB-4, Guidelines for Inspection and Preventive Maintenance of Molded Case Circuit Breakers Used in Commercial and Industrial Applications IEEE Standard 493-2007 (the Gold Book), Recommended Practice For The Design Of Reliable Industrial And Commercial Power Systems IEEE Standard 1015-2006 (the Blue Book), Recommended Practice For Applying Low-Voltage Circuit Breakers Used In Industrial And Commercial Power Systems NFPA 70E-2015, Standard for Electrical Safety in the Workplace IEEE Standard 1584-2002, IEEE Guide for Arc Flash Hazard Calculations ANSI/NETA MTS-2015, Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems National Equipment Manufacturer’s Association (NEMA) Vince A. Baclawski, Technical Director, Power Distribution Products, NEMA; EC&M magazine, pp. 10, January 1995 Manufacturer’s Instruction Books Dennis K. Neitzel, CPE, Director Emeritus of AVO Training Institute, Inc., Dallas, Texas, has over 45 years experience in Electrical Utility, Industrial facility, and shipyard/shipboard electrical equipment and systems maintenance and testing experience, with an extensive background in electrical safety and power systems analysis. He is an active member of IEEE, ASSE, AFE, IAEI, and NFPA. He is a Certified Plant Engineer (CPE) and a Certified Electrical Inspector-General. Mr. Neitzel earned his Bachelor’s degree in Electrical Engineering Management and his Master’s degree in Electrical Engineering Applied Sciences. He is a Principle Committee Member and Special Expert for the NFPA 70E, Standard for Electrical Safety in the Workplace; member of the Defense Safety Oversight Council, Electrical Safety Working Group – DoD Electrical Safety Special Interest Initiative; Working Group Chairman of IEEE 3007.1-2010 Recommended Practice for the Operation and Management of Industrial and Commercial Power Systems, 3007.2-2010 Recommended Practice for the Maintenance of Industrial and Commercial Power Systems,

86 & 3007.3-2012 Recommended Practice for Electrical Safety of Industrial and Commercial Power Systems; Working Group Chairman of IEEE P45.5 Recommended Practice for Electrical Installations on Shipboard - Safety Considerations; and co-author of the Electrical Safety Handbook, McGraw-Hill Publishers. Mr. Neitzel has also authored, published, and presented numerous technical papers and magazine articles on electrical safety, maintenance, and training. For more information, contact Mr. Neitzel by e-mail at [email protected].

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POTENTIAL IMPACT OF ISO 55000 ON MAINTENANCE CRITICAL TO ELECTRICAL SAFETY PowerTest 2016 H. Landis Floyd, PE, CSP, CESP, CMRP, CRL, Fellow IEEE

ABSTRACT This paper discusses a common problem in managing maintenance of electrical equipment critical to electrical safety. Most electrical equipment requires some level of maintenance to assure performance objectives, however not all electrical equipment is critical to electrical safety. How does an organization identify electrical safety critical equipment and assure optimum prioritization and allocation of maintenance activities? The reliability objectives of the subset of electrical equipment and systems critical to electrical safety can be best achieved by applying proven tools used in asset and reliability management. ISO 55000 Asset Management, published in 2014, is widely regarded as providing state of the art comprehensive guidance for managing reliability of physical assets including electrical equipment and systems. This paper will review and illustrate how application of concepts and tools contained in ISO 55000 can help optimize safety impact of maintenance requirements provided in NETA, NFPA, CSA, IEEE and other electrical maintenance standards.

A LESSON IN CRITICALITY I had just settled into my seat for an evening flight from Philadelphia to Los Angeles. My briefcase held recently obtained reference materials that I wanted to incorporate into a presentation I would be giving at a conference later in the week. The 5-hour flight would give me ample time to review the materials and revise my presentation. I reached overhead to turn on my reading light, but the light did not come on. Other reading lights were on, so I pushed the button again, but still no light. Now I was getting a little annoyed. My work plan for the next several hours was now disrupted by a failure in my reading light. I knew the flight was full, so changing seats was not a likely option. The reliability of the reading light was really messing up my plans. I decided to wait until after takeoff to call a flight attendant to see if changing seats was possible. The plane was barely above treetop level when it banked hard to the left. Obviously something was not right. A voice from the cockpit announced that we were returning to the airport. One of the two onboard electrical generators had failed on takeoff. In an instant, the most important reliability issue for me changed. My concern for the reliability of my reading light suddenly was insignificant. What if the failure in one generator involved something common to both generators? How long can this commercial jet fly with loss of electric power? There was a happy ending to this

story. The pilot landed the plane safely. There was a 90-min delay as the passengers and baggage were moved to another plane. The reading light in the replacement plane worked, and I completed the revision to my presentation before landing in Los Angeles. The experience was a very personal lesson in criticality analysis necessary to effectively manage maintenance and reliability. The financial and human resources to perform design and maintenance activities to achieve reliability objectives are limited for any organization. There are usually multiple objectives spanning the continuity of operations, services to customers, safety, environmental protection, and protection of costly equipment. As in my story of the reliability of the reading light and onboard generator, just because one may think that the reliability of a particular piece of electrical equipment is important, in the bigger scheme of things, what is critical to one person may not be all that critical. The tools, methods, and resources to define and achieve reliability goals must include a criticality analysis involving a broad cross section of people who are knowledgeable of an organization’s goals and objectives 1. criticality analysis: a tool to use if you want to improve reliability and manage plant assets based on risk instead of perception 2.

A COMMON GAP IN MAINTENANCE IMPACTING ELECTRICAL SAFETY Business and commerce in our modern society are completely dependent on electrical technologies. Any unscheduled disruption of electrical energy, control or communications systems can have immediate and costly disruption to operation. Assuring availability of electrical systems critical to operations uptime provides the basis for establishing reliability objectives and maintenance programs for a facility’s electrical equipment and systems. However, equipment critical to electrical safety may have little correlation with equipment critical to operations uptime. An organization that uses operation uptime as the focus for electrical reliability may unintentionally overlook equipment reliability critical to electrical safety. Consider these two examples: Switchgear enclosures provide a barrier between people and energized components. Maintaining the integrity of enclosures is critical to preventing electric shock and arc flash injuries. On the other hand, a door or cover could be missing, with no immediate impact on service continuity and operations uptime.

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Equipment grounding safeguards personnel from electric shock injury if there is an insulation failure in equipment wiring allowing the equipment case or enclosure to become energized. A failure in equipment grounding could allow personnel exposure to hazardous energy, but have no impact on equipment operation and uptime. During economic business cycles, reliability needs for equipment critical to operations uptime may change. The consequences of equipment outages during business downturns may be more acceptable than when operating at full capacity demand. During a business downturn, a maintenance manager may defer maintenance on certain equipment based on lesser outage consequences. However, this should not be the case for equipment critical to electrical safety. The hazards don’t care if there is a recession. Criticality analysis with a focus on equipment critical to electrical safety can help an organization maintain appropriate reliability for electrical safety equipment independent of economic business conditions.

Fig. 2: A section of 480V industrial switchgear destroyed by an arcing fault

CRITICAL OBJECTIVES – A CASE HISTORY 3 Figure 2 shows a catastrophic failure in a section of 480 volt switchgear in an industrial facility. An arcing fault completely destroyed the switchgear. Repair costs exceeded $100,000. The impact on the business from production losses was even greater. A single worker was standing in front of the equipment at the time of failure and received disabling burn injuries associated with the arc flash exposure from the arcing fault. The equipment shown in Figure 2 was well maintained. There was a detailed maintenance and inspection program for the circuit breakers and switchgear. Infrared thermography was part of the program. Housekeeping and ambient conditions were excellent. The event that initiated the arcing fault was a screw that the worker dropped in a control cabinet at the top of the switchgear. The screw fell through a small opening and found its way down into the 480 volt buss compartment below, where it initiated a destructive arcing fault. The protective relaying to minimize the damage from an arcing fault was designed to clear the fault within a fraction of a second. However, the fault lasted for approximately 30 seconds due to a hidden failure in a device critical to electrical safety. The hidden failure was in the trip coil of the 15kV circuit breaker on the primary of the substation. The 15kV circuit breaker and trip coil are shown in Figures 3 and 4. The trip coil is the actuating device that converts an electrical signal from the overcurrent and other protective relays for the substation and operates the circuit breaker trip mechanism. The trip coil had been defective for an undetermined period of time, with no impact on operations uptime.

Fig. 3: One of the 480V draw out circuit breakers in the destroyed switchgear

Trip coil is located behind panel

Fig: 4: An example of the 15kV circuit breaker that failed to clear the fault illustrated in Fig 1 & 2

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Engineering controls, because they consist of hardware and systems of equipment and devices, are dependent on maintenance to help assure designed functionality. Brauer discussed a major limitation with engineering controls in that they can be rendered inoperative due to improper installation, shortcoming in functional testing, or lack of maintenance 6. The net result of an inoperative engineering control is unprotected exposure of workers to the hazard.

ENGINEERING CONTROLS AND HIDDEN FAILURES

Fig. 5: An example of the trip coil that had a hidden failure In the Hierarchy of Safety Controls in ANSI Z10-2012 Occupational Health and Safety Management Systems, Engineering Controls are equipment and systems that automatically reduce risk of injury, with no action required by the person at risk 5. GFCIs, circuit breakers, fuses and equipment grounding are examples of Engineering Controls for reducing risk of electrical injuries. Other examples of Engineering Controls for both electric shock and arc flash hazards are shown in Table I. Using a few examples of electrical equipment common in facility installations, a comparison of electrical equipment reliability differentiated by uptime and electrical safety impact is provided in Table II. Examples of Engineering Controls for Electrical Hazards Engineering Control

Impact on electrical safety

Grounding and Bonding systems

• Enable overcurrent protective devices to function • Prevent ignition from sparking or arcing in explosive or flammable environments • Prevent shock exposures during fault current conditions

Overcurrent Protective Devices

Limit arc flash incident energy

Circuit breaker tripping power supplies

Provides control power for power system protective relays and circuit breakers essential for arc flash mitigation

Ground Fault Circuit Interrupters

Sense shock events and limit energy to below lethal electrocution level

High Resistance Grounding Systems

Minimize frequency of arc flash incidents

Enclosures, doors and covers to guard energized parts

Prevents unintentional contact with energized circuits with tools or body parts, impacting both electric shock and arc flash hazard mitigation

Insulated power cords for tools and appliances

Insulation integrity provides protection from contact with energized conductors that could present a shock hazard

Table I: Examples of Engineering Controls Commonly Applied to Mitigate Electrical Hazards 3

The arc flash hazard analysis and the selection of thermal personal protective equipment are completely dependent on the protective devices to function exactly as designed. Circuit breakers must function as designed. Overcurrent devices must operate at the designed and documented pick up and time settings. For circuit breakers or protective devices dependent on external power supply, the tripping power system (usually batteries and battery charger) must be functioning as designed. If the protective device is a fuse, the installed fuse must meet the design specifications and be the type, class and rating of the one documented in the arc flash analysis. There should be a robust management system to assure no deviation from this expectation. The recognition of arc flash as a unique electrical hazard has led to a new expectation for circuit protection devices: the safeguarding of personnel from the hazards of thermal burns and explosive blasts. This has changed the design rules for analysis and protection of power systems and power system protection. This has also enabled recognition of a different expected outcome for electrical equipment maintenance – the assurance that overcurrent protective device pickup and trip characteristics used as the basis for arc flash hazard analysis and selection of safety control measures including personal protective equipment will perform exactly as designed. If these devices do not function as designed, the thermal and blast energy exposure may be orders of magnitude greater than expected. Unfortunately, many engineering controls used in electrical injury risk mitigation applications can fail undetected. There may be no impact on uptime, and the loss of protective capabilities may not be known until an injury occurs. Heid and Widup, when performing functional testing on their customers’ power system circuit breakers, found more than 20% did not trip according to the designed trip specifications 4. More alarming was the finding that approximately 10% would not trip at all. The breakers were literally stuck in the closed position. These failures were not visible except under functional testing.

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Comparing Equipment Reliability Critical to Uptime and Electrical Safety Equipment

Uptime impact

Electrical safety impact

Motors

May be critical

No direct impact

Transformers

May be critical

No direct impact

Power Cables

May be critical

No direct impact

Protective devices

No direct impact

Critical to arc flash mitigation

Bonding and grounding

No direct impact

Critical to arc flash and electric shock mitigation

Ground fault circuit interrupter outlets

No direct impact

Critical to shock mitigation

Table II: Comparing examples of electrical equipment reliability differentiated by uptime and electrical safety impact

Widely recognized consensus standards relevant to electrical safety and electrical maintenance are just beginning to bring focus to reliability based on electrical safety needs. NFPA70E-2015 Standard for Electrical Safety in the Workplace emphasizes reliability for protective devices 7. NFPA70B-2016, Recommended Practice for Electrical Equipment Maintenance provides detailed guidance on maintenance of electrical equipment. Article 6.3 Identification of Critical Equipment provides an overview, but does not go in depth in methods to differentiate uptime vs. safety performance 8. IEEE 3007.2 Recommended Practice for Maintenance of Industrial and Commercial Power Systems was published in 2010, with expanded guidance on application of reliability centered maintenance 9. Collectively, these standards provide comprehensive guidance on maintenance of electrical equipment. There is some guidance on how to identify critical equipment, prioritize based on criticality and assess reliability requirements. However, there is not a strong connection to the body of knowledge on asset management systems, criticality analysis and risk assessment championed by organizations such as Society for Maintenance and Reliability Professionals, Reliabilityweb.com, and Association of Maintenance Professionals. Creating and nurturing collaboration with these organizations are important steps in managing the reliability of electrical equipment critical to electrical safety. There is a saying among some reliability engineers, “if everything is considered critical, then nothing is critical”. Criticality Analysis is an asset management tool that can help identify equipment critical to electrical safety and prioritize application of maintenance technologies and resources. The key question to help identify electrical equipment and systems critical to electrical safety is, “What equipment or system automatically prevents or limits risk of injuries from electric shock or arc flash?” For example, if the equipment in question is a motor, feeder cable, or power transformer, the answer is generally “no”. A failure would likely impact uptime, but would not jeopardize the mitigation of electrical injury risks. On the other hand, if the equipment provides short circuit protection critical to arc flash mitigation, the answer is “yes”.

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ROLE OF MANAGEMENT SYSTEMS STANDARDS RELEVANT TO ELECTRICAL SAFETY A management systems standard provides the blueprint, or framework, to help enable effective, robust and sustainable programs to assure sustainable continual improvement toward specific objectives. The objectives could be safety, quality, environmental stewardship, energy sustainability, or risk management. The difference between a program and a management system is that programs are administered at the operational levels of an organization. Management systems are initiated and monitored at the executive level of an organization 8. Examples of management systems standards include ISO 90000 Quality Management, ISO 14001 Environmental Management, OHSAS 18001 Occupational Health and Safety Management, ANSI Z10 Occupational Health and Safety Management, ISO 31000 Risk Management, and ISO 55000 Asset Management. These standards share a common framework to achieve the unique objectives aligned with each standard’s title. The common framework includes management leadership commitment, planning to achieve success, allocation of resources, implementation support, performance assessment, management review and continual improvement. These concepts are not addressed in electrical safety related standards such the National Electrical Code©, NFPA70E and NFPA70B. Understanding how to integrate the requirements of electrical safety related standards within the framework of management systems standards can help an organization maximize the return on its investment in improving its electrical safety and reliability programs. The electrical safety related standards are most effectively implemented when integrated within an organization’s management systems. NFPA70E-2015, Article 110.1(A) includes this informational note: Informational Note No. 2: ANSI/AIHA Z10, American National Standard for Occupational Health and Safety Management Systems, provides a framework for establishing a comprehensive electrical safety program as a component of an employer’s safety and health program.

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Safety Vol. 2 Aligned with the above statement in NFPA70E, a similar relationship linking electrical equipment maintenance & reliability programs with an asset management system standard could help optimize electrical reliability and electrical safety.

POTENTIAL IMPACT OF ISO 5500X ISO 5500X Asset Management published in 2014 consists of three parts: ISO 55000 Overview, Principles and Terminology, ISO 55001 Requirements, and ISO 55002 Guidelines for Application. The purpose of this standard is to enable an organization to achieve multiple objectives through effective and efficient management if its physical assets. For most organizations, the multiple objectives include uptime and continuity of operations and services, and safety to people, property and environment. ISO 5500X includes these requirements 10: ● Context of the Organization – the mission, vision and values of the organization ● Leadership – setting direction, assuring alignment with other management systems, assuring a coordinated approach to risk management ● Planning – planning the management system, establishing objectives, planning to achieve objectives ● Support – Providing necessary resources, developing competency in these resources, enabling availability of information, managing essential documents ● Operation – operation of the management system, not operation of individual assets ● Performance Evaluation – assessments, analysis, audits, management review ● Improvement – correcting non-conformities, preventive action, continual improvement The framework of ISO 5500X can enable the rigor and discipline needed for an organization to address voids and opportunities discussed in this paper. In particular, it can enable rigorous application of criticality analysis tools to identify Engineering Controls prone to hidden failure and application of measures to better assure functionality of equipment and devices critical to electrical safety. This framework establishes the foundation for management commitment necessary for sustainable and continual improvement for asset management, including those assets critical to electrical safety.

TRANSFORMING OPPORTUNITY TO REALITY Business and commerce are dependent on electrical technology for energy, control, data, and communications. In applying the concepts described in this paper, an organization can develop a better understanding and appreciation that managing its electrical safety program closely coupled with its reliability & maintenance program will derive benefits across a broad set of business perfor-

mance parameters that depend on defect free operation of electrical energy control and communications systems critical to operations. The performance parameters that can benefit from an effective electrical safety program include improved energy utilization, improved on time delivery, fewer environmental releases, optimum employee safety, improved raw material utilization, improved first pass yield, and increased operations uptime. Electrical specialists may not be expert in reliability & maintenance management systems. Traditional approaches to maintenance planning and prioritization may not identify equipment critical to electrical safety. Recognizing and understanding the role of engineering controls that reduce electrical injury risks hazards help optimize reliability critical to electrical safety. Criticality analysis is one of the most important elements in an asset management program, it is perhaps the most overlooked and misunderstood. Criticality analysis is key to solving this challenge of clarity on what is to be achieved, establishing priorities, and aligning and targeting resources 11. The opportunity and methods to establish management commitment, engage a multidiscipline team and achieve synergy with electrical safety and reliability improvement can be facilitated using the framework of ISO 5500X Asset Management. Exploring the answers to these questions may hold the key to more effective and sustainable performance: ● Has the organization established a management system to achieve reliability objectives? ● If so, how is electrical equipment included? ● Do any electrical maintenance personnel have accredited training in asset management, risk assessment, and criticality analysis? ● If not, how are those competencies applied to electrical equipment maintenance? ● How would you rate the collaboration and synergy among safety professionals, maintenance professionals, key members of management, and the electrical experts with respect to driving improvement in the electrical safety and the reliability & maintenance programs in your organization? How do you know if your electrical reliability program extends to include equipment and devices critical to electrical safety?

REFERENCES 1

Floyd, H.L., “I Need my Light Fixed!”, IEEE Industry Applications Magazine, vol 21, issue 4, p2, July/August 2015

2

Ray, Donald, Why is Criticality Analysis Important, retrieved from the internet December 12, 2015 at www.lce.com/ Why-is-Criticality-Analysis-important-1204.html

3

Floyd, H.L., Reliability for Electrical Safety, 2013 International Maintenance Conference 2013, December 10-13, 2013, Bonita Springs, FL

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4

Heid, K., & Widup, R., “Total Clearing Time of Protective Devices and Its Effect on Electrical Hazards”, Conference Record of 2009 IEEE IAS Electrical Safety Workshop, February 2009, St. Louis MO.

5

ANSI/AIHA Z10-2012, Occupational Health and Safety Management Systems, American Industrial Hygiene Association

6

Brauer, R., L., Safety and Health for Engineers, 2nd edition, p101, John Wiley & Sons, Inc., Hoboken, NJ

7

NFPA70E-2015, Standard for Electrical Safety in the Workplace, National Fire Protection Association, 1 Batterymarch Park, Quincy, MA

8

NFPA70B-2016, Recommended Practice for Electrical Equipment Maintenance, National Fire Protection Association, 1 Batterymarch Park, Quincy, MA

9

IEEE 3007.2-2010, IEEE Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, Institute of Electrical and Electronic Engineers, Inc., Piscataway, NY

10

O’Hanlon, T., et al, The (New) Asset Management Handbook, The Guide to ISO55000, 2015, ReliabilityWeb.com, Fort Myers, FL

11

Zach, T., Criticality Analysis Made Simple, 2014, ReliabilityWeb.com, Fort Myers, FL

H. Landis Floyd received his bachelor of science in electrical engineering from Virginia Tech in 1973. His more than 45-year career with DuPont focused on electrical safety in the construction, operation, and maintenance of DuPont facilities worldwide. His responsibilities included improving management systems, competency renewal, work practices, and the application of technologies critical to electrical safety performance in all DuPont operations, to achieve breakthrough performance in serious injury and fatality prevention. Landis is currently an adjunct faculty member in the graduate school of Advanced Safety Engineering and Management at the University of Alabama at Birmingham, where he teaches Electrical Systems Safety, Prevention through Design and Engineering Ethics. He is an IEEE Life Fellow, a professional member of American Society of Safety Engineers, a Certified Safety Professional, a Certified Electrical Safety Compliance Professional, a Certified Maintenance & Reliability Professional, a Certified Reliability Leader, and a registered professional engineer in Delaware. He served on the NEC Technical Committee from 1990 to 2014 and was a board member of the Electrical Safety Foundation International from 1994 to 2014. He has published more than 100 papers and articles and given more than 150 conference presentations on the practice of electrical safety. In 2001, Landis established Electrical Safety Group, Inc. in 2001

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UNITED STATES

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ALABAMA 1

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

ARKANSAS 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

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ARIZONA

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

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ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

CALIFORNIA 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

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ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

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Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

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Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

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Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

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Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

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Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

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Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

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Pacific Power e tin , Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

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Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

COLORADO 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

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Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

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Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

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Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

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RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

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Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

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Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

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RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

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CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

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CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

CONNECTICUT 45

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

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Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

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Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

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Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

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Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

ILLINOIS 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

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Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

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High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

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Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

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Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

GEORGIA 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

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FLORIDA 50

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C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

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ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

INDIANA 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

KENTUCKY

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

IOWA 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 MAINE www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 LOUISIANA www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

MARYLAND 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

NEW MEXICO 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

NEW YORK 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

151

152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

OHIO 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

NORTH CAROLINA

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

157

158

159

160

161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

OKLAHOMA 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

SOUTH CAROLINA 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

PENNSYLVANIA

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

OREGON

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

TENNESEE 181

182

183

184

185

186

187

188

189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] TEXAS www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

197

198

199

200

201

POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

206

207

208

209

210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

UTAH 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

WISCONSIN

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

VIRGINIA

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

WASHINGTON 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

242

243

244

Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: •

The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries.

•

NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

•

A Registered Professional Engineer will review all engineering reports

•

All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST).

•

The firm is a well-established, full-service electrical testing business.

Setting the Standard

VOLUME 1

TRANSFORMERS

SERIES III

HANDBOOK

TRANSFORMERS Vol. 1 HANDBOOK

SERIES III

Published By Sponsored by

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TRANSFORMERS VOLUME 1

Published by

InterNational Electrical Testing Association

TRANSFORMERS VOL. 1 TABLE OF CONTENTS The Overwhelming Need for Electrical Maintenance.............................................. 5 Glen Brown

Understanding Insulation Test Results of Transformers with a Grounded Electrostatic Shield.................................................................... 7 Michelle Ward

The Importance of a Periodic Maintenance Route................................................. 10 Lynn Hamrick

Field Testing of Arc Furnace Transformers........................................................... 14 Jim Macdonald

Reliable Demagnetization of Transformer Cores................................................... 19 Markus Pütter and Michael Rädler

DC Windings Resistance: Theory vs. Practice...................................................... 24 Charles Sweetser

Partial Discharge Testing Using the UHF Drainvalve Sensor + PD Smart or Using a Simple Survey Tool PDS 100 With the Same UHF Drainvalve................. 31 Karl Haubner

I Have A Lot of Numbers, What Do They Mean – Basic Interpretation of Two Winding Transformer Data......................................... 33 Keith Hill

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Are You Really Testing Your Instrument Transformers?............................................ 37 Michael Hancock

Partial Discharge Testing of Rotating Machines – Is it Science of Black Magic?........ 40 Vicki Warren

Consideration Testing Transformer Protection Schemes.......................................... 46 Nestor Casilla

I Know How to Add the Numbers – But What Is the Power Factor Telling Me?......... 50 Keith Hill

Water Distribution and Migration in Transformer Insulation Systems and Assessment of Paper Water Content................................................................... 56 Lance R. Lewand and David Koehler

Decision Sciences: Will This be on the Test?........................................................ 60 Nicholas Perjanik

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

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Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

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Transformers Vol. 1

THE OVERWHELMING NEED FOR ELECTRICAL MAINTENANCE NETA World, Fall 2013 Issue Glen Brown, Rimac Technologies This one may be from the Ripley’s Believe It or Not files, but it shows and proves that a knowledgeable technician with the confidence to believe in his equipment and skills can be invaluable. Recently, during an industrial plant shutdown, it became even clearer to me, as a technical person that our jobs are never done. The industry’s need for quality technical maintenance personnel is as important as it ever has been. During this project in the late evening, and after working a long, typical shutdown day, one of our crewmembers discovered a unique insulation measurement. During a routine insulation-resistance test on a 600 volt MCC, a short-to-ground was discovered--not uncommon but not good, or easy to explain, when the system was energized just moments before. The crew left the cables directly connected to the MCC for testing, including the cables in the test, due to the time constraints and the difficulty of removing the cables from the MCC and the main breaker feeding the MCC. The test was conducted at 1000 volts with all the MCC loads open. The results showed an almost dead short-to-ground which was concerning as the system was in service just prior to the testing with no indication of problems. No alterations had been made to the system during the test procedure other than de-energizing the equipment and isolating the MCC loads. We rechecked the loads on the MCC to ensure that all the disconnects were open and the main bus and cables were all that was involved in the test. We opened all the upper compartments to ensure that there were no additional connections to the bus, which would lead to our test results. It appeared as if some resistively grounded load was connected to the system. We suspected it was a load bank, heater, possibly a surge pack, or artificial neutral. Night was upon us and the client wanted the system put back into service since we had changed nothing and the system had been energized just prior to testing. It was hard to convince the client that there was a serious problem that deserved further investigation. After some discussion, the client indicated that he could get away without turning the unit area back on until the next day. The clients’s invitation was perfect for us because we could look at this with fresh brains in the morning after a hasty late meal and short hotel sleep, two of the many benefits of being a field service technician. The next morning we came in with a sense that we were going to tackle this with a fresh look. First step was to sectionalize, remove all cabling to isolate the problem and determine if it is with

the MCC or cable system. It was the cable. A digital volt ohmmeter was used to determine the value of resistance for this short circuit. The digital volt ohmmeter indicated a resistance value of about 5000 ohms phase-to-phase, and we were unable to get a reliable reading phase-to-ground, despite the short circuit with the insulation resistance meter….. strange to say the least? What could represent 5000 ohms in an electrical power system? It did not represent any load we could identify. We were all unsure as to what to do next; we could chase it down or let it go. It did not feel right to just let it go, but the client needed to understand this was something outside the norm. After some discussion, the client told us we must do everything we felt reasonable to try and find out what might be connected in the system that would cause such a strange reading. Through further investigation, we discovered the breaker that was supposed to be feeding the MCC on which we were working was mislabeled. This feeder had, in fact, been labeled incorrectly for many years, and even senior staff was unaware of this discrepancy. The potential hazard here is obvious, because failure to follow proper safety protocols (ensuring electrically safe work condition and testing before you touch) could lead to serious shock and/or burns or even death depending on the operating voltage and arc-flash hazard. To not have reliable breaker designation and a reliable single-line drawing is beyond comprehension in a post NFPA 70E/CSA Z463 world. We discovered still another problem upon questioning the lead electrician. We determined that a new MCC had been installed to replace an old one at sometime in the past. We took a look at the MCC again, and when all the cables were removed, we discovered that there was a parallel feed at the MCC. Only one set of three phase cables were connected at the MCC feeder breaker, but two sets of cables were connected at the MCC, a real stretch for single-line clarity. Where did those other cables go? After a brief search, the energized cable ends were found buried in the ground, inside the substation in a sand filled area next to the 600 volt feeder breaker compartment! The extra parallel cables from the MCC were terminated at the MCC, but only one set was connected at the feeder breaker. We could not determine how long the energized cable ends had been this way, but the site electrician said at least three years (since the MCC installation) and possibly much longer. The critical acknowledgement here is that with these energized cables

6 buried in the ground and the level of energy expended, as evidenced by the crystallization of the sand, a potential catastrophe was impending the entire time. Luck was a significant factor here as step and touch potential hazards were likely off the charts not to mention an imminent fault if the conductivity to ground or phase had been altered by a little moisture. To say no one was hurt and the techs involved in the investigation were successful in diverting a potential problem, would be a huge understatement in most books. I believe we earned our money that day. Let us consider some potential payback by the way of commercial consideration, something everyone understands—dollars. Some quick math would say amperes equals 600/5000 or 120 milliamperes (1.732) ~ 200 milliamperes continuous 3-phase load or about 120 watts. Over 3 years this equates to ~ 19000 hours give or take, 120 watts (19,000) is over 2 megawatts.! Simple math at about $0.10/kwh is about $228.00. This assuming that the ground resistance value is never changed by temperature, moisture levels, or other seasonal variables. Let’s be real here and realize the 9 Vdc battery in the digital volt ohmmeter and a 600 volt three-phase power source are not likely to yield similar reliable resistance values. Remember the 1000 volt insulation resistance meter indicated a dead short. The real number could easily be 10 or 100 times this, but the consequences of an injury could have been 1000’s of times again. By most measurements, this was a job well done and a feather in the cap of the field service crew. The customer usually has a budget for maintenance, and this money has to be expended in an efficient manner. In this case the value of an experienced team with leadership that cares about the final outcome and has a true interest in evaluating system condition proved invaluable. A less experienced crew lacking the benefit of NETA accreditation and training may have just noted this as a system anomaly and an unexplained reading. This condition could have gone on for many more years and possibly indefinitely. It pays to have a professional testing firm that is experienced, knowledgeable, and engaged in making your power system the best it can be. This is only a small example of system problems discovered and corrected during this shutdown. It was one of the most interesting, challenging, and highly visible shutdowns, as several annual shutdowns in the past had failed to raise any flags regarding the condition. This type of work and dedication to our craft raises the bar and instills confidence in our clients as to our abilities, not to mention guaranteed work for the foreseeable future. Finding these things is one of the reasons many of us are so dedicated to our field, and sharing with likewise dedicated professionals is a lot of fun. Glen Brown, President of Rimac Technologies, is a power system electrician [PSE] and a certified electrical technologist [CET] and has learned his trade working with various larger NETA firms in Western Canada.

Transformers Vol. 1

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Transformers Vol. 1

UNDERSTANDING INSULATION TEST RESULTS OF TRANSFORMERS WITH A GROUNDED ELECTROSTATIC SHIELD NETA World, Winter 2013 Issue Michelle Ward, Doble Engineering Company

INTRODUCTION A shielded transformer is a transformer that has a grounded electrostatic plate (shield) between the high-voltage and low-voltage windings (Figure 1). The grounded shield provides a low impedance path to ground by capacitive coupling which prevents unwanted high frequency signals contained in the source voltage from reaching the transformer secondary. This is valuable in protecting sensitive equipment from common-mode electrical noise and transients generated on the source side of the transformer. The shield is not always represented on a transformer nameplate. This can be very troublesome to a tester since test results for a shielded transformer will be very different compared to the expected nonshielded results.

Fig. 2: Dielectric representation of 2 winding Transformer with and without grounded electrostatic shield Test three insulation components of the two-winding transformer: CH, CL, and CHL. If a transformer has a grounded shield between the high- and low-voltage windings, the internal test circuits change. The figures below will illustrate the difference in circuits using the overall test for transformers with and without a grounded electrostatic shield.

Fig. 1: Nameplate representation of a 2 winding transformer with grounded electrostatic shield

BODY Figure 2 shows electrical representations of a two-winding transformer (A) and a two-winding transformer with an electrostatic shield (B). As shown in B of figure 2 the grounded shield provides a low impedance path to ground by capacitive coupling between it and the high- and low-voltage windings. The best way to test the insulation in a transformer is to break down the transformer into the smallest testable units. Doble does this by using test circuits or paths within the transformer and breaks the insulation testing to three separate sections: CH: The insulation between the high side winding and the tank wall.



CHL: Inter-winding insulation. The insulation between the low- and high-voltage windings.



CL: The insulation between the low-voltage winding and the core.

Fig. 3: Ground test configuration – measures current from energized winding to ground and interwinding current

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Transformers Vol. 1

Meas.

Test kV

mA

Watts

% PF corr

CH + CHL

10.005

36.135

0.938

0.26

1

9584.9

CH

10.004

14.768

0.376

0.25

1

3917.4

CHL(UST)

10.004

21.362

0.569

0.27

1

5666.3

21.367

0.562

0.26

1

5667.5

CHL

Fig. 4: Guard Test configuration – measures current from energized winding to ground and guards inter-winding current Looking at B of figures 3 and 4, the same insulation (CH+1/2 CHL) is measured for both the ground and the guard circuits. Figure 5 illustrates the third test circuit, the UST test circuit which is meant to test the CHL inter-winding insulation.

Fig. 5: UST test configuration – measures inter-winding current and guards current from energized winding to ground Now that there is an understanding of a shielded transformer and the test circuits, let’s look at some results. Below are test results of transformers with and without a grounded electrostatic shield. Table 1 has typical power factor results for a 2 winding transformer.

Corr Cap (pF) Fctr

CL + CHL

10.006

83.29

2.905

0.35

1

22093.1

CL

10.004

61.925

2.343

0.38

1

16426

CHL(UST)

10.004

21.364

0.571

0.27

1

5666.9

21.365

0.562

0.26

1

5667.1

CHL

Table 1: Unshielded transformer GE 161KV/13.2KV 61 MVA Table 2 shows the results for a transformer with a grounded electrostatic shield between the high and low side windings. Notice the mA, Capacitance and Watts values of the “CHL+CH” and “CH” and “CHL+CL” and “CL” tests are very similar (the mA are highlighted in the table). Also the mA and Watts values for all of the “CHL” results are very low. It is also apparent the power factor for the “CHL (UST)” results are low and it is not uncommon to see a negative power factor for any CHL value.

Meas.

Test kV

mA

Watts

CH + CHL

10

176.8

6.445

CH

10

175.8

6.409

CHL(UST)

10

1.079

CHL

% PF corr

Corr Cap (pF) Fctr 0.75

46918

0.27

0.75

46631

0.014

0.1

0.75

286.3

1

0.036

0.27

0.75

287

0.75

287

CL + CHL

10

174.6

9.246

CH + CHL

10

173.5

9.241

0.4

0.75

46041

CH

10

1.079

0.014

0.1

0.75

286.3

CHL(UST)

10

1.1

0.005

0.04

0.75

287

Table 2: Transformer with grounded electrostatic shield GE 161KV/13.2KV 76 MVA

Transformers Vol. 1 CONCLUSION Power-factor test results of a two-winding transformer with a grounded electrostatic shield will differ greatly from a two-winding transformer without a shield. You will see that the [CH +CHL and CH] test results are almost equal and also the [CL+CHL and CL] test results are almost equal. The CHL values are very low and can even be negative. These results can be confusing if you do not know that you are testing a shielded transformer. Some nameplates do not show the grounded electrostatic shield. You now know what results of this type indicate. If you know that the transformer is shielded the above results will be expected.

REFERENCES 1

IEEE Std C57.110-1998 “IEEE Recommended Practice for Establishing Transformer Capability When Supplying Nonsinusoidal Load Currents”

2

I EEE Std 519-1992 IEEE Recommended Practices & Requirements for Harmonic Control in Electrical Power Systems

Michelle Ward received a Bachelor of Science in Electrical Engineering from Northeastern University in Boston, Massachusetts. She has worked at Doble Engineering Company, Watertown, Massachusetts for nine years with four years at her current position of Senior Client Service Engineer. Michelle is Secretary of Doble Engineering’s Bushings, Insulators, and Instrument Transformers Committee and is a member of the IEEE Power Engineering Society.

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Transformers Vol. 1

THE IMPORTANCE OF A PERIODIC MAINTENANCE ROUTE NETA World, Winter 2013 Issue Lynn Hamrick, Shermco Industries

Physical Inspections should be performed on electrical equipment. The most cost-effective form of inspection is a periodic walkthrough to evaluate general equipment condition and changes to operating parameters. For critical equipment, this should take the form of a periodic maintenance route to ensure that an adequate physical inspection is performed. While performing the inspection, the inspector should be aware of the visual evidence associated with installation errors, equipment subassembly failures, poor equipment condition, overheating, and corona. Further, where indicators of physical parameters are available, the inspector should regularly monitor and trend status and other available data for system condition.

BACKGROUND – TRANSFORMER MAINTENANCE ROUTE Liquid-filled transformers are a typical example of critical equipment that should have a specific maintenance route. Most liquid-filled transformers have liquid level, temperature, and pressure indicators. These should be monitored periodically to ensure that the transformer is operating within acceptable parameters. In addition, the route should include inspections for oil leaks and spills. Most transformers have an oil temperature gauge that measures the actual top oil temperature. Top oil temperatures should be routinely observed to see whether the transformer is operating within normal temperature limits. For temperature, the level of the high temperature indicator should be noted and reset. For an OA cooling class transformer, a typical temperature of 55° C or 65° C (131° F or 149° F, respectively) is stated as the operating temperature limit of the windings. It should be noted that the top oil temperature is probably lower than the winding temperature. A photograph of a typical oil temperature gauge is provided in Figure 1.

Fig. 1: Transformer temperature gauge Most transformers also have a pressure gauge that measures the pressure of the nitrogen blanket above the oil. The gauge usually indicates negative or positive pressure. The pressure can vary from slightly negative to slightly positive due to ambient temperature and operating conditions. For sealed transformers, it is recommended that the pressure always be maintained at a slightly positive pressure. This is indicative of a proper seal and also ensures that moisture from the air does not leak into the nitrogen-filled gap at the top of the transformer. A photograph of a typical oil pressure gauge is provided in Figure 2.

Fig. 2: Transformer pressure gauge

11

Transformers Vol. 1 An oil level gauge is also provided so that the correct oil level can be maintained. There is usually a mark on the gauge that indicates the 25° C level, which is the proper oil level for the transformer at that temperature. Maintaining the proper oil level is extremely important because if the oil level falls below the level of the radiator inlet, flow through the radiator will cease and the transformer will overheat. A very low oil level can also expose energized and current-carrying components that are designed to operate in oil and could result in overheating or an electrical flashover. If the oil level is too high, it could cause over-pressurization as the oil expands when heated due to heavy loading conditions. A photograph of a typical oil level gauge is provided in Figure 3

Fig. 3: Transformer level gauge When combined with periodic oil sampling and IR surveys, this maintenance route can be very useful in identifying issues with a transformer before the issues become major problems resulting in a catastrophic failure of the transformer. The case below is a good example of this.

CASE STUDY – TRANSFORMER MAINTENANCE ROUTE

els are so high. The transformer has been operating under these conditions for the last one to two years with no trending up of the other key gases. In an effort to secure more information on the transformers without a shutdown, it was suggested that an IR survey be performed of the outside of the transformers in an effort to adequately understand the problems. With a proper IR survey of the outside of the transformer, an experienced and qualified worker can evaluate the natural cooling aspects of the transformer as well as the oil level within the transformer.

Fig. 4: Typical transformer IR survey – radiator As can be seen in Figure 4, a transformer with a correctly operating, natural-circulation cooling system will have a typical heat signature of the radiators with a gradual temperature rise from the bottom to the top of the cooling fins. The oil level will also be above the top of the tubes of the radiators for proper oil circulation.

While performing a maintenance route for the transformers at a large industrial company, a maintenance worker noted that the oil temperature gauge for two of the transformers (designated A and B for this discussion) had a higher than normal high oil temperature indication of between 45° C and 50° C. All other operating indications for both transformers were in the normal ranges. An investigation of the cause of these potential problems was initiated. A review of the most recent oil sample reports indicated no problem for Transformer A. However, for Transformer B, higher than normal CO2 levels suggested an overheating condition. The insulation type for the transformer has a rating of 65° C.  Trending of the past routing information for Transformer B showed that the Top Temp for Transformer B was typically 50° C. This temperature was at least 10° C higher than any other transformer.  This higher operating temperature is probably why the CO2 lev-

Fig. 5: Typical transformer IR survey – fan motor

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Transformers Vol. 1

The IR survey can also be useful in evaluating other equipment associated with the transformer cooling system. Figure 5 is indicative of a correctly operating cooling fan that supports the oil cooling features of the transformer. Note that the fan motor is running and that the cooling fins also have the correct temperature signature for natural circulation of the oil.

in the cooling fins. At the next available outage, the transformer was leveled and oil was added to ensure correct oil circulation was restored.

One of the photographs that resulted from the IR survey of transformer A is provided in Figure 6. The outside skin temperature is 20° to 30° F above the other transformers at 121° F.  It appears that there is oil circulation, but the cooling fan is not running.  Transformer cooling fans are controlled with thermostats such that they turn on and off based on the temperature settings. Further investigation revealed that the thermostat for the fan was not operating correctly. Replacing the thermostat and implementing the proper temperature settings resolved this transformer issue. More importantly, an outage was not required to implement corrective action for transformer A. Fig. 7: Transformer B – cooling problem Based on the results of this investigation, more attention is being provided to the performance and review of periodic maintenance routes for transformers. Additionally, IR surveys of the outside of their transformers has been added to the transformer maintenance route. Further, the maintenance workers have been trained in correct performance of the transformer maintenance route, oil samples, and IR surveys as well as the collective review of the information provided through these activities.

SUMMARY Fig. 6: Transformer A – fan motor not running One of the photographs that resulted from the IR survey of transformer B is provided in Figure 7. The outside skin temperature is ~ 30° F above the other transformers at ~127° F.  This transformer has 3 sets of cooling radiators, west, north and east. Figure 7 is a photograph of the east and north cooling fins.  Based on the IR survey, the oil does not appear to be circulating through the north radiator and is minimally circulating through the west radiator.  There was oil circulating through the east radiator, except for the northern most set of tubes.  Further investigation revealed that the transformer was not level.  The transformer base had settled such that the south-east corner of the transformer was two or three inches lower than the northwest corner. This problem with the transformer being not level resulted in the level of the oil for the west and north sets of fins being inadequate to maintain proper natural circulation of the oil

This case study suggests the following key attributes for implementing a periodic maintenance route, particularly for transformers: ●● Periodic maintenance routes are a valuable tool for monitoring and maintaining critical electrical equipment health. ●● Information accumulated through a periodic maintenance route and other predictive maintenance activities can provide indicators of impending equipment problems and, thus, be used to accommodate cost-effective corrective action and proper maintenance planning. ●● Correct interpretation of information by qualified workers is critical to the success of any maintenance program. ●● Timely review of available maintenance data is also critical to the success of any preventive maintenance program.

Transformers Vol. 1 Lynn Hamrick brings over 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. Lynn is a Professional Engineer, Certified Energy Manager and has a BS in Nuclear Engineering from the University of Tennessee.

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Transformers Vol. 1

FIELD TESTING OF ARC FURNACE TRANSFORMERS NETA World, Fall 2013 Issue Jim Macdonald, Doble Engineering Company

Arc furnace transformers are found in industrial settings to step down voltage to provide power for arc furnaces used for production of steel and iron. These transformers can come in a variety of types and configurations. Often the secondary may have multiple windings per phase that are in parallel with each other. In many cases, each end of each individual secondary winding is brought out through the tank wall to a low voltage bushing, and a delta connection of the windings is made externally to the transformer via a bus delta enclosure. This paper will describe some of the issues these unique configurations can pose when testing in the field and what options one has when performing testing on this apparatus.

OVERALL TEST The first step is to isolate the high-voltage and low-voltage windings from any bus and cable connections and make sure the transformer is correctly grounded. If multiple separate windings per phase are present on the secondary and each end of each individual winding is brought out to a bushing, the most direct way to perform the overall test is to electrically short circuit all secondary bushings together (in addition to shorting the high-voltage bushings together). Then perform the test the same way a standard two-winding transformer would be tested. However, keep in mind that it is always ideal, if possible, to break an insulation system down into the smallest components possible. Often a problem could be masked when taking a measurement of a number of insulation components lumped together, while it may show up when solely testing one of the individual components. Breaking the insulation into the smallest portions possible will also allow one to troubleshoot a bad reading obtained while testing the transformer as a two-winding transformer with insulation components lumped together. Below is a detailed description of how to break up the insulation into smaller pieces. The example shown in Table 1 and Figures 1-3 is a transformer with two separate windings per phase on the secondary (total of six low voltage windings). Each end of these six windings is accessible and brought out to an individual bushing. The six low-voltage windings have been completely separated from each other so that the low-voltage side is no longer delta connected (the delta connection external to the transformer has been removed). The first thing one must do is check for con-

tinuity between secondary bushings to identify which pair of bushings forms a winding. Adjacent low-voltage bushings may not always be the ends of the same winding. Once this has been done, each secondary winding should be electrically shorted individually (in addition to electrically shorting the high-voltage bushings together). In the following table, the Energize column shows which winding will be energized with the test set during the test. The two low-voltage measurement leads are placed on the windings under the Guard, GND and UST columns respectively. UST stands for ungrounded specimen test and is referring to a measurement being made to an ungrounded winding with the low-voltage test lead. GND refers to the windings that must be grounded, and Guard refers to any windings that are not included in the measurement. Any current flowing to a winding under the Guard column bypasses the meter in the test set (via the low-voltage test lead) and is not included in the measurement. Note that in order to guard or ground several windings at once, additional wire must be used to electrically short these windings together.

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Transformers Vol. 1

ENERGIZE

GUARD

UST

GND

INSULATION MEASURED

TEST MODE

H

U+V+W+X+Y+Z

-

-

CH

GST-Guard

H

-

U

V+W+X+Y+Z

CHU

UST

H

-

V

U+W+X+Y+Z

CHV

UST

H

-

W

U+V+X+Y+Z

CHW

UST

H

-

X

U+V+W+Y+Z

CHX

UST

H

-

Y

U+V+W+X+Z

CHY

UST

H

-

Z

U+V+W+X+Z

CHZ

UST

U

H+V+W+X+Y+Z

-

-

CU

GST-Guard

U

-

V

H+W+X+Y+Z

CUV

UST

U

-

W

H+V+X+Y+Z

CUW

UST

U

-

X

H+V+W+Y+Z

CUX

UST

U

-

Y

H+V+W+X+Z

CUY

UST

U

-

Z

H+V+W+X+Y

CUZ

UST

V

H+U+W+X+Y+Z

-

-

CUZ

GST-Guard

V

-

W

H+U+X+Y+Z

CVW

UST

V

-

X

H+U+W+Y+Z

CVX

UST

V

-

Y

H+U+W+X+Z

CVY

UST

Fig. 3: Test setup for line #2 from table 1, UST Test

V

-

Z

H+U+W+X+Y

CVZ

UST

W

H+U+V+X+Y+Z

-

-

CW

GST-Guard

W

-

X

H+U+V+Y+Z

CWX

UST

W

-

Y

H+U+V+X+Z

CWY

UST

W

-

Z

H+U+V+X+Y

CWZ

UST

X

H+U+V+W+Y+Z

-

-

CX

GST-Guard

X

-

Y

H+U+V+W+Z

CXY

UST

X

-

Z

H+U+V+W+Y

CXZ

UST

Y

H+U+V+W+X+Z

-

-

CY

GST-Guard

While breaking down the insulation into smaller portions can be advantageous, it will add more complexity to testing a transformer. Multiple additional tests will be added to the test procedure for each separate individual winding that is accessible. In some cases, this can add many steps to the procedure, as some arc furnace transformers can have as many as 12 low-voltage windings (four parallel windings per phase). Since it can be more complex to test each individual insulation piece, it is generally accepted to test an arc furnace transformer with multiple separate accessible windings as a two-winding transformer. If a problem is shown while performing this test, then the insulation pieces can be broken down further and tested to help identify where the problem may lie.

Y

-

Z

H+U+V+W+X

CYZ

UST

Z

H+U+V+W+X+Y

-

-

CZ

GST-Guard

Table 1: Test procedure for a seven-winding transformer (six completely isolated secondary windings – two low-voltage windings per phase)

Fig. 1: Transformer from Table 1 with six completely isolated windings on the secondary

Fig. 2: Test setup for line #1 from table 1, GST-Guard Test

ANALYSIS Regardless of how many windings one chooses to include in the test procedure, the analysis is similar to a standard two-winding transformer. Any significant changes in capacitance and power factor should be investigated. Currently there is not sufficient test data available to conduct a comprehensive tabulation of power

16

Transformers Vol. 1

factors for arc furnace transformers. It is the author’s recommendation to use the generally accepted power-factor limits of power transformers for both the high-voltage winding insulation and interwinding insulation (less than 0.5%). It is not uncommon to have higher power factors for the low-voltage winding insulation. In many cases the low-voltage winding insulation may have elevated power factors due to the multiple low-voltage bushings connected to the low-voltage windings. These low-voltage bushings are often made of a solid dielectric which may exhibit higher power factors than an oil impregnated paper condenser type bushing.

HIGH-VOLTAGE OPENCIRCUIT TEST

SFRA

SHORT-CIRCUIT TEST

Three sets of SFRA measurements are to be performed: highvoltage open circuit traces, short-circuit traces, and low-voltage open circuit traces. These measurements can be performed in two ways.

Red Lead

H3 H1

All low-voltage terminals shorted together

Option 1: When performing these measurements, the secondary should be in the same configuration as it is when in service. If the low-voltage side is an open delta, as shown in Figure 4, but is normally closed through an external bus delta enclosure, then the delta should be closed by electrically shorting the appropriate bushings. Additionally, one must ensure that any windings that are normally in parallel during service are connected in parallel by electrically shorting the appropriate bushings. It is very important to be careful and very consistent when electrically shorting the low-voltage side of the transformer in order to get representative traces for future comparison. As shown in Figures 5 and 6, the low-voltage side can have many bushings placed side by side. As a result, it can be difficult to electrically short the low-voltage side, so that the appropriate windings are in parallel and the delta is closed, without electrically shorting individual windings inadvertently.

H1 H2

All low-voltage terminals shorted together

H3 H2

All low-voltage terminals shorted together

A measurement across each high-voltage phase will be taken for the high-voltage open circuit traces, and a measurement across each low-voltage phase will be taken for the low-voltage open circuit traces. Any bushings not under test and not electrically shorted to configure the secondary properly are left floating during open circuit measurements. When performing the short circuit traces, simply electrically short all the low-voltage bushings together. Then take a measurement across each high-voltage phase. Option 2: A second option when performing the open circuit tests is to leave the low-voltage windings completely isolated from each other. In this case, one must take an open circuit measurement across each individual low-voltage winding. It is important to document how one performs the test to ensure future tests are performed the same way for comparison. It is recommended for an acceptance test to get a baseline set of measurements for both options described above. For routine testing, it is recommended to test using option 1. Below is an example of the actual test connections for the transformer shown in Figures 4-6 with the secondary in its in-service configuration.

Red Lead

Black Lead

Shorted Terminals

H3

H1

*X4-X2, X5-X3, X6-X1

H1

H2

*X4-X2, X5-X3, X6-X1

H2

H3

*X4-X2, X5-X3, X6-X1

*Delta is now closed. Additionally, bushings may need to be shorted to put separate windings per phase into parallel with each other.

Black Lead

Shorted Terminals

LOW-VOLTAGE OPENCIRCUIT TEST Red Lead

Black Lead

Shorted Terminals

X5-X3

X6-X1

*X4-X2, X5-X3, X6-X1

X6-X1

X4-X2

*X4-X2, X5-X3, X6-X1

X4-X2

X5-X3

*X4-X2, X5-X3, X6-X1

*Delta is now closed. Additionally, bushings may need to be shorted to put separate windings per phase into parallel with each other.

ANALYSIS The methodology for the analysis of an arc furnace transformer is the same as any other transformer. It is best to compare traces to a baseline set of traces for the transformer. Shifts in resonant frequencies and significant changes in the amplitude of a trace at a given frequency should be investigated. If no baseline trace is available, the next alternative option is to compare the traces to a similar unit of the same manufacturer. Lastly, a comparison amongst phases is made on the current set of traces.

17

Transformers Vol. 1 EXCITING CURRENT

Exciting current tests are performed the same way one would perform these tests on a standard two winding transformer. Test connections are made at the high-voltage side of the transformer and all other bushings are left floating. Below is a description of the test connections for the transformer shown in Figures 4, 5, and 6. Fig. 4: Vector diagram on an arc furnace transformer nameplate

High-Voltage Hook Low-Voltage Lead

Ground

H3 H1

H2

H1 H2

H3

H2 H3

H1

ANALYSIS Results that are typical for a standard two winding transformer apply here. In general a pattern of two similar high readings and one lower reading should be obtained for both current and watts readings on a given tap position for an inductive specimen. Fig. 5: Physical layout on the nameplate showing the low-voltage arrangement

WINDING RESISTANCE Winding resistance is performed on the high-voltage side by simply taking a measurement across each high-voltage phase. There are many different possible ways to perform winding resistance on the low-voltage side based on different configurations. Winding resistance can be performed across each individual winding if there are multiple individual windings accessible per phase. If multiple windings are connected in parallel, but the delta is open, one can perform a winding resistance measurement across each phase with multiple windings in parallel. If the delta is closed, winding resistance can be performed as well. It is important to make sure to document how one is performing the test and stay consistent with previous test methods to ensure comparison of similar data. Below is an example of how to perform the test on the transformer in Figures 4, 5, and 6, assuming one has taken the necessary steps in electrically shorting the appropriate bushings on the low-voltage side to ensure multiple windings per phase are connected in parallel and that the delta connection has been made.

HIGH-VOLTAGE WINDING MEASUREMENT Positive Polarity Current and Voltage Leads H3 H1 H2 Fig. 6: Low-voltage bushings showing multiple windings brought out in an open delta arrangement

Negative Polarity Current and Voltage Leads H1 H2 H3

LOW-VOLTAGE WINDING MEASUREMENT Positive Polarity Current and Negative Polarity Current Voltage Leads and Voltage Leads X5-X3 X6-X1 X6-X1 X4-X2 X4-X2 X5-X3

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Transformers Vol. 1

ANALYSIS Results should be comparable among phases and compared to previous results. Depending on the standard, a deviation of less than 1 to 5 percent is considered acceptable [1,2].

LEAKAGE REACTANCE The per phase test should be performed on arc furnace transformers. The per phase test is performed to get a comparison among phases and to use as a baseline for comparison of future tests to determine winding deformation. When performing the per phase test, all separate individual windings per phase on the lowvoltage side must be connected in parallel and the delta must be closed. Three measurements are then made across the high-voltage phases, similar to how this test is performed on any other transformer. Only one low-voltage phase is electrically shorted during each measurement. The phase that is electrically shorted corresponds to the same phase that is being measured on the high voltage side. Below an example of the test connections is shown for the transformer in Figures 4, 5, and 6.

PER PHASE TEST Positive Current Negative Current Shorted Terminals and Sense Leads and Sense Leads H3

H1

*X5-X3-X6-X1, X4-X2

H1

H2

*X4-X2-X6-X1, X5-X3

H2

H3

*X4-X2-X5-X3, X6-X1

*Delta is now closed, but all three phases are not shorted together. Additionally, bushings may need to be shorted to put separate windings per phase into parallel with each other.

ANALYSIS The per phase test is performed as part of an acceptance test and performed for subsequent tests as well. Deviation from previous readings of more than two percent should be investigated as well as a three percent deviation from the average of all three per phase readings.

REFERENCES IEEE Guide for Diagnostic Field Testing of Electric Power Apparatus-Part 1: Oil Filled Power Transformers, Regulators, and Reactors, IEEE Std 62-1995 1

Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems, ANSI/NETA MTS20011 2

Jim Macdonald is a Client Service Engineer with Doble Engineering Company. Prior to joining the Doble team in April 2010, he worked for a testing company in the northeast performing electrical testing in substations, as well as commissioning of power plants. He graduated from the University of Massachusetts – Amherst with a degree in Electrical Engineering.

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Transformers Vol. 1

RELIABLE DEMAGNETIZATION OF TRANSFORMER CORES NETA World, Summer 2014 Issue Markus Pütter, Michael Rädler, OMICRON electronics GmbH

Whenever a power or distribution transformer is isolated from the power system, it is very probable that residual magnetism remains in the core due to the phase shift. However, residual magnetism also occurs when performing winding resistance tests. Since manufacturers use these measurements in their routine testing and these tests are typically performed for on-site condition assessment, transformers can be regularly influenced by the effect of residual magnetism.

The highest inrush current occurs when the voltage is applied near the zero crossing and the polarity of the voltage is applied in the same direction as the residual magnetism in the core or the corresponding limb (Figure. 2, [Formulas 1-3]). If the core reaches saturation, the transformer’s inductance is greatly reduced. The current is now only limited by the winding resistance on the high-voltage side and the impedance of the connected transmission line.

Residual magnetism leads to high inrush currents, which put a large and unnecessary load on the transformer. A great number of diagnostic measurements are also affected by residual magnetism making it is difficult to obtain a reliable condition assessment of transformers. Therefore, demagnetizing the transformer is recommended before reenergizing or performing diagnostic measurements. Within the last few years, the first testing devices that allow practical demagnetization of transformers on-site have been launched.

INFLUENCE OF RESIDUAL MAGNETISM ON INRUSH CURRENT When a transformer is reenergized, an inrush current occurs that can greatly exceed the nominal current. If the transformer core still contains residual magnetism, the first peak current can reach the level of the short-circuit current. These high currents can cause undesirable effects, such as mechanical deformation of the windings, incorrect triggering of protection equipment, increased stress on the installation, and voltage dips in the grid. Only the ohmic components, such as the winding resistance, are capable of attenuating the high inrush currents to a stable level within just a few cycles (Figure. 1).

Fig. 2: Effects of residual magnetism on inrush current

INFLUENCE OF RESIDUAL MAGNETISM ON ELECTRICAL ROUTINE AND DIAGNOSTIC MEASUREMENTS The residual magnetism can be as high as 90 percent of the magnetic flux density (B) during operation. In the event of a fault or during routine testing, various electrical diagnostic techniques can be used for analyzing the condition of a transformer. Residual magnetism influences certain diagnostic measurements in such a way that a reliable and meaningful analysis becomes nearly impossible. Particularly, when performing exciting current measurements, the magnetic balance test, or sweep frequency response analysis for localization of faults in the core, residual magnetism may have such a negative effect that results become unsolvable.

Fig. 1: Attenuating the inrush current over time

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Transformers Vol. 1

INFLUENCE ON EXCITING CURRENT MEASUREMENTS Measuring the exciting current can provide evidence for potential faults in the core. Faults in the core lead to an increasing exciting current. If reference values for the exciting current are available, these can be used for the assessment. Since exciting currents do not have a linear behavior to the applied voltage, measurements for comparison with the reference values must be performed at the same voltage. The assessment is performed based on a typical pattern of a three-limb or five-limb transformer or on reference measurements if they are available. The magnitude of the magnetization current depends on the length of the magnetized path. This is virtually identical for the windings on the outer limbs, but lower for the winding on the middle limb (Figure. 3). For example, if there is residual magnetism on the middle limb, this can easily lead to incorrect interpretations and a reliable diagnosis becomes impossible (Figure. 4).

This should result in a typical pattern. For example, if a voltage of 100 V is applied to the winding on the middle limb, the measured voltages on the other windings should each display a value of approximately 50 V. This can be explained by the two magnetic paths with the same length. Applying a voltage to one of the windings on the outer limbs results in a different pattern because the magnetic paths have different lengths. Deviation of the recorded pattern from the anticipated pattern indicates either problems in the core or undesirable effects of residual magnetism.

INFLUENCE ON SWEEP FREQUENCY RESPONSE ANALYSIS MEASUREMENTS The sweep frequency response analysis (SFRA or FRA) uses frequency response analyses to describe the dynamic characteristics of an oscillating network based on its input and output signals. The SFRA measurement method is described in IEC 60076-18 and IEEE C57.149-2012 and has become increasingly accepted as a diagnostic method. A transformer reflects such an oscillating system, consisting of various series and parallel resonances with corresponding inductances (L), capacitances (C), and resistances (R). When one parameter is changed, such as the main inductance due to a core problem or the geometric shift of a winding, one or more characteristic resonance points is also displaced or shifted.

Fig. 3: Magnetizing current of a demagnetized transformer

Every electrical network has a unique frequency response, its so-called fingerprint. Interpretation of an SFRA measurement is based on a comparison of measurements, for example with the initial fingerprint or with other transformers of the same type. The plot of a fingerprint should not change throughout the entire life cycle of a transformer. Therefore, all influences that could affect SFRA measurements must be avoided as they could lead to misinterpretation of the obtained test results. Since residual magnetism influences the frequency response particularly at lower frequencies where the magnetization inductance dominates the response, it is vital to ensure that the transformer has been demagnetized before performing the measurement. Meanwhile, because of this pronounced and well understood influence at the lower frequencies, an SFRA measurement is effective in verifying residual magnetism.

Fig. 4: Magnetizing current with magnetized middle limb

INFLUENCE ON THE MAGNETIC BALANCE TEST The magnetic balance test, (i.e., a test of the flux ratio), is appropriate as a routine electrical field test and as an additional diagnostic method when a fault is suspected in the core. In the magnetic balance test, ac voltage is applied to a winding and the induced voltage is measured on the two other phases.

The SFRA measurement reflects the main inductance through the first resonance points. Figure. 5 shows the typical resonance points of a three-limb transformer’s main inductance. Two significant parallel and series resonance points can clearly be seen on the outer windings. This can be ascribed to the two magnetic paths with different lengths. In comparison with this, the winding on the middle limb displays only one characteristic single resonance point.

21

Transformers Vol. 1 THE ART OF ACCURATE DEMAGNETIZATION

There are various approaches for electrical demagnetization. One of these is to reduce the voltage with respect to time in predetermined steps. Small distribution transformers and large power transformers have very different hysteresis parameters. The disadvantage of this approach is that it takes a long time to ensure that both types of transformers can be reliably demagnetized using the same procedure.

Fig. 5: Typical resonance points of a three-limb transformer’s main inductance As previously explained for the inrush current, the inductance changes depending on the degree of core magnetization, whereby Ldemag > Lmag. A resonance point comprises a network of capacitances and inductancesand can be described using Formula 4. The lower the inductance becomes, as reflected by a state of higher residual magnetism, the more the resonance points move toward higher frequencies.

To counteract this problem, the current can be additionally triggered while the test is still running to start the next hysteresis cycle. However, since the magnetization current increases very rapidly when the transformer core reaches saturation, this process is fairly inaccurate. Various experiments have shown that small transformers, particularly, become re-magnetized during the final cycle, which leads to high inrush currents at energization. Demagnetization based on the measurement of the magnetic flux has proven to be the safest and most efficient approach, as it works reliably with both small and large transformers. However, this approach places very strict measuring requirements on the test equipment as the voltage needs to be continuously measured over time and the integral of voltage with respect to time calculated. [See Formula 5]. It is important to avoid any secondary hysteresis during demagnetization. The occurring residual magnetism can lead to an apparent demagnetization.

DEMAGNETIZATION MEASUREMENT PROCEDURE

Fig. 6: Demagnetization using a sinusoidal signal Demagnetization of single-phase and three-phase transformers can be performed in a similar way. When working on a threephase transformer, it is important to consider that magnetic coupling takes place between the phases. Therefore, the phase or limb used during the demagnetization procedure is extremely important and deliberately chosen. It also makes sense to use the high-voltage side for demagnetization as there are more turns associated with this winding to generate the magnetic flux. Hence, the total time for demagnetization can be reduced. Experiments have shown that the middle limb is the most suitable for demagnetization with a single-phase source. Thereby, the flux is distributed symmetrically over the two outer limbs. To determine which winding is associated with the middle limb in a delta winding, the transformer’s vector group is required.

Since the voltage and thereby also the magnetic flux of the main inductance LH cannot be measured directly, this voltage needs to be calculated (Figure. 7, [Formula 6]). Therefore, the winding resistance R must be measured in advance and the voltage drop of the winding resistance then subtracted from the measured voltage. Formula 7 shows the calculation of the magnetic flux on the main inductance. Thereby фR(0) represents the initial flux, which corresponds to the residual magnetism.

Fig. 7: Simplified equivalent electric circuit for the measurement procedure The test equipment for demagnetization is very simple. If a switchbox is used, rewiring is not necessary after measuring transformer’s ratio or winding resistance. The transformer’s vector group must be known and the test current chosen. Then the procedure can reduce the residual magnetism to virtually zero.

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Transformers Vol. 1

The core can be saturated in both directions. The specific hysteresis parameters per transformer are then determined and the initial flux is calculated. On the basis of these parameters, an iterative algorithm is then used to change both the voltage and the frequency. While this is taking place, the test equipment is constantly measuring the flux ф in the core. Using multiple iterations, the core is demagnetized to below 1 percent of its maximum value. Following the demagnetization procedure, several magnetic domains revert back into their preferred orientation. This procedure is also referred to as magnetic viscosity. The effect can be determined when performing demagnetization once again, although it is actually negligible and therefore is not really important in practice.

Phase A

Phase B

EXAMPLE BASED ON A 350 MVA TRANSFORMER A 350 MVA-YNyn0 power transformer manufactured in 1971 and rated 400/30kV was tested. For verification of state purposes, SFRA measurements were conducted. The transformer’s condition was recorded immediately after removing it from service with an initial SFRA measurement. Subsequently, a dc winding resistance measurement was carried out on phase B, (which was wound on the middle core limb), and another SFRA measurement was taken. Lastly, the transformer was demagnetized using the previously described method and checked by performing a final SFRA measurement. The results after the demagnetization procedure are shown in Table 1.

Table 1: Results following demagnetization of the 350 kV transformer When comparing the SFRA results of the individual phases, one can see that the transformer displays residual magnetism after being isolated from the power system (Figure. 8). After the demagnetization procedure, all resonance points moved towards lower frequencies as expected, and the typical SFRA pattern of a threelimb transformer can be seen. The transformer can therefore be considered as demagnetized.

Phase C

Fig. 8: Phase comparison of the SFRA results with different remanence conditions

CONCLUSION This article highlights the importance and the effect of residual magnetism. It should also increase the awareness of the associated risks with reenergizing transformers after an outage. Within the last few years, the first testing devices have been developed to allow reliable on-site demagnetization of transformers without any major additional effort. Demagnetized transformer cores minimize the risk to personnel and equipment during installation. The SFRA measurement method is described in IEC 60076-18 and IEEE C57.149-2012 and has become increasingly accepted as a diagnostic method. To gain reliable and reproducible measurement results, we recommend demagnetizing the transformer core before performing SFRA measurements.

Transformers Vol. 1

Markus Pütter is product manager for OMICRON electronics GmbH, Austria. He has 14 years of experience in the field of power transformer testing. Markus received a Dipl-Ing. in Electrical Engineering from the University Paderborn in 1997. Michael Rädler (November 27, 1987) works for OMICRON electronics GmbH as a Product Manager for testing and diagnostic solutions for primary assets, mainly focusing on power transformer applications since January 2008. He graduated at the Federal Higher Technical Institute in Bregenz, Austria with focus on electrical engineering.

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Transformers Vol. 1

DC WINDINGS RESISTANCE: THEORY VS. PRACTICE PowerTest 2013 Charles Sweetser, OMICRON electronics Corp.

ABSTRACT

MEASUREMENTS

DC Winding Resistance is a simple concept that relies on the fundamental application of Ohm’s Law. DC Winding Resistance is a powerful tool for determining continuity in power transformer winding circuits; specifically, connections and tap changer contacts. However, performing DC Winding Resistance tests often presents several technical difficulties that must be overcome. The magnetizing inductance of power transformers must be removed through saturation of the core steel. To accomplish saturation, DC voltage or DC current must be applied or injected, respectively. The magnitude of DC signals will directly affect the time to saturation. Various techniques can be applied, such as winding assist, to speed-up and increase the effectiveness of the saturation process. This paper will present the obstacles associated with performing DC Winding Resistance tests, saturation techniques, safety considerations, demagnetization, and case studies.

The goal is to isolate and measure only the winding resistance for a specific phase and winding. However, depending on the winding configuration, Delta (open or closed), Wye, Auto, and Zig-Zag, and the fact that winding resistance measurement can only be performed between terminals, the measured result may be a combination of windings and not a specific winding. All Delta winding configuration measurements often cause confusion because a single winding cannot be isolated by any terminal pair. Also, in specific applications, such as tertiary or stabilizing windings, the open or closed status of the Delta winding creates additional confusion.

INTRODUCTION The DC Winding Resistance test is used routinely in the field to validate and assess the continuity of the current carrying path between terminals of a power transformer winding. The DC Winding Resistance test is looking for a change in the continuity or real losses of this circuit, generally indicated by high or unstable resistance measurements. The diagnostic reach of the DC Winding resistance test is to identify problems such as loose lead connections, broken winding strands, or poor contact integrity in tap changers. In addition to the winding, there are several more components that are part of the transformer’s current carrying path: ●● Bushings and Bushing Connections ○○ Draw Leads ○○ Draw Lead Pins ○○ Pad Connections ●● Tap Changers (LTC and DETC) ○○ Barrier Boards

The Winding Resistance measurement circuit includes 3 components - a DC source (V or I), a Voltmeter, and a Current meter, and by simultaneously measuring voltage and current determines resistance by Ohm’s Law. As simple as the DC Winging measurement appears, several factors should be considered.

Measurement Ranges Understanding the expected resistance values is important for setting up and performing a DC Winding Resistance measurement. Most modern winding resistances instruments have the ability to measure very low resistances values in the microOhm (µΩ) range up to notably higher resistance values in the kilo-Ohm (kΩ) range. However, typical transformer winding resistances generally range from a few milli-Ohms (mΩ) to several Ohms (Ω). It is recommended to review previous results or consult the factory test report for determining the expected results. This will allow the optimum ranges on the test instrument to be selected. It is always best to run all meters close to full range, above 70%, if possible. In the case of auto-ranging instrumentation, always verify that an overload condition has not occurred; this could greatly affect accuracy in the reading.

○○ Selector Switches

Static and Dynamic Measurement Types

○○ Diverter Switches

There are two distinctive types of DC Winding Resistance measurements that can be applied, Static (Standard) and Dynamic (Advanced).

○○ Reversing Switches ●● Windings ○○ Strands ○○ Cross-Overs ○○ Tap Leads

Static–This is the standard test that is performed to measure the actual resistance value of a transformer winding and associated series components. The static measurement produces a single, temperature dependent value in Ohms (Ω).

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Transformers Vol. 1 Dynamic–This measurement is typically applied to load-tap changing (LTC) transformers. The dynamic winding resistance measurement tracks the changing resistive behavior as the LTC operates. Knowing that a LTC follows the “make before break” concept, any unusual changes, such as, loss of continuity, may indicate premature wear or fault with the LTC, specifically the diverter contacts.

The transformer winding appears to be a simple RL circuit. However, L, or the inductive component is made up of the leakage reactance of the winding, and the magnetizing reactance of the core. It is these inductive components that must be minimized through saturation. Figure 2 illustrates the RL basic components.

Kelvin Connections The Kelvin 4-wire method is the most effective method used to measure very low resistance values. The Kelvin 4-wire method will exclude the resistance from the measurement circuit leads and any contact resistance at the connection points of these leads. The concept of the Kelvin 4-wire method is to apply the voltage and current leads separately. This is shown in Figure 1.

Fig. 2: Basic transformer impedance model These inductances work in conjunction with the DC Winding Resistance and create a “not so simple” time constant. This time constant could be seconds or it could be minutes. Figure 3 shows a typical voltage and current response for a transformer winding, where 12 VDC has been applied.

Fig. 1: The Kelvin 4-wire method Connection points P1 and P2 are associated with the current injection and current measurement, and points P3 and P4 isolate the voltage measurement across the test specimen. Another subtle application of the Kelvin 4-wire method that should be noted is the placing of voltage sense leads (P4 and P4) ‘inside’ the current leads (P1 and P2). This helps ensure that any undesired voltage drops remain outside the intended resistance measurement.

Saturation The implication of the transformer core’s state of saturation makes the “simple in concept” test much more troublesome to users. Understanding the influence of the transformer core on the DC Winding Resistance measurement and why core saturation is a prerequisite for this test is challenging. To obtain the desired DC Winding Resistance measurement, the resistive component of the winding must be isolated; this requires saturation of the transformer’s magnetic circuit. Saturation occurs when all of the magnetic domains are successfully aligned in the same direction. By using Faraday’s Law: , it can be stated that the saturation process is dependent on the voltage applied across the terminals of a transformer. Intuition often leads us to believe it is current. However, higher currents produce greater voltage drops. From an application standpoint, it is important to understand the volt-amperes (VA) relationship, so that V can be maximized.

Fig. 3: Saturation response: voltage and current signals There are techniques and good practices that will improve the saturation process. If normal current injection methods are not sufficient and effective, there are additional advanced techniques to aid in saturation. Time to saturation can be shortened by either applying more current, re-directing current flow in Yn or yn windings, or using a combination of HV and LV windings. Recommended Techniques ●● Apply the highest possible terminal voltage without exceeding the recommended winding rating limits. To increase saturation performance, it is important to maximize the terminal voltage. However, there are some limitations. The current through a winding should not exceed 15% of the rated current. Limiting the current minimizes the chance of overheating, which could cause a change in resistance or thermal instability. ●● Maintain the direction of the magnetic domains between tests. Be aware of the terminal polarity. This may not be optimal when testing a Delta winding. ●● Re-directing current flow in a Wye windings with an accessible neutral takes advantage of the use of all 3 phases to align magnetic domains. Aligns flux direction in core by tying together 2 terminals. ○○ X1-X0: Inject into X1 and return through (X2 and X3) tied together; measure voltage across X1-X0

26

Transformers Vol. 1 ○○ X2-X0: Inject into X2 and return through (X3 and X1) tied together; measure voltage across X2-X0 ○○ X3-X0: Inject into X3 and return through (X1 and X2) tied together; measure voltage across X3-X0

Figure 4, shown below, is an example of re-direct current in Wye winding with an accessible neutral: “X1-X0: Inject into X1 and return through (X2 and X3) tied together; measure voltage across X1-X0”.

Fig. 5: Combining both H and LV winding

Safety ●● Strictly follow all local safety policies and procedures ●● Potential high voltage is present when applying the DC out put to test objects with a high inductance ●● As long as energy is flowing in the measurement circuit, NEVER connect or disconnect test objects and/or cables. Fig. 4: Redirecting current through a wye winding with accessible neutral ●● Use the HV and LV windings at the same time to assist in saturation; must be same phase and direction. ○○ X1-X0: Inject into H1 and tie (H3 and X1) together and return through X0; measure voltage across X1-X0 ○○ X2-X0: Inject into H2 and tie (H1 and X2) together and return through X0; measure voltage across X2-X0 ○○ X3-X0: Inject into H3 and tie (H2 and X3) together and return through X0; measure voltage across X3-X0 Figure 5, shown below, is an example of using both HV and LV windings: “X1-X0: Inject into H1 and tie (H3 and X1) together and return through X0; measure voltage across X1-X0”.

●● Always swap leads at bushing terminals and never at test equipment. ●● Use separate clamps for current and voltage connections on both sides of the test object to avoid hazards in case one clamp falls off during the test.

Magnetization The saturation process leaves the transformer core in a magnetized state. For most transformer applications, this is usually considered benign; however, magnetized transformers produce higher inrush currents upon energization. When in doubt, the manufacturer should be consulted. One side effect of core saturation is that it can influence other diagnostic tests, such as Turns Ratio and specifically, Exciting Currents and Sweep Frequency Response Analysis (SFRA). It is recommended to perform the DC Winding Resistance last to avoid contaminating the above mentioned test results. At the same time, exciting current tests and SFRA tests can be used to confirm and validate the presence or absence of magnetization. Figure 6 illustrates how magnetization can affect exciting currents results. In this example, the expected pattern of two similar high and one low is slightly distorted. As it is in this case, Phase C is often the worse because that is the phase that DC was last applied to during testing.

27

Transformers Vol. 1 ●● Poor Connections ●● Shorted Circuited Turns ●● Open Circuits and Turns

Such problems can generate significant heat during normal operation. It is recommended to review DGA results to provide supporting information that a heating condition exists.

Recommended Limits

Fig. 6: Exciting current patterns (with and without magnetization) At times, it may be required to demagnetize the transformers. There are two techniques that can be used to demagnetize a transformer. ●● Apply a decreasing AC voltage. This method is not practiced often due to the cost, size and complexity of such equipment for field use. This method would pull the BH curve, see Figure 7, to zero. ●● Apply DC power to the transformer windings and reverse the polarity of the applied source a number of times while reducing the voltage, current, and applied time until the core is demagnetized. Again, the focus is to pull the BH curve to zero.

Winding resistance test results are interpreted based on comparison. Individual phase measurements (Wye) or terminal measurements (Delta) are compared. Comparisons may also be made with the original factory results or previous test results. When comparing data from different test dates, the results should be normalized to a common reference temperature. It is expected that the measurements should be within 2% of each other 1.

Temperature Correction The temperature conversion formula is as follows 2:

where: Rs = resistance at desired temperature Ts Rm = measured resistance Ts = desired reference temperature (°C) Tm = temperature at which resistance was measured (°C) Tk = 234.5° C (copper) Tk = 225° C (aluminum)

Identifying Saturation Integrity

Fig. 7: BH curve

ANALYSIS OF RESULTS Failure Modes Detected by Winding Resistance Winding resistance is a diagnostic tool that focuses on Thermal and Mechanical failure modes. The winding resistance test is very useful in identifying: ●● Defective DETC or LTC (contacts)

To obtain valid winding resistance measurements, core saturation must occur. Often, experience is the best option for knowing how to identify saturation. The behavior of the measurement is generally inconsistent depending on the transformer design and configuration. Delta windings and preventative autotransformers in the LTC circuit are a few examples of obstacles that will affect the saturation process. Even after several minutes, saturation may appear complete, just to then change again. It is important on difficult units to document test parameters including approximate saturation time if the unit has been tested before. Once the testing is complete, an analysis is often enhanced by plotting the data, which in many cases is more helpful than viewing the data in tabular form. Figure 8, shown below, illustrates winding resistance data on a LTC that is exhibiting incomplete saturation. In both examples, early measurements are higher than expected. By viewing the plotted data, it is clear that core saturation has not occurred, and several measurements at the beginning of the test should be considered invalid.

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Transformers Vol. 1

Fig. 8: Incomplete saturation

CASE STUDIES Overheated Tap Changer Leads In this case study, the winding resistance measurements produces significantly higher readings on LTC positions 14R and 4L for Phase B, see Figure 8. Normal measurements were expected to be in the 25-30

mΩ range. The 14R and 4L measurements clearly exceeded the recommended limit of 2%. At first glance, it appears unusual that separate LTC positions produce questionable results. After reviewing the LTC nameplate information, see Table 1 below, it shows that LTC positions 14R and 4L share a common tap lead (#7).

Fig. 9: Winding resistance measurements on LTC

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Transformers Vol. 1 POS

Volts

LTC

16R 15R 14R 13R 12R 11R 10R 9R 8R 7R 6R 5R 4R 3R 2R 1R

X1-X2-X3 15180 15095 15010 14920 14835 14750 14660 14575 14490 14405 14320 14230 14145 14060 13940 13885

A 8 7 7 6 6 5 5 4 4 3 3 2 2 1 1 0

B 8 8 7 7 6 6 5 5 4 4 3 3 2 1 1 1

N IL 2L 3L 4L 5L 6L 7L 8L 9L 10L 11L 12L 13L 14L 15L 16L

13800 13715 13360 13540 13455 13370 13280 13195 13110 13025 12940 12850 12765 12680 12590 12505 12420

0 8 8 7 7 6 6 5 5 4 4 3 3 2 2 1 1

0 0 8 8 7 7 6 6 5 5 4 4 3 3 2 2 1

9

M

Upon further investigation, clear over-heating of connection #7 was observed. This overheating is shown below in Figure 10.

K

Fig. 10: Overheating of connection #7

Poor LTC Contact Winding resistance measurements were performed on a load-tap changing transformer with a resistor-type LTC. All odd positions failed. Phase X3-X0 had higher than expected measurements The resistance measurements were consistently higher. This is shown in Figure 11.

Table 1: LTC nameplate

Fig. 11: Winding resistance measurement (poor odd positions on Phase C)

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Transformers Vol. 1

When measurements fail consistently in a pattern, as shown above, “in common” components should be investigated. This pattern indicates the problem is mostly associated with the diverter switch main contacts or associated leads. See Figure 12 below shows one side of the diverter switch.

Fig. 12: Diverter Switch

CONCLUSION This paper shares insight associated with performing DC Winding Resistance tests, saturation techniques, safety considerations, and demagnetization, and provides two case studies. The salient points of this paper are summarized as follows: ●● The Winding Resistance measurement circuit includes 3 components - a DC source (V or I), a Voltmeter, and a Current meter, and by simultaneously measuring voltage and current determines resistance by Ohm’s Law. ●● The DC Winding Resistance test provides a diagnostic tool that focuses on thermal and mechanical failure modes. The winding resistance test identifies problems such as loose lead connections, broken winding strands, or poor contact integrity in tap changers. ●● DC Winding Resistance results are interpreted based on comparison, and are corrected for temperature. ●● Transformer core saturation is a prerequisite for obtaining valid winding resistance measurements. Understanding the influence of the transformer core on the DC Winding Resistance measurement is challenging. Experience best equips a user in successfully identifying complete saturation of the transformer’s magnetic circuit.

REFERENCES 1

I EEE Std 62-1995, “Guide for Diagnostic Field Testing of Electrical Apparatus – Part 1: Oil Filled Power Transformers, Regulators, and Reactors”.

2

 . Gill: “Electrical Power Equipment Maintenance and Testing” P Second Edition, CRC Press, 2009

3

 . L. Sweetser, “The Importance of Advanced Diagnostic MethC ods for Higher Availability of Power Transformers and Ancillary Components in the Era of Smart Grid”, IEEE Power Engineering Society Summer Meetings, Detroit, MI, USA, July 22-26, 2011

Charles Sweetser received a B.S. Electrical Engineering in 1992 and a M.S. Electrical Engineering in 1996 from the University of Maine. He joined OMICRON electronics Corp USA, in 2009, where he presently holds the position of Technical Services Manager for North America. Prior to joining OMICRON, he worked 13 years in the electrical apparatus diagnostic and consulting business. He has published several technical papers for IEEE and other industry forums. As a member of IEEE Power & Energy Society (PES) for 14 years, he actively participates in the IEEE Transformers Committee, and presently holds the position of Chair of the FRA Working Group PC57.149. He is also a member of several other working groups and subcommittees. Additional interests include condition assessment of power apparatus and partial discharge.

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PARTIAL DISCHARGE TESTING USING THE UHF DRAINVALVE SENSOR + PD SMART OR USING A SIMPLE SURVEY TOOL PDS 100 WITH THE SAME UHF DRAINVALVE PowerTest 2013 Karl Haubner, Doble Engineering

Partial Discharge Detection is considered one of the most powerful tools to determine the condition of insulation systems. There are various options to monitor for PD activity based on the release of the energy due to PD. Conventional electrical PD measurements according to IEC60270 require the installation of a sensor to the HV circuit. To monitor PD on transformers in the factory the PD detector is typically connected to the bushing taps. Once the transformer is placed in service this method is not always practicable and in most cases will be subject to external interference hence other called non conventional methods of PD detection are desirable. Rightfully, the most popular method to detect PD activity in transformer is by detecting the chemical decomposition of both cellulose and oil using Dissolved Gas Analysis. But there are sometimes situations that call for complementary techniques. Hydrogen, which is the key indicator of PD activity can have other origins and DGA is not 100% conclusive. DGA is an integrated measure and slower to identify a rapidly changing situation. Also direct on-line measurements can provide additional information on the type location of PD. Another methods relies on detecting the acoustic pressure wave generated by the internal PD event using piezoelectric sensors mounted on the outside of the tank wall but this technique has poor sensitivity for PD activity from within the transformer winding and should be seen more as an location rather than a detection technique. The demand for a more sensitive field technique has lead to the development of alternative methods. A PD event results in a transient current pulse and an electromagnetic field in very high (VHF) and ultrahigh (UHF) frequency range. These electromagnetic waves can be detected using special sensors or antennas. For transformer these electromagnetic waves emitted by PD resonate within the transformers enclosure and can be measured everywhere in the transformer with moderate attenuation of the signal but are not easily detected from the outside. The transformer tank acts like a Faraday cage effectively shielding external PD signals that may corrupt the measurement permitting much sensitive detection of PD activity on energized transformer then other methods based on acoustics or detection of PD activity via High Frequency CT’s in-

stalled on the neutral of the transformer but an internal PD sensor is required. There are two possibilities of installing these sensors. Either permanently fitted UHF hatch type sensor that can be incorporated in the transformer design or later installed by replacing an inspection cover typically installed during an outage in a UHF sensors that can be inserted through an oil drain wave are used.

Fig. 1: UHF Hatch Sensor

Fig. 2: PDS 100 RFI Survey

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Fig. 5: Healthy transformer with no PD activity detected Fig. 3: UHF drain valve

Fig. 4: PDS 100 RFI Survey PD measurent using the UHF Drainvalve sensor + PDsmart or for a simple survey the UHF Drainvalve + PDS100 PD measurements via the oil drain sensor can be conducted whilst the transformer remains energized. The output signal of the sensors can be processed in time or frequency domain. The output cannot be described in term of apparent charge as in conventional measurements, but simultaneous measurements using both conventional IEC60270 test circuit and UHF couplers have shown sensitivities in the low pC range for the UHF couplers. Because the transformer shields the measurement from external interference, interpretation also is less complex.. In the absence of any active PD source in most cases only background is detected.

Fig. 6: Transformer with critical PD activity Since the PD pulse characteristics are preserved using a UHF PD detector, it is sometimes possible to determine the nature of the PD using the phase resolved patterns. The main aim of the above tests is to detect if the transformer has PD activity or not. Once the presence of PD has been confirmed and some estimate about the severity of the activity is known PD location should be attempted. The output of the UHF probe can now be used as the trigger signal enhancing the accuracy of the triangulation techniques. In summary for the first time PD measurements comparable in terms of sensitivity to laboratory tests are possible in the field even under adverse condition and without an outage to conduct these tests. This compliments the well known Dissolved Gas Analysis and overcomes shortcomings of the acoustic technique which is more suitable for location rather than conclusive detection. The main disadvantage of the UHF method is that it is not possible to calibrate the PD in terms of apparent charge in pC.

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Transformers Vol. 1

I HAVE A LOT OF NUMBERS, WHAT DO THEY MEAN – BASIC INTERPRETATION OF TWO WINDING TRANSFORMER DATA PowerTest 2013 Keith Hill, Doble Engineering Company

INTRODUCTION: The intent of this paper is to educate an inexperienced tester on the steps to be taken to be assured that the proper test procedures were performed. It is recommended that these guidelines be understood and followed to prevent testing errors in the field. In this paper, you will see some terminology that may be new to you. An attempt will be made to identify these components with a brief description. More detailed information can be located in the operator’s manual provided by the manufacturer of your equipment. For this paper it will be assumed that the tester knows how to operate the test set. This presentation is an attempt to demonstrate to the tester what each item means. It is important that the tester fully understand the test form and software being used.

The CH’ and CL’ may be new terminology to both inexperienced and experienced testers who may normally use test equipment manufactured by various manufacturers. CH’ is the CH insulation minus the sum of the C1 results for the primary bushings. CL’ is the CL insulation minus the sum of the C1 results for the secondary bushings. C1 is the test performed on the bushings (Figure 2), with a capacitance tap, by energizing the main conductor and measuring to the tap in the Ungrounded Specimen Test (UST) mode.

The following terminology will be used in this paper: CH, CL, CHL, CH, CL, and C1. CH is used to describe all of the high voltage components to ground. This will include the high side insulation, high side bushings, structural insulating members, insulating fluid, and de-energized tap changed, if present. CL is used to describe all of the low voltage components to ground. This will include the low side insulation, low side bushings, structural insulating members, insulating fluid and load tap changer, if present. CHL is used to describe the insulation between the windings, winding barriers, and the insulating fluid.

Fig. 2: Main-insulation/C1 test standard method One of the most important parts of analyzing test data is to make sure that the tests were performed correctly. This can be accomplished by using simple math as demonstrated in the following examples. A review of the DTAF layout (Figure 3) is provided for personnel who are not familiar with this test form. Column 1: Test number Column 2: Note indication box Column 3: Winding energized Column 4: Test mode of low voltage lead - Ground

Fig. 1: Dielectric circuit of a two-winding transformer

Column 5: Test mode of low voltage lead - Guard Column 6: Test mode of low voltage lead - Measured

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Transformers Vol. 1

Column 7: Test voltage in kV Column 8:

mA

Column 9: Watts Column 10: Measured power factor Column 11: Power factor corrected to 20 degree C Column: 12: Correction factor

sured that the test procedures used were correct. If the currents and watts add correctly then the high voltage cable and the low voltage lead can be reversed and testing of the low voltage winding can take place. Once testing has been performed on the low voltage windings, the same procedure is used to verify the low voltage test results (Figure 4).

Column 13: Measured capacitance Column 14: Insulation measured Column 15: Rating provided by DTAF expert system Column 16: rating provided by tester

Fig. 4: Low voltage test results For test number 5 (column 1), note that the insulation measured (column 14) is the CL and CHL. Fig. 3: DTAF layout For test number 1 (column 1), note that the insulation measured (column 14) is the CH and CHL. For test number 2 (column 1), note that the insulation measured (column 14) is the CH. For test number 3 (column 1), note that the insulation measured (column 14) is the CHL. Using simple math we see that the following statement should be true: Line 2 mA + Line 3 mA = Line 1 mA (CH) + (CHL) = (CH + CHL) 11 mA + 19.97 mA = 30.97 mA Line 1 is actually 30.98 mA Line 2 watts + Line 3 watts = Line 1 watts (CH) + (CHL) = (CH + CHL) .248 watts + .578 watts = .826 W Line 1 is actually .829 watts Test 4 is the calculated CHL which allows the tester to “doublecheck” the test result. Test 1 (Current and Watts) - Test 2 (Current and Watts) = Calculated UST (Line 4) (CH + CHL) - (CH) = (CHL) Test 3 and Test 4 should be “equal” If these currents and watts add up the tester can usually be as-

For test number 6 (column 1), note that the insulation measured (column 14) is the CL. For test number 7 (column 1), note that the insulation measured (column 14) is the CHL. Using simple math, we see that the following statement should be true: Line 6 mA + Line 7 mA = Line 5 mA (CL) + (CHL) = (CL + CHL) 45.43 mA + 19.97 mA = 65.40 mA Line 5 is actually 65.41 mA Line 6 Watts + Line 7 Watts = Line 5 Watts (CL) + (CHL) = (CL + CHL) 1.328 W + .576 W = 1.904 W Line 1 is actually 1.907 W Test 8 is the calculated CHL which allows the tester to “doublecheck” the test results. Test 5 (Current and Watts) - Test 6 (Current and Watts) = Calculated UST (Line 8) (CL + CHL) - (CL) = (CHL) Test 7 and Test 8 should be “equal” Tests 3, 4, 7, and 8 should be “equal” As stated for the high voltage winding tests, if the low side currents and watts add up the tester can usually be assured that the test procedures used were correct. If the bushing have capacitance taps the C1 and C2 tests can be performed, which will allow for the calculations of the CH’ and CL’.

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Transformers Vol. 1 In Figure 5 the CH’ Calculation is on Line 9 of the test form.

Fig. 8: Fig. 5:

Using the current and watts in Figures 7 and 8, we can calculate the CL’. Sum of the Secondary Bushings C1 tests currents (Figure 8) 2.114 (X1) + 2.138 (X2) + 2.189 (X3) + 2.146 (X0) = 8.587 mA Line 6 mA – Sum of C1 mA = Line 10 mA (Figure 7) 45.430mA – 8.587 mA = 36.843 Ma

Fig. 6:

Sum of the Secondary Bushings C1 tests Watts (Figure 8)

Using the current and watts in Figures 5 and 6, we can calculate the CH’.

.054 (X1) + .053 (X2) + .054 (X3) + .056 (X0) = .217W

Sum of the H bushings C1 tests currents (Figure 6)

Line 6 Watts – Sum of C1 Watts = Line 10 Watts (Figure 7)

1.333 (H1) + 1.333 (H2) + 1.323 (H3) + 1.334 (H0) = 5.323 mA

1.328 W – .217 W = 1.111 W

Line 2 mA – Sum of C1 mA = Line 9 mA (Figure 5) 11mA –

5.323 mA

= 5.677 Ma

Sum of the H bushings C1 tests Watts (Figure 6) .030 (H1) + .030 (H2) + 1.323 (H3) + .030 (H0) = 1.20 Watts Line 2 Watts – Sum of C1 Watts = Line 9 Watts (Figure 5) .128 W – .120 W = .128 W Line 9 (Figure 5) is the primary insulation without the bushings included in the tests. We should remember that power factor is actually ‘average’ power factor” as an average of the insulation system is measured. The power factor for line 9 may remain the same if both the bushings and windings were acceptable. If the bushings were acceptable and the windings were contaminated the power could increase. If the bushings had higher than normal power factors the power factor for line 9 could decrease.

Line 10 is the CL insulation without the secondary bushings included in the tests. The same holds to be true for the secondary tests as for the primary tests. The power factor for line 10 may remain the same if the bushings and windings were acceptable. If the bushings were acceptable and the windings were contaminated the power could increase. If the bushings had higher than normal power factors the power factor for line 10 could decrease. Please remember that after the bushing tests are performed the tester must return to the overall test sheet and perform a recalculation for the bushings to be subtracted from the CH and CL.

This same procedure is used when calculating the CL’. Fig. 9:

Fig. 7:

In Figure 9, you will note an increase in the power factor for tests 9 (CH), when compared to test 2 (CH) and test 10 (CL) when compared to test 6 (CL). The power factor increased 1.5% for test 9, without the bushings, compared to test 2, with the bushings. This is an indication of good bushings (Figure 10) “masking” the contaminated windings. The same applies for test 10 compared to test 6, but the increase in power factor is not as great.

36

Transformers Vol. 1 When questions arise always go back to the basics: A change is current or capacitance is a physical change. A change in watts is due to contamination or deterioration.

Fig. 10:

HANDY FORMULAS AND THINGS TO KEEP IN MIND Power Factor = watts x 10 mA Capacitance = 265 x mA (60 Hz) (Rule of thumb is good up to about 15% power factor)  apacitance = 318 x mA (50 Hz) (Rule of thumb is good up C to about 15% power factor) It must be remembered that a change in current or capacitance from prior tests is a physical change, while a change in watts is usually from contamination or deterioration. From the above power factor formula, one can see that if the capacitance and current are the same that the change in power factor would have to be from a change in the watts.

CONCLUSION: This is a quick review/introduction on the steps used to verify that the test procedures used were correct. One should always analyze the power factor but that will not be covered in this paper as the power factor can vary for different transformers. These quick steps should always be performed once a test is complete and before the leads are changed. Please remember that a “G” rating does not mean that the tests were performed correctly as this may be the first test performed and the software may be comparing the corrected power factor to know limits. Often, emphasis is placed only on the power factor of the apparatus being tested. To correctly analyze the data, the currents, watts, capacitances, and power factor should all be reviewed and analyzed. Prior test data can be used as a reference as the currents should basically be the same each time. Power factor is only one tool in your tool box and acceptance of this apparatus should not be based only on power factor results. Excitation current, transformer turns ratio, winding resistance, and oil analysis are all recommended to be performed in an attempt to establish the condition of the transformer. Sweep Frequency Response Analysis (SFRA) along with Leakage Reactance (LR) tests may also assist in identifying a problem.

Keith Hill has been employed at Doble Engineering since 2001, and currently works as a Principal Engineer in the Client Service Department. Keith has over 38 years of experience in substation maintenance, electrical testing, and project management. Mr. Hill is a member of IEEE, a former NETA certified technician, and is a level I and II certified thermographer. Prior to Doble, Mr. Hill was the Electrical Supervisor of Engineering Services for a major refinery. Mr. Hill has published several papers relating to equipment testing and maintenance for various conferences and publications. At the present time, Keith serves as the secretary of the Doble Arresters, Capacitors, Cables, and Accessories committee. Keith received his BS from the University of Houston with a major in Electric Power.

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Transformers Vol. 1

ARE YOU REALLY TESTING YOUR INSTRUMENT TRANSFORMERS? PowerTest 2013 Michael Hancock, P.E.

INTRODUCTION Instrument transformers are a forgotten entity within any electrical system. Sometimes, they are tested upon commissioning and sometimes they are not. With the ever increasing focus on cost reductions, instrument transformer testing is usually one of the first items to be removed from the preventative maintenance test listing. There are many basic tests that can be completed on instrument transformers. However, are these tests satisfactory and sufficient to determine if they are acceptable for use and/or will they function as designed? There are many hidden secrets within these tests and this paper will focus on the basics of testing instrument transformers and the hidden practice to determine if they will truly work correctly. For example, are you simply hooking up an automated test set and looking at the results and assuming that all is well? What about the burden, i.e. connected load? We will dive into the art of instrument transformer testing to determine if you are indeed actually testing your instrument transformers.

WHAT TESTS SHOULD BE CONDUCTED ON INSTRUMENT TRANSFORMERS: ●● Perform insulation resistance through bolted connections. ●● Perform insulation resistance between windings ●● Perform Polarity Test ●● Perform ratio test on all taps ●● Perform excitation test to determine knee voltage or saturation point on current transformers ●● Measure burden at transformer terminals ●● Perform dielectric withstand voltage on primary windings

“Through” the connection. The results should be very low, i.e. in the micro-ohms. Compare the results for similar connections for they should be very close. If anomalies are found, investigate further by checking the torque on the bolts and if necessary, break the connection, clean, reassemble and then retest. See Figure 1 below for an example of where to apply the test leads to measure the resistance of the bolted connection.

Fig. 1: Test Resistance of Bolted Connection

Perform insulation resistance between windings The intention of this test is to ensure that there are no shorted windings to one another and to ensure that the internal windings are properly insulated from ground. This test is important to ensure that the windings are properly insulated. There are many types of instrument tranformers, for example, some are encased in plastic, and some have metal mounting brackets molded into them, just to name a few. See Figure 2 below for an example of where to apply the test leads in order to test between the various windings.

●● Measure power factor ●● Verify proper grounding ●● Verify fuse ratings and test fuses

Perform insulation resistance through bolted connections. All current and potential transformers are connected to bus bars, cables or some other type of connection. The intention of this test is to ensure that the connections are tight and torqued properly. To perform this test, you apply a Digital Low Resistance Ohmmeter (“DLRO”) across the connection and measure the resistance

Fig. 2: Perform Insulation Resistance Between Windings

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Transformers Vol. 1

Perform Polarity Test The polarity test is extremely important, especially in today’s times with the advanced protective relays and metering devices. The polarity determines the power flow of the current or voltage applied. If the power flow into the protective relay or meter is not correct, the meter may not read correctly and the protective relay may miss operate or not operate at all depending upon how it is wired. All current and potential transformers have markings that show the high and low side connections. These are normally labeled as H1, H2, X1, and X2. If the current transformers have multiple windings, i.e. taps, they may have additional markings, such as X1, X2, X3, X4, X5, etc. Please review Figure 3 below which shows an elementary diagram of a current transformer, a potential transformer and a typical test utilized to measure the polarity.

ments are exceeded, i.e. connected load is too large, the instrument transformer will become saturated and not produce linear results. Therefore, it is important to perform the excitation test to determine the point at which the instrument transformer will saturate and not produce linear results. The knee point is determined at the point on the curve where the voltage plot begins to be non-linear, which is typically at a point of 45 degrees tangent to the curve; see the example in Figure 4 below. To determine this point, apply voltage to the instrument transformer, raise the voltage and plot the results. The resulting graph should be similar to the one in Figure 4.

Fig. 4: Current Transformer Excitation Plot

Measure burden at transformer terminals Fig. 3: Polarity Test

Perform ratio test on all taps All instrument transformers have a set ratio. For example, a common potential ratio for a 4200 volt system is 4200/120. If exactly 4200 volts were applied onto the primary, the secondary would read 120 volts. Current transformers typically have ratios similar to 4000/5, 3000/5, 1200/5, etc. Therefore, utilizing the 4000/5 ratio as an example, if 4000 amps were applied to the primary, the secondary flow would be 5 amps. The intention of the ratio test is to verify that the ratio is per the name plate and that the proper tap is connected per the engineering design if the instrument transformer has multiple taps.

What is the proper way to measure burden? Do you simply apply 5 amps in 1 amp increments and measure the voltage? Technically no. What happens when a severe fault occurs and instantaneous settings are utilized? Not only that but each device should be tested to ensure that it is properly wired into the instrument transformer loop and the proper polarity has been applied. In order to properly test the burden, you should ask what the instantaneous setting is if utilized because this is the maximum current that must be sensed by the protective relay. The instrument transformer should be able to push this current and voltage through the connected secondary loops linearly.

Perform excitation test to determine knee voltage or saturation point on current transformers

To determine the maximum burden voltage level, apply current, preferably at the instrument transformer, so that all of the resistance of the connected instrument transformer load is connected and evaluated. The measured voltage required to drive the instantaneous setting should be less than 50% of the knee voltage. If the voltage required to drive the connected load is above 50% as compared to the knee voltage of the instrument transformer, it is highly advised to consult the engineering group that designed the circuit and to further recommend high current injection testing of the instrument transformer loop to ensure proper operation.

The excitation test is utilized to determine the knee voltage or saturation point. All instrument transformers have a power rating, just like a large power transformer. If the power require-

When testing the burden, it is recommended to apply low amperage, around 1 amp or so, then verify that all of the connected loads are wired correctly. Every element should be verified to

Most modern instrument transformer test units have auto functions and will measure and provide the ratio. A simple method to verify a ratio is to apply voltage onto the primary and measure the secondary voltage, then compare this against the name plate rating, which should be the same.

Transformers Vol. 1 have the proper polarity as connected. Most relays utilized today are of microprocessor type and can determine phase faults, phase calculations, watts, vars, etc. and if any of the elements are corrected incorrectly the relay may trip incorrectly or read incorrectly. Figure 5 below shows an elementary diagram on the left showing where to ensure proper polarity, which should be done for all connected devices. The diagram on the right is a more advanced system and all elements in this example should be verified.

Fig. 5: Current Transformer Burden Testing

Perform dielectric withstand voltage on primary windings The intention of this test is to verify that the device can withstand the applied voltage and ensure proper insulation. This test should be applied when appropriate and the appropriate AC and or DC test voltage should be utilized.

Measure power factor This test is typically applied to higher class instrument transformers such as 138kV rated or higher. This test can be applied to lower classes but is most typically completed on higher class instrument transformers. The power factor should be referenced to similar like devices and to historical tables. This is an extremely useful test to determine the overall condition of the apparatus.

Verify proper grounding Proper ground should be verified on the secondary side of the instrument transformers. Most current and potential transformer loops are grounded on the secondary sides and should only have one ground. The ground should be verified for reference and for safety purposes.

Verify fuse ratings and test fuses All potential transformer loops should be protected by fuses. The fuse ratings should be verified and it is further recommended to test the fuses. Care must be utilized when testing low ratings to not utilize a test instrument that will blow the fuses. The fuse ohm readings should be compared to similar fuse types.

39 Mike Hancock is a P.E. who has worked within the Electrical Power industry since 1992. Within Shermco, Mike is tasked with leading the 8010 divisional sales team and developing the electrical power utility markets. Mike has held numerous positions with various companies with increasing responsibility such as Senior Field Engineer, Area Supervisor, Executive Project Manager, PDS Global & National Accounts Manager and currently holds the title District Sales Manager/ Business Development with Shermco’s (ESD) Electrical Services Division. Mike has extensive experience with power systems engineering and solutions, field startup and commissioning and has advanced into the management realm. Mike has experience working with telecom, industrials, electric utilities, large retail, commercial, government, institutions and in many other market segments.

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Transformers Vol. 1

PARTIAL DISCHARGE TESTING OF ROTATING MACHINES – IS IT SCIENCE OF BLACK MAGIC? PowerTest 2013 Vicki Warren, Iris Power LP, Qualitrol Company

ABSTRACT In the past few years, reports based on a few case studies have shown that modern air-cooled stator windings are suffering from premature deterioration of the insulation. However, since these reports have no statistical basis, the total population is unknown and some machine manufacturers claim the ‘situation is normal.’ To obtain a more objective insight into whether modern air cooled stators are seeing an increase in deterioration; analysis was made of a large partial discharge database collected from such machines. The paper will present the data and explain the PD measurement process. The deduction is that this more objective analysis indicates that higher design stresses used in the past decade are in fact resulting in more rapid deterioration of insulation systems.

INTRODUCTION Partial discharges (PD) are small electrical sparks that occur when voids exist within or on the surface of high voltage insulation of stator windings in motors and generators. These PD pulses can occur because of the thermal deterioration [Figure 1], manufacturing/installation processes [Figure 2], winding contamination or stator bar movement during operation. As the insulation degrades, the number and magnitude of PD pulses will increase. Although the magnitude of the PD pulses cannot be directly related to the remaining life of the winding, the doubling of PD pulse magnitudes approximately every 6 months indicates rapid deterioration is occurring. If the rate of PD pulse activity increases rapidly, or the PD levels are high compared to other similar machines, this is an indicator that visual inspections and/or other testing methods are needed to confirm the insulation condition [IEEE 1434-2000]. Furthermore, if the PD magnitudes by the same test method from several identical windings are compared, the windings exhibiting higher PD activity are generally closer to failure.

Fig. 1: PD due to Thermal Deterioration

Fig. 2: PD at the Voltage Stress Coatings

THEORY Once a void is created within the bulk or on the surface of insulation, a potential difference will build across it. The magnitude of this voltage will depend upon the applied voltage, the capacitance of the insulation and the gas in the void. The voltage that develops across the void is shown in Figure 3. A discharge can only occur when the electric stress (V/mm) exceeds the electrical breakdown point for the gas based on Paschen’s law. Other issues besides gap length that can affect the electric stress in a void are: diameter, internal gas and pressure, and the nature of the surface in the void. In general, the product of the gap separation and the gas pressure establishes the voltage necessary to lead to a discharge, i.e., breakdown voltage [IEEE 1434-2000].

41

Transformers Vol. 1 PD CHARACTERISTICS

Fig. 3: Electrical Stress in a Void between Coil and the Core When the applied 50/60Hz increases sinusoidally, the apparent electric stress across the void increases until it reaches 3kV/mm or the equivalent breakdown voltage in the void. Over voltage is the state at which the voltage across a void exceeds the breakdown voltage required for the void size and gas. The larger the over voltage the more intense the space charge effects in the void. Although a void may be in an over voltage state, breakdown will not occur until a free electron (due to cosmic or natural radiation) appears within the gap and starts an avalanche of the electrons. This avalanche is a flow of electrons across the gap which gives rise to a very fast rise-time (a few nanoseconds) current pulse, called a partial discharge (PD). The dependence on the free electron for a partial discharge makes the occurrence of PD a statistical event and therefore not predictable. Once the breakdown occurs, the voltage across the gap collapses to a voltage level sufficient to sustain the discharge. Most instruments only detect the initial breakdown pulse [IEC 60034-27]. No further detectable discharges will occur until the gap voltage has reversed in polarity and another over voltage condition established. Thus, for each pulse position there will be a detectable PD occurring twice in an AC cycle. However, the occurrence, magnitude, and pattern in a void are a complex phenomenon depending on the size, shape, internal gas pressure, and nature of the void surface and will deviate from cycle to cycle due to past space charge trapping (as shown in Figure 4).

Fig. 4: Partial Discharge Occurence

Machines that have not been properly impregnated or that have been operating for several years at high temperatures tend to develop voids within the groundwall insulation. If both sides of the void have similar insulation materials then the charge distribution will be equal during the positive and negative cycles. In theory, there will be two observable PD pulses in each AC cycle of equal magnitude and opposite polarity per void within the bulk of the insulation [Figure 5]. These pulses clump at the classic positions for phase-to-ground dependent pulses, that is, negative pulses at 45° and the positive pulses at 225° with reference to the 50/60Hz phase-to-ground voltage [Figure 6]. A machine that is frequently load cycled or severely overheated develops voids near the copper conductors. A void bounded by the copper conductor and insulation, exhibits a different phenomenon than those within the bulk of the insulation. Though the basic breakdown mechanisms are the same, because the electrodes are of dissimilar materials, polarity predominance occurs. The mobility of the positive ions on the insulation surface is much lower than the negative ions on the conductor surface. The result is a predominance of negative ions migrating through the gap to the positive insulation surface. In this case, there will usually be an observable predominance of negative PD pulses clumped at 45° during the positive AC cycle [Figure 5]. Loose coils, poor semi-conductive coatings, and problems with the grading/semicon interface can all lead to surface discharge between the stator bar and the grounded core iron, called slot discharges. As with those near the copper conductors, these discharges occur between electrodes made of different materials. Here, the immobile positive charges on the insulation and mobile negative charges on the grounded metallic electrode lead to pulses occurring during the negative AC cycle. Because the metallic electrode is grounded, the observable PD pulses will be predominantly positive clumped at 225° [Figure 5].

Fig. 5: Polarity Predominance

42

Transformers Vol. 1 where near the source of the PD. Two types of sensors referenced in IEEE 1434-2000 and IEC/TS 60034-27-2 are: ●● Capacitive couplers, Epoxy Mica Capacitors (EMC) - for motors, hydros, and small turbos. [Fig. 8, Fig. 9] ●● Stator slot couplers (SSC) - for large turbos (>100MW). [Fig. 10]

Fig. 6: Phase-to-ground Discharges Contamination and/or Phase to Phase Discharges in the end arm area, on ring busses, or motor leads can lead to partial discharge activity in these areas. Unlike the previously described pulses that are phase-to-ground voltage dependent, these pulses are based on phase-to-phase voltages. Though these pulses tend to be very erratic, it is sometimes possible to distinguish these pulses from others by observing their location with reference to the phase-to-ground voltage. Typically, because of the phase-to-phase voltage dependency there is a 30° phase shift from the classic phase positions associated with pulses that are phase-to-ground voltage dependence as shown in Figure 7. Phase-to-phase pulses tend to clump at 15°, 75°, 195°, and 255°, based on the location of the pulses and the phase rotation of the machine. Sometimes, it is possible to determine which two phases are involved, but often it is difficult to extract that information accurately from the quantity of pulses detected.

Fig. 8: EMC at Terminals

Fig. 9: EMCs on Bus Bar

Fig. 10: SSCs in Turbo

PD DETECTION Fig. 7: Phase-to-phase Discharges

PARTIAL DISCHARGE SENSORS Permanently mounted PD sensors block the AC power signal (50/60Hz), but pass the high frequency PD pulses (50-250MHz). The type of sensor installation and test instrument depends on the machine or equipment being monitored. The first step of PD detection is the placement of a sensor some-

During normal operation, a continuous PD monitoring or portable PD instrument connected to the sensors separates noise and properly classifies the PD. Until recently such an “on-line” PD test had been difficult to implement due to the presence of electrical disturbances that have PD-like characteristics. This can lead to healthy windings being misdiagnosed as deteriorated, which lowers confidence in the test results. “Noise is defined to be non-stator winding signals that clearly are not pulses.” [IEC/TS 60034-27-2] Electrical noise from power tool operation, corona

43

Transformers Vol. 1 from the switchgear and RF sources, etc., is easily confused with PD from the machine windings.

Separation based on pulse characteristics [Figure 14].

“Disturbances are electrical pulses of relatively short duration that may have many of the characteristics of stator winding PD pulses – but in fact are not stator winding PD.” [IEC/TS 6003427-2] Some of these disturbances are synchronized to the AC cycle, and some are not. Sometimes synchronized disturbance pulses can be suppressed based on their position with respect to the AC phase angle. A good on-line PD test reduces the influence of noise and disturbances, leading to a more reliable indication of machine insulation condition. Three methods of noise and disturbance separation include: Fig. 14: PD coming from System

Band-pass filtering of PD between 50-300MHz, whereas noise is less than 35MHz [Figure 11]

ANALYSIS

Fig. 11: Band-pass Filter 40-350MHz Separation based on direction-of-arrival to two sensors connected to a single phase [Figure 12, Figure 13]

Although the magnitude of the PD pulses cannot be directly related to the remaining life of the winding, if the rate of PD pulse activity increases rapidly or the PD levels are high compared to other similar machines, this is an indicator that visual inspections and/or other testing methods are needed to confirm the insulation condition [IEEE 1434-2000].

TREND If the unit operating parameters – voltage, load, winding temperature and gas pressure – are similar to those of the previous test, then a direct comparison can be made between the two test results. Environmental conditions such as humidity may have a very noticeable impact, especially if the surface contamination becomes to some extent conductive when damp, so it should be recorded from one test to the next. When a trend line is established for PD tests taken over a period, it will be obvious that most show small up and down variation between successive tests [Figure 15]; however, a sustained upward trend indicates developing problems.

Fig. 12: PD coming from Machine

Fig. 15: Typical PD Trend

COMPARE TO SIMILAR MACHINES

Fig. 13: PD coming from System

If the PD magnitudes by the same test method from several similar windings are compared, the windings exhibiting higher PD activity are generally closer to failure. Due to the influence of the test arrangement on the results, the test setup (sensors and test instrument) must be the same for all comparisons5 .

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Transformers Vol. 1

One example is the statistical summaries of the peak magnitude, Qm, values based on the most recent Iris Power database that contains several thousands of test results. Each table shows the average, maximum, and the 25th, 50th, 75th, 90th, and 95th percentile ranks [Table 1]. The 25th percentile is the Qm magnitude for which 25% of the test results are below, similarly for the other percentiles. Normally, there is concern for a winding if the Qm in a machine is higher than the 75th percentile and increasing. 25

6-9

10-12

13-15

16-18

25%

29

34

50

41

Chart 1: Motors 6-8kV by OEM

50%

70

77

113

77

75%

149

172

239

151

90%

288

376

469

292

Chart 2 below depicts the 25th, 50th, 75th, 90th and 95th percentiles for all manufacturers based on date of winding installation (<1981, 1981-1985, 1986-1990, 1991-1995, 1996-2000, 2001-2005, and 2006-2010). Note that only the most recent test data is displayed, that is, even if a winding was installed in 1986, only the PD results the 2009 tests are included. In this presentation, it is expected that due to aging, the older machines in the 2009 test results would have higher PD results than the newer ones. In other words, there should be a noticeable downward trend from those manufactured before 1981 to those installed in 2006-2010.

Table 1: PD statistics for turbos & motors (Qm in mV) (Data using Iris Power sensors and PD instruments for installations using EMC sensors at the terminals)

MANUFACTURERS AND AGE Because PD results are dependent on the machine type and voltage class, to properly evaluate the industry trends one of the most common air-cooled machine types and voltage classes were selected: Motors 6-8kV. For each machine and voltage category, the results were separated based on manufacturer (labeled A-I in the charts). There was no attempt to evaluate type or method of manufacturing, or to extend the breakdown the machine types beyond the general categories listed. In addition, for all manufacturers trends based on year of winding installation are also presented 3.

However, it is apparent that this is not the case. Instead, the newer windings manufactured from 2006-2010 actually have higher PD for the 75th, 90th and 95th percentiles than the previous decade of 1996-2005. This suggests that across the industry there is a trend in some of the newer windings of this voltage class to have problems that result in PD activity that was not present in the past decade, but perhaps was present in earlier machines.

Though the 90th percentile is recommended as the level for further investigation of a specific winding, the 75th percentile is a better measure of manufacturing design and process, so the 75th percentile is used in this evaluation. Chart 1 below depicts the 25th, 50th, 75th, 90th and 95th percentiles for each and all of the manufacturers. It is apparent by the chart that for manufacturers D and F, the PD values are higher than typical (ALL), especially for the machines with measured PD levels in the 90th and 95th percentiles. This indicates that for these two manufacturers, the highly PD-active machines are substantially more active than similar machines from other manufacturers.

Chart 2: Motors 6-8kV by year of install (test results of 2009) Discussion ●● The overall trend of the data separated by date of winding for all manufacturers has emerged with an upward trend to indicate that newer machines have more PD activity than older machines, and thus a PD-source problem has developed within the industry. ●● Machines from manufacturers, D and F, have higher PD activity than everyone else.

45

Transformers Vol. 1 PD DISTRIBUTIONS

CONCLUSIONS

The pulse distribution with respect to the AC phase position in the 3D plots can assist in determining the source of any problems in the stator winding. Normal pulse distributions are Gaussian, negative pulses clustered between 0-90° and positive pulses between 180270°, and are indicative of spherical shaped voids within the slot section of the core [Figure 16].

When using a PD measuring system that adequately separates noise and disturbances, monitoring of the PD activity in a running motor or generator stator winding can be as simple as evaluating the trend, comparing to a statistical database, and evaluating the polarity predominance of the pattern. With this configuration, monitoring for most of the failure mechanisms common to stator winding insulation can be quickly and easily evaluated while the machine is subjected to normal thermal, electrical, ambient and mechanical stresses.

Due to space charge effects, a pulse will occur in a specific direction based on the proximity of the void to a metallic substance [Figure 17]. No polarity predominance is normally the result of internal delamination (overheating) of the insulation system that has forced the organic bonding material of the insulation to lose its adhesive strength. Negative PD predominance may be the result of voids created due to either improper manufacturing or thermal cycling that has stressed the bonds between the conductor and the first layers of insulating tape. Due to pulse behavior, positive PD predominance normally indicates PD originating on the surface of the insulation system, such as slot discharge, endwinding tracking, and gradient or semicon coating deterioration. Surface PD happens when a coil does not have intimate contact with the core due to shrinkage, improper installation, bar/coil movement, or perhaps degradation of the voltage stress control coatings.

Fig. 16: Normal PD distribution

Fig. 17: PD polarity predominance

REFERENCES 1

IEEE 1434-2000 “IEEE Guide to the Measurement of Partial Discharges in Rotating Machinery.”

2

V. Warren, G.C. Stone, “Recent Developments in Diagnostic Testing of Stator Windings,” IEEE Electrical Insulation Magazine, September 1998.

3

V. Warren, “Partial Discharge Testing – A Progress Report” Proc. Iris Rotating Machine Conference, New Orleans, LA, June 2009.

4

IEC/TS 60034-27-2 for 1CD, “Part 27-2: On-line partial discharge measurements on the stator winding insulation of rotating electrical machines,” International Electrotechnical Commission, 2011

5

 . Warren, “Partial Discharge Testing – A Progress Report” Proc. V Iris Rotating Machine Conference, Las Vegas, NV, June 2012.

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

46

Transformers Vol. 1

CONSIDERATION TESTING TRANSFORMER PROTECTION SCHEMES PowerTest 2014 Nestor Casilla, Doble Engineering Company

INTRODUCTION Transformer are static apparatus that may suffer for diverse conditions, like short circuits, open circuits, mechanical stress created due external faults or changes in system operation parameters. Transformer protection schemes are complex due to the variety of operating conditions to which they are exposed, the impact on service and repair costs that represents the failure of a transformer. For several decades, the protection relays of power system have undergone many important changes. The technology let us go from electromechanical relays, electronics relays until the microprocessor relays. A modern transformer protection and control system has many features that reflect the trends of integration, such as:

PROTECTION FUNCTIONS FOR POWER TRANSFORMER Transformer Differential Protection It is the most important protection for power transformer due its high speed to detect internal faults. Differential Protection compares an operating current with a restraining current. The operating current (also called differential current), IOP, can be obtained as the phasor sum of the currents entering the protected element: IOP = I1 + I2 Eq 1 IOP is proportional to the fault current for internal faults and approaches zero for any other operating conditions.

●● Differential Protection for two or three winding transformer. ●● Second Harmonic Blocking. ●● Fifth Harmonic Blocking. ●● Restricted Earth Fault Element. ●● Phase Overcurrent Protection. ●● Ground Overcurrent Protection. ●● Over/Under voltage Elements. ●● Frequency Elements. ●● Thermal Element. ●● Events recorder. ●● Fault recorder. ●● Applications based on the IEC61850 standard.

Fig. 1: Basic current differential scheme There are different forms to get the restraining current. The advantage of microprocessor technology is that each manufacturer defines their own algorithms, features and parameters to adjust the differential function. The following table shows some example of formulas to get the restraining current (also known as bias current).

The new protection features must be tested in different system known conditions, which can influence both its performance and safety.

Relay Model

Restraining Formulas

Relay A

Min (Iw1, Iw2,…Iwn)

In this paper, we will review the different models for Differential Protection and how to test them considering the transformer winding configuration.

Relay B

Max (Iw1, Iw2,…Iwn)

Relay C

(a*Iw1 + b*Iw2 +…+n*Iwn)/c

We will cover how to test all protection function using static, dynamic and transient test.

Table 1: Restraining formulas used in differential relays

47

Transformers Vol. 1 The following figure 2 is a typical Differential Characteristic.

TEST PLAN Testing any protection scheme includes visual inspections of the relays, wire connections, and design schematics. There are also several different current transformer tests performed in order to verify proper CT condition and connections. These tests are done when the transformer is out of service. By applying voltage and current, several tests are performed including ratio, polarity, and saturation.

Blocking Function

Relay testing is done by applying settings and verifying the desired outcome. Typical tests include differential/slope, harmonic, minimum pickup, voltage protection, and sudden pressure. For the differential/slope test, two current sources are used to inject current into single-phase relays or three-phase relays with no vector compensation. It is suggested that for three-phase numerical transformer differential relays that have vector compensation settings, especially those that involve zero-sequence removal, three phase current injection into both two relay windings be performed. A harmonic test includes simulating a second and a fifth harmonic current to verify the relay(s) will not operate for overexcitation or inrush current. Relays that employ waveform recognition, for example, to block the differential function from operating during inrush conditions, can be tested by use of COMTRADE files or real-time simulation techniques. Similar types of test file cases could generally be applied to devices without harmonic waveform recognition.

For harmonic blocking, the harmonic content of the differential current must exceed the individual threshold values:

Steady-state tests are widely used to test the pickup value of different protection functions, like:

Fig. 2: Typical Differential Characteristic with two slopes This characteristic consists of a straight line having one or several slopes and a horizontal straight line defining the relay minimum pickup current. The relay operating region is located above the slope characteristic and the restraining region is below the slope characteristic. Transformer Differential Protection has to manage several factors associated with the transformer performance like ratio of currents, phase shift due transformer vector group, inrush current, overexcitation, filtering of zero sequence component, etc.

●● Second Harmonic for inrush conditions ●● Fifth Harmonic for overexcitation conditions.

Restricted Earth Fault Element This element provides sensitive protection against ground faults in wye-connected transformer winding.

●● Pickup of differential function for each winding, overcurrent, undervoltage ●● Pickup of the blocking function for second and fifth harmonic. ●● Differential Characteristic ●● Overcurrent Characteristic

Phase and Ground Overcurrent Protection IED provides numerous overcurrent elements per winding. Phase, ground or negative sequence instantaneous/definite time elements are available for single or three pole feeder protection, breaker failure protection, transformer backup protection, etc.

Transformer and CT Connection Compensation Transformer and CT connection compensation adjusts the sets of three-phase currents for the phase angle and phase interaction effects introduced by the winding connection of the transformer and CTs. Relays have automatic compensation settings based on the protected transformer ratings, vector group, neutral grounding, CT connections and ratios. In many relays the user has the option to select the elimination of zero-sequence components.

Fig. 3: Shows a typical connection to run three phase test. A typical test plan with steady state test can include the following test: ●● Pickup Diff W1 Three Phase test ●● Pickup Diff W1 One Phase test ●● Pickup Diff W2 Three Phase test

48

Transformers Vol. 1

●● Pickup Diff W2 One Phase test ●● Pickup 2nd Harmonic Three Phase Test ●● Pickup 2nd Harmonic One Phase Test ●● Pickup 5th Harmonic Three Phase Test ●● Pickup 5th Harmonic One Phase Test ●● Differential Characteristic

These tests will evaluate the performance of the protection under the following conditions: ●● 2nd and 5th Harmonic blocking function ●● Trip with 2nd and 5th Harmonic ●● Trip with 2nd Harmonic in one phase ●● No operation with 5th harmonic in one phase ●● External fault simulation

●● Overcurrent Pickup W1

●● Internal fault simulation

●● Overcurrent Pickup W2 ●● Overcurrent Characteristic To verify the performance of the protection under real situation, dynamic and transient test should be done.

Figures 4 and 5 show the test configuration and a relay record for the operation during the simulation of internal fault. Digital fault record should be used to verify the performance of the all functions that operate during the test.

Dynamic test can be done with state simulation test and transient test with COMTRADE files.

Fig. 4: Dynamic test to simulate internal fault in the transformer

49

Transformers Vol. 1 REFERENCES

IEEE Std C37.233-2009 IEEE Guide for Power System Protection Testing

1

Fig. 5: Digital fault record of the relay for internal fault in the transformer COMTRADE files can be used to simulate the same conditions with transient tests. Following figures show examples of COMTRADE files:

Fig. 6: Inrush simulation to verify 2nd Harmonic Blocking

Fig. 7: Overexcitation simulation to verify 5th harmonic blocking

2

F6Test Doble Engineering User Guide

3

 ower transformer protection improvements with numerical P relays, A. Guzman, H. Altuve, D. Tziouvaras, Schweitzer Engineering Laboratories, Inc.

4

SEL-387E INSTRUCTION MANUAL, Schweitzer Engineering Laboratories, Inc., Date Code 20110111

Nestor Casilla has 30 years of diverse background in power engineering, including 17 years within the power generation, transmission, and distribution system of oil companies in Venezuela and 13 years as a Consultant Engineer working as Protection Application Engineer and doing protection coordination studies. As a Principal Protection Applications Engineer with Doble Engineering Company, he provides technical support for clients in the US, Canada, and Latin America, training an average of 150 technicians and engineers per year in the application of the Doble Power System Simulation F6150, evaluating different protection schemes, and protection schemes based on IEC 61850. He has participated as a speaker at technical conferences of CIGRE, IEEE, NETA, and Doble Engineering, as well as utilities’ technical conferences in the USA, Mexico, Colombia, Chile, Peru, Brazil, Puerto Rico, India, Canada, and Venezuela.

50

Transformers Vol. 1

I KNOW HOW TO ADD THE NUMBERS – BUT WHAT IS THE POWER FACTOR TELLING ME? PowerTest 2014 Keith Hill, Doble Engineering Company

INTRODUCTION The purpose of this paper is to advance the technical ability of the tester to correctly identify and interpret power factor test data. In the paper I Have a Lot of Numbers, What do they Mean – Basic Interpretation of Two Winding Transformers, presented at PowerTest 2013, the tester learned how to verify that the tests were performed correctly. In this paper, we will dig deeper into the interpretation of irregular test data for the following types of transformers: two-windings, auto with tertiary and three winding. This data will include an excellent example of what we mean by ‘average power factor”. Several case studies for various types of transformers, along with various problems are included in this paper. This data will point out problems that are often encountered in the field and it is often times difficult for the tester to interpret the results. These case studies will detail how to verify the test results and what to look for when analyzing the test data. Some terminology listed in this paper may be new to you so an attempt is being made to identify these components with a brief description. More detailed information can be located in the operator’s manual provided by the manufacturer of your equipment. For this paper it will be assumed that the tester knows how to operate the test set and how to verify that the tests were performed properly. It is important that the tester fully understands the test forms or software being used. It is imperative that the test data for the apparatus be analyzed in the field and not back in the office after the apparatus has been returned to service. One of the most important parts of analyzing test data is to make sure that the tests were performed correctly. Test data will be invalid if the test procedures used were incorrect.

This will include the low side insulation, low side bushings, structural insulating members, and insulating fluid. CHL is used to describe the insulation between the windings, winding barriers, and the insulating fluid.

Fig. 1: Dielectric circuit of a two-winding transformer The CH and CL may be new terminology to both inexperienced and experienced testers who may normally use test equipment manufactured by various manufacturers. CH is the CH insulation minus the sum of the C1 results for the primary bushings. CL is the CL insulation minus the sum of the C1 results for the secondary bushings. C1 is the test performed on the bushings (Figure 2), with a capacitance tap, by energizing the main conductor and measuring to the tap in the Ungrounded Specimen Test (UST) mode.

The following terminology will be used in this paper: CH, CL, CHL, CH , CL , and C1 CH is used to describe all of the high voltage components to ground. This will include the high side insulation, high side bushings, structural insulating members, insulating fluid, and de-energized tap changed, if present. CL is used to describe all of the low voltage components to ground. This will include the low side insulation, low side bushings, structural insulating members, insulating fluid and load tap changer, if present. CT is used to describe all of the tertiary components to ground.

Fig. 2: Main-insulation/C1 test standard method

51

Transformers Vol. 1 HANDY FORMULAS AND THINGS TO KEEP IN MIND

After doing the “math” for Transformer 1, the tester should feel comfortable that the tests performed on the primary were performed correctly since tests 2 and 3 add to be test 1 and that tests 3 and 4 are “equal”.

Power Factor = watts x 10 mA  apacitance = 265 x mA (60 Hz) (Rule of thumb is good up C to about 15% power factor) Capacitance = 318 x mA (50 Hz) (Rule of thumb is good up to about 15% power factor) It must be remembered that a change in current or capacitance from prior tests is a physical change, while a change in watts is usually from contamination or deterioration. From the above power factor formula, one can see that if the capacitance and current are the same that the change in power factor would have to be from a change in the watts. One should remember that when we state “power factor” we should be stating “average power factor” as good insulation and defective insulation are averaged together.

REVIEW OF TEST PROCEDURE VERIFICATION By performing some simple math we can verify that the tests were performed correctly. For the primary winding the summation of the currents and watts for Test 2 (CH) and Test 3 (CHL) add to be Test 1 (CH + CHL). Test 4 is the calculated CHL which is calculated by subtracting the currents and watts of test 2 (CH) from test 1 (CH +CHL). As you can see the CHs will cancel out leaving the CHL. For the secondary winding the summation of the currents and watts for Test 6 (CL) and Test 7 (CHL) add to be Test 5 (CL + CHL). Test 8 is the calculated CHL which is calculated by subtracting the currents and watts of test 6 (CL) from test 5 (CL +CHL). As you can see the CLs will cancel out leaving the CHL. For some test sets, all data is referenced to 10 kV. This means that the CHL insulation tests 3, 4, 7, and 8 should be “equal” even when tested at different voltages. If a difference in the data is noted there may be a voltage related test problem.

Transformer 1 Test Data Test # ENG Test kV 1 H 10 2 H 10 3 H 10 4 H 5 I-2 10 6 L 10 7 L 210 8 L 9 5-6 10

mA 31.889 10.287 21.605 21.605 66.615 45.013 21.613 21.602 6.550 6.550

% PF Meas 1.063 1 ----0.408 0.40 6.550 0.30 6.550 0.30 2.557 ----1.930 0.43 0.622 0.29 0.627 0.29 0.243 0.37 1.534 0.43 Watts

% PF Corr 0.39 0.29 0.29 ----0.42 0.28 0.28 0.36 0.42

% PF Corr 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98

Cap

Meas.

8458.8 2728.7 5730.9 5730.1 17669.8 11939.8 5732.9 5730 1737.47 9366.64

CH+CHL CH CHL(UST) CHL CL+CHL CL CHL(UST) CHL CH’ CL’

Fig. 3: Two winding 67 kV/12.47 kV 15 MVA

The secondary tests were also performed correctly since tests 6 and 7 add to be test 5 and that tests 7 and 8 are “equal”. To verify the results, tests 3, 4, 7, and 8 should be “equal”. (These four tests should be “equal” even when the windings are tested at different voltages). The data for the CH’ and CL’ are the CH and CL without the bushings If taps are not present or the C1 tests were not performed CH’ and CL’ cannot be calculated. Now since the tests were performed correctly the tester should analyze the corrected power factor results. The measured power factor results have not been compensated for the oil temperature. The apparatus or top oil temperature can often time greatly affect watts which will affect the corrected power factor results. All oil filled equipment should be corrected to 20° C (68° F). This temperature correction factor compensates for the different temperatures that may occur for different test periods (hot vs. cold) or loading factors which can often times affect the temperature of the insulating fluid. From the data above you can see that the oil temperature resulted in a correction factor of .98. The measured power factors are multiplied by the correction factor .98 to determine the corrected power factors. The data for Transformer 1 is acceptable as the “numbers” add up correctly and the corrected power factor is below the expected limit of 0.5% for this type of transformer.

Transformer 2 Test Data Test # ENG 1 2 3 4 5 6 7 8 9 10

H H H H I-2 L L 5-6

Test kV 2.5 2.5 2.5 ----1.0 1.0 1.0 -----

mA

Watts

12.920 4.911 21.605 21.605 66.615 45.013 21.613 8.010

3.605 1.268 2.338 2.337 5.620 3.282 2.336 2.338

% PF Meas ----2.58 2.92 2.92 ----3.07 2.33 2.92

% PF Corr .80 2.06 2.34 2.34 ----2.46 2.33 2.34

% PF Corr .80 .80 .80 .80 .80 .80 .80 .80

Cap

Meas.

3426 CH+CHL 1302 CH 2125 CHL(UST) 2124 CHL 4963 CL+CHL 2838 CL 2125 CHL(UST) 2125 CHL CH’ CL’

Fig. 4: Two Winding 2400/480 volt D-Y 750 kVA (As found test results) After doing the “math” for Transformer 2, the tester should feel comfortable that the tests performed on the primary were performed correctly since tests 2 and 3 add to be test 1 and that tests 3 and 4 are “equal”.

52

Transformers Vol. 1

The secondary tests were also performed correctly since tests 6 and 7 add to be test 5 and that tests 7 and 8 are “equal”. To verify the results, tests 3, 4, 7, and 8 are “equal” even when the windings were tested at different voltages. There will be no data for the CH’ and CL’ since the bushings did not have taps. If taps are not present or the C1 tests were not performed CH’ and CL’ cannot be calculated. From the data above you can see that the oil temperature resulted in a correction factor of .80. The measured power factors are multiplied by the correction factor .80 to determine the corrected power factors. Noting that all of the power factor results exceed the recommended limits (1.0%) the tester must determine some of the possible causes for the abnormal test results. Using the information provided that described CH, CL, and CHL the tester can narrow the possible problems. Since CH, CL, and CHL are all higher than the recommended limits, the only thing common to all three insulation systems is the insulating fluid, so if we have contaminated fluid, we have contaminated windings.

Transformer 2 Test Data – after repairs Test # ENG

Test kV

mA

Watts

% PF Meas

% PF Corr

% PF Corr

Cap

Meas.

1

H

2.5

11.810

0.327

-----

-----

.90

3134

CH+CHL

2

H

2.5

4.552

0.143

0.31

0.28

.90

1207

CH

3

H

2.5

7.271

0.182

0.31

0.23

.90

1928 CHL(UST)

4

I-2

-----

7.258

0.184

0.31

0.23

.90

1927

CHL

5

L

1.0

17.040

0.541

-----

-----

.90

4521

CL+CHL

6

L

1.0

9.777

0.356

0.36

0.32

.90

2593

CL

7

L

1.0

9.777

0.179

0.25

0.23

.90

1928 CHL(UST)

8

5-6

-----

7.263

0.185

0.25

0.23

.90

1928

Transformer 3 Test Data Test ENG Test # kV

mA

Watts

% PF Meas

% PF Corr Corr Factor

Cap

Meas.

1

H

10

262.11 10.905

-----

-----

1.00

69525.8

CH+CHL

2

H

10

258.45 10.918

0.42

0.42

1.00

68555.6

CH

3

H

10

3.633

0.0210

0.06

0.06

1.00

963.55

CHL(UST)

4

1-2

3.660

-0.013

-0.04

-.04

1.00

970.200

CHL

5

L

3.

677.76 27.797

-----

-----

1.00

179779.7

CL+CHL

6

L

3

674.08 27.728

0.41

0.41

1.00

178803.1

CL

7

L

2.

3.639

0.0180

0.05

0.05

1.00

965.27

CHL(UST)

8

5-6

3.680

0.069

0.19

0.19

1.00

976.600

CHL

9

251.373 10.732

0.43

0.43

1.00

66678.49

CH’

10

640.064 26.768

0.42

0.42

1.00

169780.4

CL’

Fig. 6: Two Winding 230 kV/25 kV Y-D 900 MVA Please note the data for Figure 6 as the primary currents and watts for tests 1 and 2 are basically the same while the currents and watts for tests 3 and 4 are basically zero. The same is true for the secondary as tests 5 and 6 are basically the same while tests 7 and 8 are zero. This two winding transformer was used in an application from a very high voltage (230 kV) to a much lower voltage (25 kV). Electrostatically shield transformers are used to protect sensitive electrical equipment from undesirable high frequency signals commonly generated by lighting, switching surges, motors, and SCR feeds.

CHL

9

.90

CH’

10

.90

CL’

Fig. 5: As left test After baking the windings and replacing the insulating fluid the transformer now has power factors that are normally expected on a new transformer. A new power transformer (over 500 kVA) would normally be specified to have a power factor less than 0.5%, but in reality one would normally expect to see a power factor that is in the 0.25% to 0.30% range. This 25 year old transformer now has power factor results expected on a new transformer.

Fig. 7: Shielded transformer This shield (Figure 7) is not always represented on a transformer nameplate and this can be very troublesome to a tester since the power factor test results for a shielded transformer will be very different compared to the expected non-shielded results. Since the currents and watts for tests 3, 4, 7, and 8 are often “0” we do not pay a lot of attention to the measured or corrected power factors. A very small current can often result in a very high power factor which in this case is not accurate for the condition of the windings.

53

Transformers Vol. 1 Transformer 4 Test Data Test # ENG Test kV

Transformer 5 Test Data

mA

Watts

% PF Meas

% PF Corr

% PF Corr

Cap

Meas.

Test # ENG Test kV

mA

Watts

% PF Meas

% PF Corr Corr Factor

Cap

Meas.

1

H

10

61.430

2.044

-----

-----

0.97

19556 CH+CHL

1

H

10

32.380

2.558

-----

-----

1.00

8591

CH+CHL

2

H

10

18.110

0.502

0.28

0.27

0.97

5765

2

H

10

9.969

1.855

1.86

1.86

1.00

2644

CH

3

H

10

43.300

1.553

0.36

0.35

0.97

13785 CHL(UST)

3

H

10

22.390

0.694

0.31

0.31

1.00

5941

CHL(UST)

4

I-2

43.300

1.542

0.36

0.35

0.97

13791

CHL

4

I-2

22.411

0.703

0.31

0.31

1.00

5947

CHL

5

L

4

23.260

1.020

-----

-----

0.97

7405

CL+CLT

5

L

2

40.720

1.484

-----

-----

1.00

10803

CL+CHL

6

L

4

6.411

.425

0.66

0.64

0.97

2040

CL

6

L

2

18.320

0.737

0.40

0.40

1.00

4860

CL

7

L

4

16.840

0.612

0.36

0.35

0.97

5362

CHL(UST)

7

L

2

22.400

0.734

0.33

0.33

1.00

5942

CHL(UST)

8

5-6

16.849

0.595

0.35

0.34

0.97

5365

CLT

8

5-6

22.400

0.747

0.33

0.33

1.00

5943

CHL

9

T

52.890

2.688

-----

-----

0.97

16837

CT+cht

9

7.753

-0.15

-0.19

-0.19

1.00

2058.8

CH’

10

T

52.690

2.676

0.52

0.49

0.97

16774

CT

10

11

T

0.179

0.006

0.34

0.33

0.97

57.040 CHT(UST)

12

9-10

.200

0.102

0.60

0.58

0.97

13

ALL

63

CH

CHT CH,CL,CT

Fig. 8: Three winding After performing the math for the primary and secondary windings, for the three winding transformer (Figure 8), it appears the tests were performed correctly. The test results for the tertiary may be questionable as the test results for the tertiary winding are similar to the results for the shielded transformer (Transformer 3). Transformer 4 is not a shielded transformer, however the low voltage winding for this transformer is acting as a “shield” since the low voltage is “guarded” or taken out of the test when performing the tests on the tertiary winding. For test 9 the winding is guarded, test 10 the winding is guarded, and for the UST test the winding is grounded in which case ground current is not measured. Please note Figure 8a for the winding layout.

Fig. 8a: Three winding transformer

1.00

CL’

Fig. 9: Two Winding Transformer Analysis of the data in Figure 9 reveals a very high power factor for test 2 which is the CH. Since CH is the only insulation system that has a very high power factor we do not suspect the oil or any items that part of the secondary winding. From the data on line 9 we determine that C1 tests have been performed on the primary bushings and the CH, without the bushings, now has negative watts. The C1 test data for the primary bushings were:



mA

Watts

% Power Factor

H1 0.761 0.798

10.5

H2 0.736 0.653

8.87

H 30.719 0.555

7.72

Fig. 10 We can see from the above data (Figure 10) that the summation of the watts (0.798 + 0.653 + 0.555 = 2.006 watts) for the C1 test exceeds the watts for the CH (1.855 watts) which makes the watts for test 9 negative ( 1.855 – 2.006 = -0.19).

54

Transformers Vol. 1

Transformer 6 Test Data Test ENG Test # kV

mA

Watts

% PF Meas

% PF Corr Corr Factor

Cap

Meas.

1

H

10

33.080

16.220

-----

-----

1.01

8765

CH+CHL

2

H

10

12.860

3.612

2.81

2.84

1.01

3411

CH

3

H

10

4

1-2

5

L

6 7 8

5-6

20.210

12.610

6.24

6.30

1.01

5352

CHL(UST)

20.220

12.608

6.24

6.30

1.01

5354

CHL

10

59.360

23.630

-----

-----

1.01

15734

CL+CHL

L

10

39.140

11.040

2.82

2.85

1.01

10380

CL

L

10

20.210

12.610

6.24

6.30

1.01

5353

CHL(UST)

20.220

12.590

6.23

6.29

1.01

5354

CHL

Transformer 8 - Two Winding Transformer Acceptance Tests The following transformer data can be devastating for a testing company as it may cost you an excellent customer. The owner of the transformer questioned if you can have “negative” results. He was informed that it was possible but that it was very abnormal and usually was the result of a test procedure error. The first dataset was the results attained by testing company number #1 while the second dataset was provided by testing company #2. Test #

ENG Test kV

mA

Watts

% PF Meas

% PF Corr Corr Factor

Cap

Meas.

9

8.133

3.495

4.30

4.34

1.01

2157

CH’

1

H

2

11.76

0.600

-----

-----

0.71

3121

CH+CHL

10

35.668

10.813

3.03

3.06

1.01

9459

CL’

2

H

2

3.040

0.955

3.14

2.23

0.71

805.9

CH

3

H

2

8.729

-0.350

-0.40

-0.3

0.71

2315

CHL(UST)

4

1-2

8.720

-0.355

-0.41

-0.3

0.71

2315

CHL

5

L

1

15.23

1.634

-----

-----

0.71

4041

CL+CHL

6

L

1

6.514

1.952

3.00

2.13

0.71

1727

CL

7

L

1

8.729

-0.330

-0.38

-0.3

0.71

2315

CHL(UST)

8

5-6

8.716

-0.318

-0.36

-0.3

0.71

2314

CHL

Fig. 11: Two Winding Transformer The data in Figure 11 indicates that the power factor without the bushings (Line 9) is greater than the power factor with the bushings (Line 2). Review of the data indicates that all of the overall power factors are above the acceptable limits for this transformer. Since all of the power factors are elevated one would first suspect that the insulating fluid and windings are contaminated. As stated earlier we are reviewing the average power factors of the insulations. The good bushings made the contaminated winding look “better”.

Transformer 7 Test Data Test # ENG Test kV

mA

Watts

% PF Meas

% PF Corr Corr Factor

Cap

Meas.

1

HL

10

50.720

1.039

-----

-----

1.0

13456

CH+CHT

2

HL

10

22.200

0.528

0.24

0.24

1.0

5890

CH

3

HL

10

28.490

0.518

0.18

0.18

1.0

7557

CHT(UST)

4

1-2

28.520

0.511

0.18

0.18

1.0

7566

CHT

5

T

10

95.080

1.752

-----

-----

1.0

25220

CT+CHT

6

T

10

66.550

1.228

0.18

0.18

1.0

17655

CT

7

T

10

28.490

0.520

0.18

0.18

1.0

7557

CHT(UST)

8

5-6

28.530

0.524

0.18

0.18

1.0

7565

CHT

Fig. 12: Auto Transformer with a Tertiary An auto transformer with a tertiary is actually a two winding transformer. Interpretation of an auto with tertiary is the same as for the two winding. The currents and watts add up correctly so we are comfortable that the tests were performed correctly. All of the power factors are below the acceptable limits, so this transformer is acceptable.

Fig. 13: Data provided by Testing Company #1– ACCEPTANCE TEST The numbers add up (Figure 13) to indicate that the test were performed correctly but the power factors for tests 2 and 6 are well above the recommended limits for a new power transformer. Tests 3, 4, 7, and 8 have negative power factors since the watts for test 2 were greater than the watts for test 1. The watts were also great for test 6 than test 5. The troubling thing about these results is that the tester was asked if the transformer was grounded for the tests and he stated that it was grounded for all of the tests. This “tester” (really a button pusher) had no concern for the high power factors, the negative results for watts and power factors, and the inaccurate report that was provide to his customer.

55

Transformers Vol. 1

Test #

ENG Test kV

mA

Watts

% PF Meas

% PF Corr Corr Factor

Cap

Meas.

1

H

10

11.82

0.314

-----

-----

0.80

3135

CH+CHL

2

H

10

3.206

0.111

0.35

0.28

0.80

850.4

CH

3

H

10

8.616

0.205

0.24

0.19

0.80

2285

CHL(UST)

4

1-2

8.614

0.203

0.24

0.19

0.80

2284

CHL

5

L

1

15.49

0.335

-----

-----

0.80

4109

CL+CHL

6

L

1

6.874

0.123

0.18

0.14

0.80

1823

CL

7

L

1

8.616

0.191

0.22

0.18

0.80

2285

CHL(UST)

8

5-6

8.616

0.212

0.25

0.20

0.80

2286

CHL

Fig. 14: Data provided by Testing Company #2 – RETEST The math for the retest adds up (Figure 14) and the power factors are well below the acceptable limits for a new power transformer. When questioned about these results and what he identified when he arrived on site, the 2nd tester stated that the transformer was not grounded. The tester for the second testing company connected the substation ground to the transformer as it was sitting on the concrete pad ungrounded. Who would you call in the future?

CONCLUSION As one can see, interpretation of power factor test data can be involved and very often time consuming. As mentioned earlier in the paper, it is imperative that the data is analyzed in the field in case other diagnostics tests need to be performed. Do not wait until you get back into the office to perform the math and to analyze the power factors. Do not be a “button pusher”! Keith Hill has been employed at Doble Engineering since 2001, and currently works as a Principal Engineer in the Client Service Department. Keith has over 38 years of experience in substation maintenance, electrical testing, and project management. Mr. Hill is a member of IEEE, a former NETA certified technician, and is a level I and II certified thermographer. Prior to Doble, Mr. Hill was the Electrical Supervisor of Engineering Services for a major refinery. Mr. Hill has published several papers relating to equipment testing and maintenance for various conferences and publications. At the present time, Keith serves as the secretary of the Doble Arresters, Capacitors, Cables, and Accessories committee. Keith received his BS from the University of Houston with a major in Electric Power.

56

Transformers Vol. 1

WATER DISTRIBUTION AND MIGRATION IN TRANSFORMER INSULATION SYSTEMS AND ASSESSMENT OF PAPER WATER CONTENT PowerTest 2014 Lance R. Lewand and David Koehler, Doble Engineering Company

INTRODUCTION Transformers are typically composed of an insulation system consisting of both a solid (cellulosic pressboard, wood and paper) and liquid (insulating dielectric liquid). Water has a direct impact on both the solid and liquid insulation. These systems are complicated, but critical information about the insulation system can be obtained through proper sampling, testing, and monitoring. The collection of water content data can occur in a variety of ways. Real-time online moisture sensors provide end-users with current measured water content and estimated wetness of the solid insulation system. A sample of the insulating liquid can be obtained and tested for water content. When an internal inspection is performed a sample of the solid insulation can be obtained and tested for water content. The amount of water in the insulation system, coupled with loading and operating temperature data, can provide end-users with critical information for operating and maintaining transformers.

SOURCES OF WATER It is important to understand potential sources of the water found in transformers. Table 1 lists typical sources of water within a transformer. Each of these sources should be controlled to help minimize the amount of water in transformers.

Residual after processing (manufacturing, installation, and maintenance) Leaks through weak points of a transformer (gaskets, valves, gauges, plugs) Transformer preservation system (free breathing units, ineffective silica gel breathers, ruptured bladders) Breakdown of cellulose insulation Table 1: Typical sources of water within a transformer

WATER IN THE LIQUID INSULATION ASTM D 1533 is the test most commonly used to determine the concentration of water in dielectric liquids in parts per million (ppm) by weight (mg/kg). The test method is typically referred to as “Karl Fischer” titration, named after the well-known German

chemist that developed this water content test. Oil samples are easily obtained for water content analysis and the corresponding data is most often the source of information on the wetness of the insulation system. Although samples of the solid insulation can be taken, it is not typically done on transformers in the field because of the intrusiveness and extreme cost. Care must be taken when testing for water in insulating materials to minimize ingress of moisture from air while sampling, transporting, and testing. The solubility of water in an insulating liquid changes with temperature. The solubility is the amount of dissolved water the liquid can hold, or 100% saturation. As the temperature increases, the amount of water that can be dissolved in the insulating liquid increases. Correspondingly, as the temperature decreases, the amount of water than can be dissolved in the insulating liquid decreases. These temperature dependent solubility changes are shown in Table 2. Oil Temperature

Water Content in Oil, ppm

0°C

22

10°C

36

20°C

55

30°C

83

40°C

121

50°C

173

60°C

242

70°C

331

80°C

446

90°C

595

100°C

772

Table 2: Water solubility in mineral oil as a function of temperature

57

Transformers Vol. 1 The solubility of water in new electrical insulating mineral oil can be calculated using Equation 1: (Equation 1) Log So = -1567/K + 7.0895 Where: So is the solubility of water in new mineral oil

K is the temperature in Kelvin (∞C + 273.15)

Relative saturation is defined as the ratio of the actual amount of water in the oil relative to the solubility at that temperature. Relative saturation is typically expressed in units of percent and the calculation is given in Equation 2. (Equation 2) RS = Wc / So (100%) Where: Wc is in ppm wt./wt. So is in ppm wt./wt. For example, a sample of mineral oil was obtained for water content determination. The temperature of the mineral oil (recommend using the top oil temperature of the transformer) at the time of sampling was 90°C. The water content of the oil sample was 36 ppm. Using Equation 1, the solubility of water in mineral oil at 90°C is 592 ppm. Using Equation 2, the relative saturation of water in the mineral oil sample is calculated to be 6.1%. Water concentration threshold values have been used for years to determine acceptable water content (ppm) levels in insulating liquids. At 36 ppm of water in mineral oil many guides that are based only on concentration of water in oil would flag this as elevated, regardless of the transformer’s voltage class. However, based on the relative saturation of water in oil this unit would not appear to be as wet as the concentration suggests. It is recommended to use relative saturation values to assess the wetness of the insulting liquid and to begin evaluating the dryness of the solid insulation. At all temperatures the relative saturation of water in oil should remain below 50%. When the transformer’s top oil temperature is above 30°C the relative saturation of water in oil can be used to evaluate dryness of the insulation system. Above 50°C, estimates of the dryness of the solid insulation can be performed using equilibrium curves that are discussed later in the paper. The above example shows the dramatic increase in the mineral oil’s ability to dissolve more water at higher temperatures. Desired water relative saturation levels in insulating liquids are below 5% for dry systems and wet units typically being 10% percent and above.

strength of the solid insulation decreases with increasing moisture content. The water content of the solid insulation also impacts its rate of aging. The aging rate increases in proportion to the change in water content. Therefore, as the water content in the paper doubles so does the aging rate 2. Figures 1 and 2 can be used to estimate the moisture content in the solid insulation. Figure 1 is for water in mineral oil and cellulose insulation using the measured water content in oil. Figure 2 uses relative saturation of water in oil and can be applied to calculated values from water content and solubility data or from measured results from sensors that report in relative saturation. When the relative saturation of the insulating liquid is known, Figure 2 can be used regardless of the type of dielectric liquid. For example, a transformer with a top oil temperature of 30°C has an insulating liquid with a calculated relative saturation level of 11%. Using Figure 2 the water content of the solid insulation is estimated to be 3.5%. It should be noted that using Figure 2 assumes that the transformer’s insulating system is in an equilibrium state with constant uniform temperature and therefore is only an estimate.

Fig. 1: Equilibrium Curve Water in Oil Content (ppm)

WATER IN THE SOLID INSULATION One reason to measure or estimate the moisture content of the solid insulation system is for emergency loading purposes. Transformers may need to occasionally operate at higher than rated loads and temperatures due to numerous factors. The wetter the solid insulation, the lower the hot-spot or insulation temperature needed to induce (water vapor) bubble formation within the insulation system. These moisture bubbles have a low dielectric strength compared to the insulation system and can result in discharge activity and ultimately lead to failure. The dielectric

Fig. 2: Equilibrium Curve Relative Saturation

58

Transformers Vol. 1

The distribution of water in transformers is not uniform. This water distribution is mainly temperature driven. For example, Figure 3 shows different estimated percent water content levels in the solid insulation system for a naturally cooled (ONAN) transformer with a 98°C hot spot.  This assumes that the moisture is distributed with the thermal gradient under equilibrium within each temperature zone.  In a forced cooled (OFAF) transformer the temperature difference between the hot spot and the bottom section of the solid insulation is less and the associated moisture distribution within the transformer is much smaller. 

Fig. 3: Non-Uniform Moisture Distribution

DIELECTRIC STRENGTH The dielectric breakdown voltages of insulating liquids are influenced by the water content. The data shown in Figure 1 was obtained through laboratory testing conducted at standard room ambient conditions. ASTM test method D1816 with a 1 mm gap was used for the dielectric strength testing. The dielectric strength of an insulating liquid is also adversely impacted by the type and number of particles present in the insulating liquid. The data obtained in Figure 4 focused on the impact of water to the insulating liquid’s dielectric strength, thus clean/dry/filtered insulating liquid was utilized to obtain the dielectric breakdown strength data 2.

Fig. 4: Dielectric strength as a function of water content and relative saturation Figure 4A shows the water content in ppm and associated dielectric breakdown voltage of the oil at room temperature. Through the use of the Equations 1 and 2, Figure 4B was derived and shows the data correlation between the insulating liquid’s relative saturation and dielectric breakdown voltage. The dielectric breakdown voltage is a function of the relative saturation of water in oil. If the oil temperature had been altered, Figure 4A would no longer be correct while Figure 4B would be very consistent.

CASE STUDY In order to apply the previously discussed water dynamic principles, Figure 5 will be reviewed. Figure 5 shows online moisture data from a transformer for a period of two days. As the operating temperature of the transformer increases, the relative saturation of water in oil initially decreases as it takes time for the water to move out of the solid insulation into the oil and reestablish a steady state. The concentration (ppm) of water in oil is very low (1.5 to 2.4) and increases with the increasing insulation temperature. The estimated water content of the solid insulation decreased slightly as a new steady state was established at the warmer temperature which typically provides more reliable estimates of moisture in paper. The data was collected using a continuous water in oil sensor with a moisture model, which utilizes an intial learning process to estimate the moisture content in the paper insulation system 3. This transformer’s insulation system would have been considered relatively dry. This example demostrates the continuous water migration associated with changing operating temperatures that occur in transformers. Online moisture data should be reviewed for a longer period of time to allow for a more defenitive overview of the transfomer’s temperature cycling and associated water distribution. Typically, 3 or 4 days at top oil temperatures above 60°C are needed. More drastic temperature dependent changes in water content and relative saturation would have been noticed had these same measrurements been conducted on a transfromer with a wetter insualtion system.

Fig. 5: Online moisture distribution data for two days

THERMAL MODEL Figure 6 shows the results of a laboratory experiment with wet solid insulation. The data is derived from a continuous water sensor in a laboratory model oil-paper system. The paper insulation was very wet, the oil was stirred and the model contained temperature control of the oil. The temperature was cycled to evaluate the mositure migration in a wet insulation system 3.

59

Transformers Vol. 1 As the temperature was increased, the relative saturation level of moisture in the oil decreased until the water had sufficient time to migrate from the paper to the insulating liquid. As the temperature stabilizes, the relative saturation of water in oil continues to increase and then stabilizes. As the model temperature decreased, the relative saturation of water in oil increased. The migration of the water from the insulating liquid to the paper takes time and slows as the diffusion time constants of water in paper decreases with decreasing temperature. As the relative saturation of the water in oil increases, the associated dielectric breakdown voltage decreases. As shown in Figure 3B, when the relative saturation of water in oil approaches fifty percent, the dielectric breakdown voltage is significantly lowered. The relative saturation of water in oil approaches a steady state as the temeprature in the model holds steady for a period of time. The migration of moisture between the solid and liquid insulation systems is not instantaneous, but occurs over a period of time that is temperature and moisture content dependent. The outer layers of the paper insulation tend to react more quickly to the thermal transients as the diffusion into the inner layers have longer time constants.

Fig. 6: Wet solid insulation thermal cycling

CONCLUSION The dynamics of water migration between a transformer’s liquid and solid dielectric insulation systems have been discussed. Understanding the amount of water in the insulation system is critical to minimize failures, reduce the rate of aging, and maintain appropriate dielectric breakdown strength. Various methods available to calculate or estimate the overall wetness of the insulating system have been discussed.

REFERENCES 1

Lewand, L.R. “Understanding Water in Transformer Systems: The Relationship Between Relative Saturation and Parts per Million”, NETA World, Spring 2002, pp. 1-4.

2

 riffin, P. J. “Water in Transformers – So What!”, National Grid G Condition Monitoring Conference, May 1996.

3

 ewand, L.R. and Heywood R., “Application of a Continuous L Moisture-In-oil Sensor For On-Line Transformer Monitoring”, Annual International Conference of Doble Clients, 2000, Sec. 5-4

Lance Lewand is the Laboratory Director for the Insulating Doble Insulating Materials Laboratory and is also the Product Manager for the Doble DOMINO., a moisture-in-oil sensor. The Insulating Materials Laboratory is responsible for routine and investigative analyses of liquid and solid dielectrics for electric apparatus. Since joining Doble in 1992, Mr. Lewand has published over 75 technical papers pertaining to testing and sampling of electrical insulating materials and laboratory diagnostics. Mr. Lewand was formerly Manager of Transformer Fluid Test Laboratory and PCB and Oil Field Services at MET Electrical Testing Company in Baltimore, MD USA for seven years. His years of field service experience in this capacity provide a unique perspective, coupling laboratory analysis and field service work. Mr. Lewand received his Bachelor of Science degree from St. Mary’s College of Maryland. He is actively involved in professional organizations including the American Chemical Society, a representative of the U.S. National Committee for TC10 of the International Electrotechnical Commission (IEC) and ISO TC28, ASTM D-27 since 1989 and is the sub-committee chair 06 on Chemical Tests, ASTM Committee D-27 Vice-Chair, and a recipient of the ASTM Award of Merit for Committee D-27. David Koehler received his Bachelor’s Degree in Chemistry from Indiana University and his M.B.A. from Indiana Wesleyan University. He has over 16 years of experience in the testing of insulating fluids and management of analytical laboratories. He has provided numerous technical presentations and published technical articles within the power industry. David has the following industry affiliations: Doble Engineering Insulating Materials Committee Asst. Secretary, Chair IEEE-Central Indiana Section, IEEE Region 4 East Area Chair, IEEE Region 4 Strategic Planning Committee, Senior Member IEEE, ASTM D-27 Technical Committee on Electrical Insulating Liquids and Gases, and in 2011 was an Executive Committee Member of the Indiana American Chemical Society and remains active within ACS.

60

Transformers Vol. 1

DECISION SCIENCES: WILL THIS BE ON THE TEST? PowerTest 2014 Nicholas Perjanik, Weidmann Diagnostic Solutions

ABSTRACT Much of the work in determining industry diagnostics, specifications, and guidelines for equipment maintenance practices has been based on field and laboratory data, empirical studies, and to a large degree common sense or other holistic methods. With the use of analytics increasing in many industries, current research involving decision support systems and the use of decision trees, probability models, simulations, fuzzy logic and even artificial intelligence are being applied to transformer maintenance diagnostics. Testing often generates results that are simply either “acceptable” or “not acceptable.” What is missing in the diagnostic process is an understanding of how to make a decision and take action based on these results. This area of knowledge is referred to as decision sciences. This paper begins with a brief review of the decision making process and how one converts data to information, information to knowledge, and then chooses between the alternatives to make an optimum decision. After providing an overview of DSS techniques, an application of dissolved gas analysis and the role that decision sciences play in the maintenance and diagnostic testing of electrical equipment is provided. The purpose of the paper is to present a general, introductory, yet not too technical overview of how decision sciences are being utilized in the electrical equipment testing and diagnostic field. Real world examples will be provided to support the techniques and illustrate the potential for its use. This paper is presented in three sections including; (1) a section on the theoretical foundation of Decision Sciences and Decision Support Systems (DSS), (2) a section of current research relating to DSS, and (3) a section on DSS applications and advancements in electrical insulation fluid diagnostic decision tools.

PAPER OUTLINE Section One: The first section (a) analyzes the decision making frameworks of Simon, Anthony, Gorry and Scott-Morton, and Huber in terms of their underlying principles regarding organizational management, (b) compares the theoretical foundations of Simon, Anthony, Gorry and Scott-Morton, and Huber and their perspectives on organizational management, and (c) discusses the relationships between of organizational management decision-making foundations and how the theories contribute to organizational management.

Section Two: The second section discusses and synthesizes the literature relating to current research, methods, and analyses of DSS. It evaluates the strengths and weaknesses of methods utilized in DSS, and it analyzes the applications of DSS in various industries. Section Three: The third section evaluates application of DSS in various industries and its application to Dissolved Gas Analysis (DGA). Examples of various novel approaches are presented and opportunities for new approaches to DGA diagnostics and decision making tools are introduced. A complete reference list concludes the paper. While the paper covers topics ranging from decision theory to the application of Microsoft Excel Add-in tools, the goal of the paper is to provide new and existing users of DGA with new and upcoming approaches for converting analytical data to information, and information to actionable information through improved diagnostic decision making tools.

PRESENTATION OUTLINE I. Tacit vs. Explicit Knowledge II. Decision Making Fundamentals III. Decision Support Systems (DSS) IV. Predictive Analytics V. Modeling VI. DGA Applications

SECTION 1: Theoretical Foundation of Decision Sciences and Decision Support Systems (DSS) Whether one believes that a good manager is born or made, Simon (1997) used the insightful term that good managers are those capable of making good choices or decisions. If one believes the foundation of a good manager is determined and influenced by the environment or structure provided, that person would support Archer’s (1964) decision theory that a foundation is needed that “attempts to give structure and rationale to the different conditions under which decisions are made (p. 269).” After first requiring that a problem existed in need of an action, Huber (1980) defined the terms decision making as “the process through which a course

Transformers Vol. 1 of action is chosen” and problem solving as the “the conscious process of reducing the difference between an actual situation and an actual situation and the desired situation (p. 9).” The theories and foundation to modern day decision sciences originated from the developing ideas of Simon (1960, & 1997), Archer (1964), Anthony (1965), Gorry and Morton (1971), and Huber (1980). Beginning with the idea that the continued use of computers combined with improved technologies and operational techniques, would significantly destroy the worker and change middle management decision making processes, Simon (1997, p. 22), provided five metaphors for the changes to decision making and the role of managers. These included: (1) The computer is an incredibly powerful number cruncher, (2) The computer is a large memory, (3) The computer is an expert, and (4) The computer is a giant “brain,” cable of thinking, problem solving, and yes, making decisions. During the period from 1966 to 1971, Gorry and Morton recognized the technological progress that had been made and stated that “we are adding to our knowledge of how many human beings solve problems and how to build models that capture aspects of the human decision making processes (p. 56).” According to Simon (1960), “the problem-solving and information-handling capabilities of the brain have proved to be the easiest to duplicate, and great progress has been made in this direction (p. 24).” In looking at the process of mechanizing a process, Simon added that “when we have mechanized one part of the manufacturing sequence, the regularity and predictiveness secured from this mechanization generally facilitates the mechanization of the next stage (p. 26).” Seen as a natural progression of mechanized systems, Simon concluded that “our earlier conclusion that humans are likely to retain their competitive advantage in activities that require sensory, manipulative, and motor flexibility (and, to a much lesser extent, problem-solving flexibility) (p.26).” With the end of World War II and the integration of the computer into management applications, the field of decision sciences was originally referred to by Simon (1960) as operations research and management science. The result of this was the initial introduction of mathematical tools and techniques in the early 1950s. Simon was considered by many as a controversial researcher in his early works - he was also considered the bearer of bad news. It was based on the fear that computers were going to “dehumanize” work and be detrimental to the worker of the future. In addition, there were fears that the rapid changes in technology were going to be too much for people to deal with, and mentally that computers would alienate workers by reducing work to non-motivating tasks. As a response to Simon’s (1960) view of technology, and the affects of computers and office automation on the workplace, the fear of unemployment grew. Simon’s response was based on the belief that unemployment would not be a net result, but rather that those employees experienced with tedious routine functions would move to different types of positions as a new “equilibrium” was established. Simon supported this belief by stating that

61 the decrease in the number of factory and clerical level workers would be offset by the increased number of more technical workers. In addition, Simon projected that the quality or satisfaction level of workers in this new equilibrium would be higher. Regarding the quality of work and the worker’s involvement in their working environment, Simon (1960) stated that workers were more content working in organizations where responsibility for the decision making process, and ownership of the challenging decisions, were made by the workers themselves - when they were vested in the process. With the increased complexity resulting from the sharing of the decision making process, the decision making process was seen as having added constraints and often conflicting goals to consider. In regard to making decision in these real life situations, Simon (1997) later supported his earlier view: A course of action, to be acceptable, must satisfy a whole set of requirements, or constraints. Sometimes one of these requirements is singled out and referred to as the goal of the action. But the choice of constraint from many is to a large extent arbitrary. For many purposes it is more meaningful to refer to the whole set of requirements as the (complex) goal of the action. This conclusion applies both to individual and organizational decision-making. (p. 155) In addition to the issue of unemployment, Simon (1960) made several other projections relating to the implementation of computers and office automation into the managerial workplace. The first prediction was that the use of technology would continue to rise throughout the organizations from middle-management to senior executives. The second was that managers would be working in environments where the complete organization commitment of those supporting the technology would benefit from its use in multiple ways. The third projection was that as new decisionmaking techniques were accepted into practice, a better understanding of the external environmental would improve the overall success of the organization. According to Simon (1960), it was the responsibility of the executive to not only make good decisions, but build into the organization a system that enabled others to do the same. He pointed to the fact that just because someone was able to make effective decisions, it did not mean that they could also build effective decision making systems. One of the significant contributions of Simon was his recognition of the difference between the decision making process utilized by lower managers and that of senior managers. Simon (1960) had defined decisions as being made along a spectrum. At the ends, the decisions were categorized as either programed or non-programmed (also referred to as un-programmed in later work). Programmed decisions were those highly repetitive and routine decisions. They did not typically require additional information to make the decision. At the other end of the spectrum were non-programmed decisions. These applied to situations when it was “novel, unstructured and unusually consequential (p. 46).”

62 A decision that required any unique consideration, an additional variable, was new, or required a different method of looking at the situation was considered non-programed by Simon. In this case, the decision did not have a standard procedure to solve it. Through learning, managers were capable of making nonprogramed decisions that improved incrementally with experience. When faced with decisions that were within the capacity of the manager, the decision making process could improve on a continuous basis and be balanced along the spectrum. In complex situations or in the more analytical decision making circumstances, Simon (1960) pointed to “Gresham’s Law of Planning” which stated that “programmed activity tends to drive out nonprogramed activity: if an executive has a job that involves a mixture of programed and non-programed decision-making responsibilities, the former will crowd out the later (p. 53).” Simon (1960) generalized that while executives tended to focus on un-programmed decisions in general, one could not unilaterally relate the level of programmed/un-programmed decisions to the level of management within the firm. As an additional perspective, while Simon referred to the programmed end of the spectrum as operations research or management science, those un-programmed decisions that related to heuristic programming or artificial intelligence landed at the opposite end of the spectrum. In general, a significant portion of managerial decision making land somewhere in between. While a generalization, Simon (1960) acknowledged that there was a rough correlation between the level of the manger and the degree of programmed and un-programed decisions made. Both terms, operations research and management science, were often associated with the modeling and programming observed in the decision making process of programed decisions. Originating from operations research, Simon noted that the concept of a “systems approach” or the idea of looking at the situation in its entirety and designing the components to operate within that system came from the introduction of mathematical tools from World War II. In Simon’s (1960) examination of the manager as the decision maker, the idea of the decision making as a process was presented. Accordingly, Simon stated that the process was “comprising of four phases: finding occasions for making decisions (intelligence activity), finding possible course of action (design activity), choosing among courses of action choice activity), and evaluating past choices (review activity) (p. 40)”. While these were the major components, the cycle, the possible omission of a phase, and the actual carrying out of the decision still needed to be understood. In this process, Simon stated that “technology is knowledge: knowledge of how to make things, but also knowledge of how to do things. It is knowledge that broadens the range of alternatives before us (p. 165).” Following Simon’s work on the classification of decisions lying along a programed to non-programed spectrum, Huber’s (1980) published Managerial Decision Making and introduced three

Transformers Vol. 1 reasons for improving on Simon’s (1960) managerial decisionmaking process. These included recognizing the importance that these decisions could have on a manager’s career, the belief that improving the performance of the organization was a result of making their decisions, and the recognition of the time and effort that a manager puts into making the these decisions. Huber’s (1980) contribution to Simon’s work included the identification of the three types of decision situations one takes while considering decision alternatives. The first was referred to as the conspicuous-alternative situation characterized by the acceptance of the most acceptable and immediate alternative. Huber’s second and third situations where referred to as the multiple-alternative situation and the situation when there were no acceptable alternatives respectively. It was during the second step of Simon’s (1960) decision-making technique that the focus on maximizing the alternatives was highlighted. Huber (1980) recognized that the “the benefits gained from choosing the best alternative are large (p. 17)” and extended the foundation of Simon’s (1960) four step problem solving process. Huber’s process included: (a) exploring the nature of the problem, (b) generating alternative solutions, (c) choosing among alternate solutions, (d) implementing the chosen alternatives, and (e) controlling the solution program. Again, Huber emphasized that the choosing among alternatives step was important and that having a systematic process to address it was most needed. A component of Huber’s (1980) decision-making process was the definition for “valuing” the decision-making choice of alternatives. Huber saw the value as resulting in the difference between the actual and the potential quality of decisions between each alternative. In trying to quantify the outcomes of decisions and choosing between alternatives, Huber considered the situational views that the gaps between “what we think it is” and “what we think it could be,” and “what it is” and “what it actually could be” were approximately equal. Huber concluded that it was the actual difference in the later that tended to be larger than the perceived difference: the actual value difference between alternatives is larger than what we think it could be. In summary, the differences or believed values from alternatives were not always representative of real world value: They were often undervalued during the decision making process. While Huber (1980) introduced the idea and recognized the need for quantifying the value of the decision making process, he also recognized that decisions were often made based on being “good enough,” This idea of good enough supported March and Simon’s (1958) concept of satisficing - the process of analyzing alternative choices or solutions, and then choosing the first alternative that met or satisfied the basic requirements for the decision. As it is defined here, the assumption could be made that the first satisficing decision may not necessarily be the best decision: it was good enough to end the analysis of alternatives. Lindblom (as cited in Huber, 1980, p.27) stated that an alternative approach

Transformers Vol. 1 to satisficing involved moving on the first of the alternatives where “the actual and the desired condition is at least tolerable”. Both of these methods were referred to “heuristics”, “educated guesses”, or “rules of thumb”. These are today’s common forms of March and Simon’s satisficing: accepting a solution prior to fully considering all alternatives. Huber (1980) also noted an important concept, one that is still often missed and overlooked in optimizing the decision model. This concept was based on the potential risk of bad decisions being made as a result of an incomplete decision making process. When a full consideration of all the information is not made, especially when the information most critical to making the best decision is not considered, the decision making model was considered by Huber as being an “inadequate model.” In regard to all decisions, Simon (1997) later stated they are all a matter of compromise, and that “the alternative that is finally selected never permits a complete or perfect achievement of objectives, but is merely the best solution that is available under the circumstances (p. 5).” Simon went on to recognize that “decisions are seldom directed toward a single goal; rather, decisions are concerned with discovering course of action that satisfy a whole set of constraints (p. 163).” The idea that multiple goals, multiple constraints, and multiple variables could be involved in a satisficing manner was introduced by Simon (1997). In responding to decisions involving a set of considerations or simultaneous equations, Simon (1997) stated that decisions would be limited “by existing or prospective computational equipment (p. 160).” In addition, Simon stated that in these cases, “particular” decisions could be made by separate particular units within the organization. In making their decisions, those closest to the decision find a satisfactory solution for one or more of the components or sub-problems. When brought together, these subproblems connect and result in a satisfactory solution. According to Simon, the ability to consider all factors and all complexities in the process would be limited by one’s cognitive inability: the cognitive capability of seeing the whole problem. With this understanding, Simon recognized that “administrators satisfice rather than maximize, they can choose without first examining all possible behavior alternatives and without ascertaining that these are in fact all the alternatives (p. 119).” As noted by Huber (1980), the process of analyzing alternatives was an important stage of the decision making process for organizational management. Choices, as they are referred to by Archer (1964) are made when a manager is forced to choose among alternate strategies and “elects one strategy over others based on criteria such as minimum cost, greatest rate of return, maximum sales, or some combination of criteria or objectives (p. 269).” Interchangeable with the terms alternatives and choices, Archer preferred the use of strategies to note the number of options to choose from and proposed that the number of strategies may “vary from two to infinity (if there were only one, there would be no decision) (p. 271).”

63 The process of choosing between alternatives may involve a more complex process than it would appear. For example, Archer (1964) noted it was possible that “all possible alternatives are not enumerated or considered (p. 271)” and there may be rules in place that would strike out particular alternatives. In many cases, the elimination from consideration of specific strategies would be based on the experience of the manager. There were other cases where the probability of a satisfactory solution was small, relative to the cost of obtaining it, so the consideration of that alternative may have been omitted. In the end, Archer recognized that choosing the right number of alternatives to choose between was a very important problem to address. ­­ regard to the number and reducing alternatives or strategies, In Archer (1964) concluded that in most cases, only a limited range of all possible strategies are considered. The use of practical techniques could be used for “eliminating strategies from further consideration—those which are known not to be considered as successful in achieving the objectives (p 271).” Archer summarized that in eliminating certain strategies, consideration is made based on “the probability of their satisfactory payoff to be so extremely small as not to be worth the cost involved in further consideration (p. 271).” Archer’s (1964) concept that “a manager must choose among alternative strategies (p. 269)” was later accepted by Simon (1997). Simon proposed that “it is the process by which one of the alternatives for each moment’s behaviors selected to be carried out. The series of such decisions which determines behavior over some stretch of time may be called a strategy (p. 77).” Included in this position was Simon’s belief that “the function of knowledge in the decision-making process is to determine which consequen es follow upon which alternative strategies (p. 78).” While Archer’s earlier view was that decisions result from some process, Simon later concluded that the decision maker, with an “expectation” of a future outcome, considers alternatives based on the information and experience of current and past decisions and then chooses based on that knowledge. Following Gorry and Morton’s (1971) statement that “Anthony addresses the problem of developing a classification scheme that will allow management some perspective when dealing with planning and control systems (p. 57),” they presented three categories of management activity in their taxonomy. The first category was strategic management, focusing on both the objectives of the organization and on those issues facing higher-level managers that are of the non-repetitive and creative form. This category was representative of Simon’s (1960) earlier definition of non-programed decisions. The second category was management control which referred to the process of managing the resources of the organization: those actually involved with human participation. The third category was referred to as operational control and addressed the effective and efficient use of the processes involved in managing the tasks associated with the process.

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In regard to these classifications, Anthony (1965) stated that with the irregular nature of the situations or problems addressed, there was not a general approach or model available to address strategic planning. In addition, with the primary source of information being obtained from external sources and the summary of the information leading to imprecise estimations, the strategic planning process resulted in “expected results of the future.” To Anthony, the idea of expected results was in contrast with the use of detailed internal information generated to assist managers with taking the best action leading to desired results. Anthony distinguished this difference as a defining characteristic of the management and operational control classifications – a topic addressed in much detail by Gorry and Morton (1971).

Where Simon (1960) considered management in regards to the two types of decisions made along a spectrum, Gorry and Morton (1971) approached their organizational management and the relative functions of each by considering three categories of management activity and the sources of the information used. While Anthony’s (1965) three classifications of management activity each required information from different sources and at different levels of detail, Gorry and Morton stated that “the information needed by strategic planners is aggregate information, and obtained mainly from sources external to the organization itself (p. 58 ).” With the type of information ranging from broad and external to narrow and defined, the respective differences in strategic planning to operational control are the extremes of Anthony’s categories.

In evaluating Anthony’s (1965) three categories including strategic planning, management control, and operational control, Gorry and Morton (1971) stated that at the highest level, managers should have analytical and reflective skills, versus skills associated with communication and procedures. On the topic of Anthony’s operational control, Gorry and Morton (1971) added that “the decision process, the implementation process, and the level of analytical sophistication of the managers (as opposed to the staff) in strategic planning all differ quite markedly from their counterparts in operational control (p. 67).” It was concluded that that in terms of operational control, decision makers experience more constrained control.

While Gorry and Morton (1971, p. 59) stated that “Anthony’s classification of managerial activities is a useful one for people working in information systems design and implementation”, and they recognized that Simon’s (1960) approach to solving problems and focusing on the structure of the decisions was dependent of one’s organizational position, they did accept Simon’s classification that decisions could land along a spectrum from programed and non-programed based on the extent that the situation was “repetitive, routine, structured, and complex”. Gorry and Morton chose to refer to the programed and non-programed terminology as structured and unstructured respectively.

Anthony (1965) had defined strategic planning as “the process of deciding on objectives of the organization, on changes in these objectives, and on the policies that are to govern the acquisition, use, and disposition of these resources (p. 16).” This was in contrast to his definition of management control defined as “the process by which managers assure that resources are obtained and used effectively and efficiently in the accomplishment of the organization’s objectives (p. 17).” As noted by Anthony, this second process involved managers, utilized the objectives created in strategic planning, and focused on effectiveness and efficiency. True operational control was approached in a similar manner by Simon (1960) – noted as being somewhere between management control and operational control based on “the use of judgement”. While judgements are made in management control, the process is made with the aid of decision rules at the operational control level. Anthony (1965) referred to these differences in a similar manner to Simon’s (1960) non-programmed and programmed decision model and the classifications of management and operational activities. Anthony defined operational control as the process of assuring that specific tasks are carried out effectively and efficiently and noted that the main difference between managerial and operational control was the concern for managers over that of the tasks. In presenting the three classifications, Anthony stated that each should not be considered as a discrete entity. Like Simon’s range of decision types, Anthony recognized that the activities occur over a continuum with overlapping characteristics and criteria.

Decision making in organizational management has been categorized, classified, and approached from multiple perspectives. Gorry and Morton’s (1971) approach acknowledged that “research on human problem solving support’s Simon’s claim that all problem solving can be broken down into three categories (p. 60).” The three categories in Simon’s (1960) decision-making process including intelligence activity, design activity, and choice activity were also considered in Anthony’s (1965) approach. Gorry and Morton (1971) stated that Anthony’s categorization was based on management activity while Simon classified the process by the way that the manager approached the problem at hand. It was earlier noted by Simon (1960) that operational control in the decision classifications was based on the use of judgement. Anthony (1965) related judgement to the specific classification types of strategic planning and managerial control: the first being driven by judgements and the latter being based in facts. Simon’s (1997) concept of judgement was extended to consider four key decision making concepts including: (1) rationality, (2) efficiency, (3) maximum utility, and (4) payoff. Additional scrutiny and an understanding of these concepts provides the foundation for determining the real contributions made by Simon on the decision making process. In regard to knowledge and rationality, Simon (1997) stated that knowledge and experience were involved in the choosing of alternative strategies. Simon concluded that the decision maker, with an “expectation” of a future outcome, considers alternatives based on the information and experience of current and past decisions and

Transformers Vol. 1 then chooses based on that knowledge. For Simon, “Knowledge is the means of discovering which of all of the possible consequences of a behavior will actually follow it (p. 85).” In regard to one’s ability to make decisions, he added that “decision-making processes are molded by limits on their knowledge and computational capabilities (bounded rationality) (p.20).” Simon’s (1997) view of rationale comes from the following perspective:

A decision is rational from the standpoint of the individual (subjectively rational) if it is consistent with the values, the alternatives, and the information which he weighed in reaching it. A decision is rational from the standpoint of the group (objectively rational) if it is consistent with the values governing the group, and the information that the group possesses relevant to the decision. (p. 324)

According to Simon (1997), “the task of the rational decision is to select the one of the strategies which is followed by the preferred set of consequences (p. 77).” With different perspectives used in considering a decisional rational, Simon encouraged clarifying the definition of the term “rational” by considering it in the proper context. He recommended an appropriate adverb be added to the term such as “subjectively” rational, “consciously” rational, “deliberately” rational, organizationally” rational, or “personally” rational to clarify the perspective. When making decisions with multiple factors, one must be aware of and address the idea of limits on rationality - a term defined by Huber (1980). This concept referred to one’s ability or capability to consider all facts and considerations and to make a decision that is of lower quality than it could be. Due to the ability to only handle or consider a finite amount of information, the concept recognizes that the human thinking process is limited by its capacity to handle all of the information required to address all of the potential alternative solutions. This idea of a limit on rationality was earlier recognized by Simon when he stated that the capacity of the human mind could not objectively make decisions while considering all of the information available in the real world. In 1980, it was evident to Huber that the human mind was limited and was not sufficient for making comprehensive complex solutions in short periods of time. He noted that various methods would be needed to simplify the process and increase the speed. In the choosing of alternatives for example, Simon (1997) recognized that three major limitations existed. Simon’s first limitation addressed the “incompleteness of knowledge.” Having a complete picture of the consequences was not always possible. Due to the limited capacity of individuals, it would be assumed that all information regarding an alternative would not be known. Simon’s second limitation involved “Difficulties of Anticipation.” In choosing an alternative, the anticipated benefit of choosing an alternative measured in terms pleasure, satisfaction, or expected experience may not be as realized. In addition, the valu-

65 ation may not be consistently measured across all of the alternatives. Simon’s third limitation addressed “The Scope of Behavior Possibilities.” Basically, this related to the limited ability that one has to consider all aspects of an alternative - what Simon referred to as “all aspects of value, knowledge, and behavior that would be relevant (p. 117).” With limited capacity and a natural tendency to value variables based on a ranking, it was possible that certain components or variables within the alternatives could be omitted or provided less weight than warranted. Considering the second key concept involved with making a judgement, Simon (1997) related the idea of rationality to efficiency by stating that decisions are “largely determined by a principle that is implied in all rational behavior: the criterion of efficiency (p. 12).” This principle is based on the idea that one would take the most straight forward and simplest path to obtain desired results. In considering the criterion of efficiency in organizational decision-making, Simon stated in situations with “two alternatives having the same cost, that one can be chosen which will lead to the great attainment of the organizational objectives; and that, of two alternatives leading to the same degree of attainment, that one be chosen which entails the lesser cost (p. 150).” Simon proposed that according to this principle, organizations will select the alternative from all available options which will provide the greatest net financial return. Simon added that the principle was “applicable to the process of decision where factors are involved that are not directly measurable in monetary terms (p. 251).” In summary, Simon concluded that the criterion of efficiency was the guiding management force that “dictated” the choice of alternatives with “the largest results for the given application of resources (p. 256).” He added that the principle was an organizational management tool to guide administrators. Recognizing that efficiency related to the largest return for a given application of resources, Simon (1997) proposed that the measurement of the ratio of the results obtained to the quantity of resources consumed, was an “appropriate and fundamental criterion” for all organizational decisions. In considering organizational decision making objectives, Simon acknowledged that it was the merging of the individual’s values and objectives with those organizational objectives that guide the decision making process of the organization. This process, referred to as identification, occurs when “a person identifies himself with a group when, in making a decision, he evaluates the several alternatives of choice in terms of their consequences for a specified group (Simon, 1997, p. 284).” The idea of determining individual and group decision efficiency in organizational management decisions led Simon to the idea of maximizing utility. The concept of utility is the third key concept in the judgement making process. Once alternatives are identified, the next step in the process is to determine a value from which to compare the alternatives – also referred to as utility. Archer (1964) had earlier stated that “the process in a broad sense includes: (1) the activities of discovering and defining things to decide about; (2) determin-

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ing the objective of the organization; and, (3) the enumeration and preparation of the alternative ways of making a decision (p. 269).” Simon (1997) referred to this stage as valuation. Whether the ranking of the alternatives is based on a financial figure, or any other preferred outcome, a ranking of alternatives is created and becomes the basis for comparing alternatives and consequences. For organizational decision making, Archer (1964) stated that “the manager elects one strategy over others based on criteria such as minimum cost, rate of return, maximum sales, or some combination of criteria or objectives (p. 269).” The key point made by Archer was that the choice of alternatives was based on the strategy or goals of the organization.

Simon’s (1979) judgement making process. This idea of determining a payoff relates back to Archer’s (1964) statement that in cases of choosing between alternatives, the strategy chosen should be based on achieving the largest or smallest payoff depending on whether one is considering a maximizing or minimizing decision. Archer indicated that the final decision should be based on a systematic process that considers the states of nature, the probabilities of their outcomes, and the alternatives or strategies chosen. With the potential of multiple payoffs, Archer also recommended calculating a weighed probability for each state of nature and then reaching an optimal decision by selecting the strategy that “optimized expected value.”

Archer (1964) supported this position by stating that “in the organization, the mix of specific goals that maximizes his [the manger’s] utility includes, among other considerations, achieving what he believes others feel should be the organizational goals (p. 270).” In reality, the manager balances what is perceived as the highest utility, with what others believe is the maximum utility to the organization. Considering the goals of the manager and their alignment with the organization’s goals, Archer stated that the goals include one’s personal objectives and are most likely influenced or “reshaped and modified” by all stakeholders (i.e., stockholders, co-workers, and other managers). It is in this process that the manager finds what Archer referred to as his utility or satisfaction in attaining his goals.

In determining the payoff, Archer (1964) was initially concerned with the amount of time that passed after choosing an alternative and before an outcome could be accurately determined. It was believed that this payoff was a function of the time period used in measuring it. ­­­­With that view, Archer also believed that the time between the decision and the outcome was dependent on two issues - the type of decision made and the accuracy in the measurement of the outcome. Archer concluded that “some amount of time must pass before an outcome is determined, and the payoff or measured outcome is a function of the length of the measurement period (p. 270).” On the topic of how postponing a decision could affect the payoff, Simon (1997) added that problems arise when all of the alternatives have undesired consequences, and postponing the decision is a needed response to search for a better alternative.

While noting that maximum satisfaction is the real goal of the manager, Archer (1964) stated that if “one is seeking to maximize utility (via some mix of goals), profit may, in many situations, be an inadequate measurement of utility (p. 277).” Accordingly, Archer added that the best strategy to follow is the one that maximizes utility, or rather minimums disutility. In this context, Huber (1980) added this idea to a decision rule referred to as the “Maximize Expected Utility (MEU)” decision rule. This rule stated that when decisions are made, the maximizing of the overall utility should be of primary importance. In determining the utility of the alternatives, the context of the alternatives should be considered. Huber (1980) identified three “category types of information” including identifying alternatives, identifying future conditions or consequences that result from the decision, and identifying or determining the criteria that was used in the evaluation process. These three categories of basic information set the foundation for systematically analyzing the relative information. Huber recommended that the information identified in the process be organized in tabular form where the alternatives, results, and criteria used in the process could be compared and evaluated. When the basic information is then combined with the “probability” of an outcome occurring, some form of “weighted importance” for each of the criteria chosen and the measurable outcomes or what Huber (1980) referred to as the “payoffs” can be considered with a simple systematic decision making model. The concept of payoff is the fourth and final key concept in

When Archer (1964) concluded that “the outcome or payoff is predicted with less than complete certainty (p. 272),” there was a realization that, with limited information relating to assumptions made, a lack of understanding of the entire system, the vast numbers of variables, both known and unknown, and the challenge of making predictions one could not predict with certainty all of the outcomes of a decision. Archer (1964) introduced an important concept in the decision making process – the topic of certainty. By stating that “among other conditions, decisions must be made under varying degrees of information – customarily classified as conditions of certainty, risk, and uncertainty (p. 269),” Archer acknowledged that to account for the number of variables in the decision making process, certain states of nature should be considered and measured with some level of relative frequency. He recognized three models for decisions. The first was referred to as decisions under conditions of certainty. In these cases, the payoff from the strategy (or alternative) is known or predicted perfectly. Archer (1964) illustrated this model by providing a two column table where the strategies were listed in one column, and their relative states of nature were provided in the other. This assumed that with each strategy chosen, a resulting state of nature (i.e., payoff) would be known. The strategies could then be compared to each other. In essence, by

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determining those states of nature for each strategy and knowing the related payoff, one could compare the different strategies on a relative basis.

reliable assumptions to completely unknowns, they go from accurate reflections, to estimates based on experience, and to complete disregard for all probabilities.

While Archer recognized that determining the exact payoff from a specific strategy was not always possible in most business cases, models and predictions would need to be made allowing for “expectations as to their relative occurrence (p. 275).” This model classification was referred to as conditions of risk. The assumption here is that probability distributions are known or can be determined, and probabilities relate directly to the payoff consideration.

As an added discussion, the topic of risk warrants consideration. Archer (1964) stated that “in any decision, we do not know which of the states of nature will occur but only have expectations as to their relative occurrence (p. 275).” This was an important point to recognize. In decisions, assumptions are made regarding risk - when in reality, decision makers accept this risk in the decision process even when it may not be accurate. As the level of risk increases with a decision, and the complexity of the situation increases, the level of risk, control, and understanding of the alternatives and relative outcomes take on additional challenges. The decision maker is therefore in need of decision making aids.

In the third classification, the payoff from a decision made under uncertainty is attained according to the maximum utility discussion previously discussed. In cases where the payoff alternatives are not certain, the decision-maker must determine the various payoffs, represented by combinations of states of nature and estimated probabilities, and make the final decision. In this case, Archer (1964) stated that “the payoff should be weighed by the probabilities involved” and the “appropriate decision is to select the strategy with optimizing expected value (largest, for maximization of the payoff unit) (p. 276).” With most organizational decisions made under some level of uncertainty, the payoff must be obtained through some objective experience. Decisions under these conditions are made along a spectrum of certainty. At one end, the decision-maker has an objective perspective. This is based on their level of confidence in the payoff or utility developed as a result of accumulated demonstrated experience, and with the expectation that conditions will remain consistent over time. On the other end of this spectrum is the subjective perspective. In these decisions, the decision-maker is determining the expected payoff from judgements made from past experience alone. In summary, decisions made under uncertainty will vary in the level of their objectiveness. When a decision-maker is basing the payoff firmly on subjective judgements, the level of confidence decreases significantly. Archer (1964) stated that in some specific cases, the decisionmaker “must turn to models of decision-making under extreme uncertainty (p. 285)” whereby no assumptions or relative probabilities are assigned to the states of nature. Under these conditions, Archer recognized that the decisions encounter the influences of rationality, pessimism, optimism, regret, and surprise and must base the decision strictly on “simple expected value (equivalent to an unweighted average of payoff)” and resulting “highest expected payoff (p. 285).” When Archer (1964) related the different strategies to the estimated probability of these certain states of nature, more accurate payoffs were determined. With one important caution noted, Archer stated that since the process involves probabilities and not conditions of certainty, assumptions may over-simplify the process of the real world and may lead to incorrect decision making solutions. As the probabilities of the states of nature move from

In regard to the tools available to managers in making complex decisions, Drucker (as cited in Anthony, 1965, p. 128) stated that the manager should “realize that his job is not to make the universe rational – but to make the decisions of limited, fallible human beings a little more intelligent than they otherwise would be”. With shifts in the decision processes, Anthony (1965) stated that “as new techniques are developed, there is a tendency for more and more activities to become susceptible to programmed control (p. 75).” In building devices to transmit, store, and process symbols, Simon (1997) stated that “the most important change is not the growth of these devices but the growth of a science that helps us understand how information can be transmitted, how it can be organized for storage and retrieval, how it can be used (and how it is used) in thinking, in problem-solving, in decisionmaking (p. 227).” Simon (1997) added that “we must understand not only the structure of the decision to be made, but also the decision-making tools at our disposal, both human and mechanical – men and computers (p. 243).” With the hierarchic-structure of organizations, Simon’s three levels of decision making characteristics include a bottom, middle, and top level. At the bottom level are those in production or on the factory floor involved in the most basic decision-making processes. For those in the middle level, represented by those that manage day-to-day activities, they are involved in the programmed decision-making processes. At the top level, those held by senior leadership and those responsible for major corporate initiatives and implementations, they are involved in the non-programed decision-making process. To account for this, Simon proposed that the use of mathematical techniques and tools would advance decision making for evaluating operational, strategic, economic, and industry related scenarios in all levels. Gorry and Morton (1971) stated that with the introduction of Management Information Systems (MIS), a framework was designed “to be useful in planning for information system activities within an organization and for distinguishing between the various model building activities, models, computer systems, and so forth which are used for supporting different kinds of

68 decisions (p. 56).” The early systems were being applied to large storage and retrieval systems and provided only limited processing capabilities to those with access to the information. With the increased need at all levels of the organization, Simon (1997) stated that with “our scientific and technological knowledge, our decision-making and information-processing systems should permit us to absorb information very selectively, extracting from it just the parts that we want (p. 226).” Gorry and Morton (1971) realized early on that a framework was needed to assist managers and systems planners with new systems that avoid managing from “crisis to crisis.” With the increased focus and recognition that organizational decision making aids were needed at all levels within a firm, Simon (1997) stated that with the structuring of decisions based on level or operational, supervisory, or executive responsibilities, “vertical specialization” required increased attention on decision specialization and accountability. In regard to decision-aided tools and techniques, ­­­­­­­­­­­­­­­­­­­­­­Gorry and Morton (1971) acknowledges that an appropriate framework was first needed. They concluded that “information systems should exist only to support decisions, and hence we are looking for a characterization of organizational activity in terms of the type of decisions involved (p. 56).” Simon (1997) took the position that the most important use for tools is in the modeling of complex situations and in determining the consequences of alternative decisions. Following Gorry and Morton’s (1971) approach based on Simon’s (1960) programed and unprogramed decisions, structured decision systems (SDS) and decision support systems (DSS) were developed. While the SDSs led to the development of management information systems, the more complex or non-programed decision processes required an advanced DSS. With the range of decisions requiring different systems, Gorry and Morton presented the idea that for upper level decision makers, “attention should be on the critical decisions in an organization and on explicit modeling of these decisions prior to the design of information systems support (p. 66).” This was in line with previous perspectives that decision making processes varied with the level of complexity and the amount of judgement required for each. At one extreme, daily decisions are made with a habitual decision-making processes that simply involves taking previous judgements from decisions made in similar situations, storing them to memory, and then recalling their use for another similar situation. Simon (1997) stated that “habit is the most general, the most persuasive, of all the techniques for making programed decisions (p. 50).” This form of recalling previous outcomes, while effective for most decisions, gives way to a more complex decision that requires a heuristic approach: one already discussed and commonly known as an educated guess or one that follows a rules of thumb. For many organizational decisions, Simon (1997) stated that these types of decisions “may not only serve their purposes effectively, but also conserve scarce and costly decision-making time and attention (p. 89).” This does have to be considered in

Transformers Vol. 1 light of the potential risk. Simon noted that a habit, or a response based on an unconscious process, may result in an inappropriate response if it is misapplied to a situation where more a conscious effort was required.­­ While heuristics are the most easily understood of the decision methods, Archer (1964) stated that in many cases the number of alternatives needs to be reduced through a procedure referred to as heuristic programming. Archer stated that this programming “consists of successive applications of rules (usually with the aid of a computer) deemed to be appropriate, so the number of alternatives is reduced to sufficiently few as to be manageable by the decision-maker (p. 272).” Archer referred to decision theory as essentially being heuristic programming. When the complexity of the decision increases or is significantly different than previous experiences, the value of using decision models increase. Simon (1960) provided the early framework for utilizing mathematics as tools in the decision making process. An assumption in its use was that this approach works best when the results generated by using the mathematical models were better than those that would have resulted from using “common sense without mathematics.” According to Simon (1997), the four-step process evolved and involved: (1) constructing a mathematical model that best represented the components and conditions of the situation, (2) defining the criterion function (determines the possible outcomes), (3) obtaining empirical estimates of the variables under consideration, and (4) running the mathematical model to determine the best outcome that allowed for a better decision to be made. Anthony (1965) defined a mathematical model as “a device that attempts to express in symbols and numbers the behavior of the important parameters in a given situation (p. 58).” There was noted criticism of Simon (1997) and his view that decision-making was defined as a rigid linear process. Simon responded that while the decision process could be divided into a four step process that included setting the agenda, representing the problem, finding alternatives, and selecting alternatives, the process was not limited to occurring in that order. Simon added that the process often overlapped with other decisions and that the final decision could result from merging multiple processes in their various stages. Simon stated that the most important use in the modeling of complex situations was the ability to “infer the consequences” of alternative decisions, thus making models “direct decision-making tools.” At other times, Simon considered a model a “simulator” capable of calculating the outcomes of different decision strategies. Mathematical modeling is a tool that can turn non-programmed decisions into programmed decisions by defining variables, creating alternatives, estimating them in a model, and then calculating them using the best suited mathematical calculation. A consideration of this model, however, is the actual number of alternatives created and reducing them with formalized procedures. Views on the use of modeling have varied with early researchers. For

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Transformers Vol. 1 example, Archer’s (1964) idea of heuristic programming and the need to reduce the number of alternatives to a manageable number through the “successive application of rules” supports this idea of systematically reducing the choices of alternative strategies, ideally down to one. In 1980, Huber provided five benefits of utilizing decisionmaking models including: (1) the ability to systematically identify the limitations of our limits of rationality; (2) the importance of considering all alternatives in the process; (3) the criteria, data, and information considered in the process could be collected, stored, and used in future decision models; (4) the vast amount of information could be organized in ways the human mind is not capable of; and (5) the model provides a visual representation that could be shared with others involved in the outcomes of the decision. According to Huber, “the development of a model representing the decision situation and the use of a step-by-step procedure for using the information captured in the model are, together, the application of a decision-aiding ‘technique’ (p. 87).” In cases where multiple variables and multiple payoffs are involved, the need for mathematical modeling takes on additional importance. Huber (1980) referred to these situations as multicriterian decisions. The need for decision making processes for these multicriterion decisions resulted in the development of graphical and mathematical models where the payoffs of the various alternative solutions could be determined and compared. Huber stated that the use of these models “should be used as aids to judgement and not as a substitute for judgement (p. 47).” They could be aids to provide managers with a more systematic tool for making their judgements. As an example, a generally recognized model used as a decision making technique is the decision tree. For many situations that involve successive decisions, the amount of information at hand and the amount of additional information needed to choose the best of the alternatives will determine the length of the process. Similar to the use of a basic decision matrix, a decision tree is a sequential model that can be graphically represented. By starting with a “choice fork,” “branches” from the fork represent alternate paths of action. These paths can then lead to additional “outcome forks” for the next sequential path. At the end of the last path, the alternative that maximizes the payoff is chosen as the best alternative. Huber (1980) stated that “a principal payoff we receive from drawing a decision tree is an increase in our understanding of the decision situation (p. 120).” By identifying the relevant information, and then aggregating it, one has a visual representation. According to Huber, “Experience have shown that the use of these techniques, or even of scaled down versions of the techniques, can increase decision quality (1980, p. 214).” The use of decision trees warrants further consideration discussed later in this paper. Simon’s (1997) basic decision making hypothesis was based on the concept that decisions could be broken into subparts, or into what he referred to as “orderly, complex sequences” and could

therefore be simulated by the use of computers. Of importance was the idea that human thinking could be mimicked with the use of computers in managerial decision making generation. Simon recognized the field of research that focused on building systems called artificial intelligence but acknowledged that this field was limited to simulation and not full reproducibility. Simon supported the idea of developing “expert systems” (i.e., capable of developing expert solutions) and believed that through cognitive sciences and artificial intelligence, problem-solving techniques focused at a professional level could ultimately assist those at lower levels to become experts as well. Simon stated that as expert systems exhibit reasoning and are combined with processes for accessing knowledge banks, expert systems could have the capability of “automating the expertise”, or creating an “expert computerized consultant”. With automation, especially that automation addressing the “minute-by-minute” and “day-by-day” operations of the factory, systems were increasingly being focused on issues of preventive maintenance, system breakdowns and malfunctions (Simon, 1997): a continued area of interest to today’s organizations.

SECTION 2: Current Research Relating to DSS With an understanding of the theoretical foundation of decision support systems (DSS), much of the more recent research has been focused on the methods and analyses based on Simon’s (1960) non-programed situations. Understood to be a process, Asemi, Afari, and Zavareh (2011) stated that higher level systems including MIS, DSS, and Expert Systems apply “the expertise of decision makers to solve specific, unstructured problems (p. 164).” When considering Simon’s programmed decisions, Asemi et al. recognized that standard decisions are generally based on management guidelines. For non-programmed decisions, where the process involves determining the problem, developing alternative solutions, and then selecting the best alternative required additional advanced support tools. Liu, Duffy, Whitfield, and Boyle (2010) stated that the more recently accepted three-phase decision making process, known as “intelligence-design-choice” had been based on the work of Simon (1960) and was still considered in current system designs. With multiple perspectives and models for the decision making process developed in the 1960s, Gorry and Morton’s (1971) structured, unstructured, and semi-structured decision model provided additional support to the idea that decision support systems needed to consider the type of decision. In expanding upon Simon’s work, Asemi et al. (2011) stated that Huber (1980) had expanded the original model and added the step of “implementation of the solution” and the “monitoring and changing of the solution if needed”. From the earlier work on management support systems, Waston (as cited in Asemi, Afari, & Zavareh, 2011, p. 165) defined MIS as “an organizational method of providing past,

70 present, and projected information related to internal operations and external intelligence.” It was stated that the goal of the system was to provide uniform information and assistance to the decision maker: specifically that data and information collected of value in solving the firm’s problems. Asemi et al. (2011) stated that there were five key characteristics of an MIS including: (a) standardized reporting formats, (b) dedicated systems analysts or programmers involved in writing the programs, (c) report requests are made by the users, (d) the delivery of scheduled demand reports, and (e) external data is included. While somewhat limited in scope, the main initial focus of MIS was as an organizational aid to a manager’s decision making process. While MIS could help extract information from databases, provide information needed for decision making, and improve operations and organizational success, the scope and application of the system was limited to operational concerns. In considering the tools that assist with semi-structured decisions, Asemi et al. (2011) defined a DSS as a computer based system used by management in solving semi-structured problems and identified that the primary benefits of a DSS are producing periodic reports and conducting mathematical simulations. Liu et al. (2010) defined it as “an interactive computer-based information system designed to support solutions to decision problems (p. 261),” Asemi et al. noted that DSS has advanced to include group decision support systems known as Groupware - a system designed to allow multiple individuals or groups to work and communicate together. In distinguishing DSS from MIS, Liu et al. stated, “A DSS is decision focused, user initiated and controlled, and combines the use of models and analytical techniques with traditional data access and retrieval functions p. 280)”- a much more robust system than MIS as defined by Asemi et al. Asemi et al. (2011, p. 166) provided nine characteristics of DSS including: ●● DSS provide support for a decision maker mainly in semi structured and unstructured decisions. ●● DSS attempts to improve the effectiveness of decision making. ●● DSS provides support to individuals as well as groups. ●● Advanced DSS are equipped by a knowledge component. ●● A DSS can handle large amount of data. ●● A DSS can be developed using a modular approach. ●● A DSS has a graphical orientation. ●● A DSS support optimization and heuristic approach. ●● A DSS can perform “what – if” and goal – seeking analysis. Within these nine characteristics are a few key attributes for semi-structured problems. Specifically, DSS can be used to cover a wide range of type and size problems, it can provide graphical presentations for its output, it can be used to determine a satificing solution. Additionally, it can provide guidance with hypothetical

Transformers Vol. 1 situations. In noting that MIS was limited to providing routine information for operations, Asemi et al. (2011) added that its main weakness was that it did not provide the right information or meet the exact needs of upper management in dealing with unstructured or semi-structured decisions. There was a need for precise and suitable data at all levels of the organization. Understanding this, Asemi et al. (2011) was aware that not only were different kinds of data required for different levels of the hierarchy, they were aware that the clarity, precision, and source of the data and information were important considerations. “At lower level, supervisors need defined, clear, precise, quantifiable and internal organizational information but at the top level a manager needs undefined, future oriented, infrequent, summarized, relatively, non quantifiable and mostly external information (Asemi et al., 2011, p. 167).” In regard to the levels of needs, they added that MIS could furnish most daily data and information needs of middle managers and DSS could provide more directed information to those middle and higher levels of the organization. With the increasing use of stand-alone DSS at the group and executive levels, the scope of the tools were extended from the individual, to the group, and up through the corporate level. Systems such as integrated decision support systems (IDSS) are gaining use. Technology has shifted from databases to online analysis processing (OLAP) and mainframes to the World Wide Web. The emergence of other systems including enterprise resource planning (ERP), supply chain management (SCM), customer relationship management (CRM) the continued expanding availability of information could overload decision makers. Liu et al. (2010) saw these challenges as an opportunity to focus on expanding and integrating these systems to make better decisions - to provide advanced support in making rational decisions. According to Liu et al. (2010), a major strength of utilizing DSS and IDSS is the related integration that results. As a resulting benefit, the “prominence effects, overconfidence and other biases are reduced for managers who use model-based IDSS compared with managers that do not (p. 266).” Liu et al. indicated that the focus has remained on those modes of integration in DSS including data and information, model, process, service, and presentation: components that are still addressed today. Designing a DSS involves ensuring that decisions are made from consistent information, modern models are properly developed from the combining of sub-models, the processes are properly defined, components are served by the other components in the system, and include the ease of use and consistency of language. According to Liu et al. (2010), the strengths of this technology are measureable and “the benefits of IDSS have been clearly manifested through tangible returns on investment and savings in organizations over many years… (p. 270).” Their research had covered a wide range of technologies, including knowledgebased system, data-mining, intelligent agents, and web-enhanced IDSS. Knowledge-based enhanced IDSS are support systems that

Transformers Vol. 1 are combined with domain knowledge. With the added benefit of improving consistency, Liu et al. stated that when combined with rule-based reasoning (RBR), case-based reasoning (CBR), and hybrid reasoning (HR), or other recognized approaches the knowledge based enhanced IDSS improves decision making performance. Data-mining refers to the process of extracting from data any valuable corporate knowledge and intelligence, and according to Liu et al., the addition of data-mining to DSS could result in a knowledge creation phase: one where the decision making process is not based solely on data but is based on cleaned data, identified patterns, applied algorithms, decision tree induction, and association rules. They referred to this process as providing “requirements-oriented support rather than unfocused informational support (Liu et al., 2010, p. 275).” Seen as a response to the weaknesses inherent in the idleness and passiveness of existing DSS interactions with users, Liu et al. (2010) provided a robust review of successful applications of intelligent interfaces developed to provide users with more active communication options with DSS. Noting that decision support performance has improved, the use of intelligent agents has continued and is creating enhanced group support as well (Liu et al, 2010). With DSS lacking in its ability to move beyond its database and knowledge orientation, the weaknesses were addressed with web-based IDSS. Moving from a closed system to an open system equipped with extensible mark-up-language (XML), research has demonstrated that adding web technology to IDSS increased successful communications, improved sharing of information, and promoted “more consistent decision making on repetitive tasks (Liu et al., 2010, p. 278).” In addition, process integration is resulting in a common platform that supports decision making processes across all levels of management and technical departments while also providing aid in structured, semi-structured, and non-structured decisions. Inherent in DSS design is the attention required to recognize the strengths and weaknesses in maximizing decision utility. In advanced neural network analysis, for example, a topic to be discussed in more detail later in this paper, Davenport and Harris (2009) stated that as a prediction technique that models the human brain, large amounts of data are first analyzed and then the neural networks are “trained” to be predictors of the variables. The strengths of this technique include being a good predictor of potential outcomes as well as in determining other unexpected outcomes. The weaknesses of the technique include a thorough understanding by the user on how or why the specific outcome was determined, the extensive amount of data required, and the input of experts are needed to develop it. Since the early work of Simon (1960), there has been changing perspectives presented that relate the nature of decision theory to multidisciplinary problems and complex situations. Kovacic

71 and Sousa-Poza (2010), for example, stated that while decisions are often approached from one discipline, and are made to fit for a satisficing solution, approaching these complex problems does not typically follow Simon’s quantitative decision process of intelligence, design, and choice, but rather follow a parallel and circular process described as identification, development, and selection. Kovacic and Sousa-Poza extended this circular perspective with the idea that decision making in complex situations must consider more than just the knowns and unknowns at each stage: one “must account for known, known unknowns, and the unknown unknowns (p. 498).” This perspective was based on a concept of the wholeness or more comprehensive nature of the situation: a perspective referred to by Kovacic and Sousa-Poza as the gestalt imperative. This new holistic perspective had been approached by a proposed method called Reverse Decision Making. One observed strength in this method was that it sought to propose new methods for bringing a multidisciplinary perspective to complex situations. An example of groups utilizing this approach is the currently funded three year partnership between the Department of Homeland Security, Systems Engineering Solutions Inc (SESI), and Old Dominion University (ODU) presented by Kovacic and Sousa-Poza (2010). Additional advancements have been made on the topic of decision theoretic methods of consensus. On-line decision making and decisions under uncertainty continue to be widely studied. In regard to computational power and information, Roberts (2008) stated that there are limits to the quantity of information being made available for decision making. Noting that participants often have limited computational power, or have bounded rationality, Roberts recognized that challenges still existed in complex situations when partial and limited information must be relied upon. The increase in on-line applications and related techniques have advanced the use of algorithms, artificial intelligence, Boolean based decision functions, improved graphical presentations, and decision tree modeling. It should be noted that in regard to sequential decision making and decision making under uncertainty (where incomplete, noisy, or partial information is all that is available), Roberts (2008) acknowledged that with the increase of “on-line” decision making (for those decisions that need to be made with limited information), the methods to improve on-line decision making, and to make diagnoses and inferences are greatly needed. In considering game theory for example, decision making applications have been valuable tools. The challenge for its use relates to the ability of the aids to adapt as the complexity increases, the sheer scale grows, and the variables change mid-stream in the process. Of note is the ongoing sophistication needed to account for less than “fully rationale” participants. As these systems get larger and more complex, the algorithms need to be able to account for both “full rationality,” and “bounded rationality” (Roberts, 2008).

72 With a focus on algorithmic decision theory, Roberts (2008) stated that while technical fields have remarkable new technologies, the need for “algorithms for decision support, especially algorithms that can approximate good analytical solutions are needed (p. 228).” The challenges stated by Roberts are based on the volume of information, the increased speed of sharing information, and the increased speed to make decisions. With these issues, users are still daunted by information that is “often incomplete” or “unreliable” and the question of uncertainty must be adequately considered. Sequential decision problems exist in many technical industries, including in manufacturing and fault diagnostics, and was noted as an area where existing algorithms “do not scale” (Roberts, 2008). In considering risk models for sequential decision analyses, Roberts (2008) stated that “work is needed to understand the computational complexity of obtaining the optimal policies for risk-averse dynamic models and to design good algorithms for this purpose that incorporate the extra dimension of complexity brought in by risk considerations (p. 229).” The same complex considerations are applied to the field of artificial intelligence (AI). The classical approaches based on actions that were measurable and their utility determined quantitatively did not always apply in the field of AI. Uncertainty and utility needed to be accounted for on a qualitative basis. This observation has given rise to qualitative theories of sequential decision making that include logical languages for expressing preferences (Roberts, 2008). Roberts further stated that that the classical approach to sequential decision making with AI applications has given way to new automated Markov decision processes. Additionally, on the topic of Boolean decision functions and binary decision trees (BDT), Roberts (2008) indicated that the there is an increase in the literature on connecting BDT to given Boolean functions. On the topic of presentations, probabilistic graphical models are increasingly being used in computer-assisted diagnostics, multivariate statistical analysis, and in decision making. And, on the relevant topic of decision-theoretic artificial intelligence and computer-based reasoning systems, Roberts (2008) stated that mathematically grounded approaches are increasing in the decision sciences field. With advancements in both quantitative probability distributions and approaches incorporating “qualitative decision theory” capabilities, current applications are now taking into account more human preferences and mixing behavioral sciences into the framework. One specific application of interest in the field of preventive maintenance relates to efficient instance-based decision making. Roberts (2008) stated that incorporating instance-based decision making, also known as memory-based, case-based, or an episode based approach, involves breaking an experience down to smaller episodes; storing those individual episodes in a database; creating a model of the episodes; and then making the models available for determining potential future courses of action. With a new experience, the individual episodes are compared to the existing data-

Transformers Vol. 1 base, a search is conducted for “similar” episodes, and the most appropriate action could be chosen. While instance-based decision making has its strengths, including the creation of a knowledge and experience-based decision support system founded on qualitative comparisons of experiences, these systems were still weak in terms of comprehensiveness (i.e., in their ability to address episodes that are not quantifiable). Roberts presented several challenges in this field including the need for capturing episodes in sufficiently wide “broad strokes,” staying relevant to the episode at hand, and the development of algorithms that address the large number of needed episodes. As decision support in the real world moves from simple quantitative operational activities based on “IF-THEN” statements to being more qualitative in form and diversity, the complexity of the techniques need to improve. As information fuses from many sources, Roberts (2008) stated that what was needed were “ways of fusing uncertain information from subjective judgments of different sources and of combining these judgments with objective but disparate information from automatic devices such as sensors (p. 213)”. In addition, Roberts noted that the new models would need to account for both the increased complexity and uncertainty, and be capable of making diagnostics and inferences with “incomplete or noisy data.” In regard to the development of new technology-based advancements in complex systems, Baldwin, Allen, and Ridgway (2010) stated that newly introduced modeling and simulations are being more readily adopted and implemented. Noting the important role that organizational decision making has, Baldwin et al. considered Simon’s (1960) concept of bounded rationality and the role that incomplete knowledge plays in the decision making process in their research. They focused on the role that diversity played in evolutionary complex systems (ECS). This concept addressed the idea that diversity in the management decision making process could affect the future trajectory of the firm. Baldwin et al. also recognized that “perfect predictability” is not a certainty and should be replaced by accepting variation and uncertainty with better modeling. In their qualitative study of a manufacturing firm, they utilized an ECS model that considered the qualitative opinions and views of a diverse group of managers (functional diversity), instead of using aggregated IF-THEN rules, and concluded that their model generated more valuable information. As discussed earlier and worthy of further discussion is the use of decision trees in the decision making process. Kingsford and Salzberg (2008) stated that while a fairly simple type of classifier, which is one of their advantages, decision trees are tools that enable data to be classified by the asking of questions (referred to as ‘nodes’). In its simplest form, in a type of ancestry chart from, the data is addressed with a YES-or-NO question where the two possible answers follow the path of two children; a “YES” child or a “‘NO” child. Starting at the top node, referred to as the root node, the first YES-or-NO response moves the classification down one

Transformers Vol. 1 layer along either branch based on the appropriate response. The branching either ends at a leaf node (an end point of the tree), or continues to another node where the process repeats until the classification is complete. The YES-or-NO questions and nodes presented by Kingsford and Salzberg (2008) consisted of decision nodes, event nodes, or terminal nodes and the branches consisted of edges that represent decision alternatives and lead to the terminal nodes, which “represent the outcome of a sequence of decisions and events (p. 632)” and leads to an optimal solution. Marginean, Sirbu, and Racovitan (2010) added the definition that a decision tree is a visual tool, one that systematically does so by “computing expected values of all decision alternatives in order to identify the best solution (p. 631).” They recognized that decision trees were suitable for choosing an optimal solution when presented with a complex series of interdependent decisions with a degree of uncertainty. In developing the decision tree, Kingsford and Salzberg (2008) stated that the process involves adding question nodes incrementally and continues “recursively” into the layers forming the tree. It was noted that the tree could be overly developed and that diminishing returns need to be considered as the number of nodes increases. Two variants were introduced including the ideas of random forests and boosting strategies. The first referred to modifying the nodes or the subsets with random tree-building algorithms to obtain a group of decision trees for consideration and the second referred to the process of changing the weighting, the classifiers, or even using alternate decision trees that account for stronger or weaker classifiers. The goals of these two strategies were to improve the classification process by modifying and comparing trees, and to obtain more narrow or interpretable classifiers. As a general rule, each increase in the number of pre-specified leaves and nodes does not directly increase the value of the tool. Chang and Sheng (2008) stated that the trees could become overly complex and the resulting classification accuracy could drop. In addressing this, Chang and Sheng concluded that a multi-decision-tree induction (MDTI) approach encompassing an infusion of multiple different decision trees may increase the classification accuracy. Decision trees with different rules and classes could be constructed to provide alternative classifications, either supporting or negating the classification of another. On an additional note, the performance measurements for decision trees relate to classification accuracy and rule conciseness (Chang & Sheng, 2008). Classification accuracy refers to the relationship of accurate classifications in relation to the number of situations tested: reported as a percentage. Rule conciseness relates to the actual number of decision or event nodes in the decision tree. In general, lower complexity and therefore, a lower number of decision and event nodes, is preferable. In considering the advantages and measures of utilizing decision trees, Marginean et al. (2010) stated their simplicity makes

73 their usage to real world problems possible. In addition, with software packages, intuitive interfaces, and graphical outputs, they added that decision trees have the advantage of being combined with other techniques and DSS tools. With the increase in database and pattern recognition, Chang and Sheng (2008) stated that while neural networks (techniques used in predictive and classification scenarios) are routinely utilized, decision trees (rules-based techniques) continue to be well received in part, due to their ease of understanding and use. In terms of system reliability, the use of DSS tools like decision trees becomes dependent on the ability of the system to consistently provide optimum results. Concerning advanced techniques, Russell and Yoon (2010) stated that users are generally not concerned with how something was done, how it was managed, and what technology was utilized: they are concerned with whether the information was available, accessible, and reliable. DSS tools utilizing these approaches continue to be utilized in a wide array of industries, and specifically in cases involving higher levels of uncertainty. Jampani et al. (2011) recognized that the use of stochastic models and analytical techniques were becoming commonplace. Based on the theory of probability, uncertainty, and focused on probabilistic methods, stochastic methods applied to large databases are increasingly and routinely combined with Monte Carlo techniques for “analyzing the probability distribution of the result of an SQL query over random variables (Jampani et al., 2011, p. 181).” According to Jampani et al. (2011), probability distributions, such as in determining the expected load on an electrical system given a price level in the electrical utility industry, involve complexity and uncertainty, and the use of the Monte-Carlo method could be used to aid in making decisions. In the electrical industry example above, the Monte Carlo method would follow a multistep process. This could include (1) beginning with a statistical prediction based on the data stored within a database (e.g., What would have been the load had retail pricing been raised one cent/KW last year?), (2) the development of a model to represent the probability distribution, (3) the processing of existing data with the new “IF” statements to capture what “would” have occurred had the price changed, (4) processing of all of the new probability distributions to train the model to match the data thus creating a “learning” system, and (5) using the new model to address the original question asked. The learning stage could be performed by an external application or integrated into the database directly through Monte Carlo database software. In industries where large investments in equipment are required, the financial risks are significant, limited options exist for replacing equipment, and the unexpected risk of failures is real, significant resources are consumed to minimize the total risk: especially those resources that are focused on minimizing catastrophic losses. For example, it was a conclusion of the study by the Conference of Insurance Supervisory services of the Member States of the European Union, known as the Sharma Report, that insolvency issues were related to inadequate internal controls and

74 problems with the insurer’s decision-making processes (Cummins & Phillips, 2009). It was determined that quantitative modeling of insurer risk was required for evaluating the firm’s management, internal operations, and decision-making process. According to Cummins and Phillip (2009), a more dynamic risk-based model that focused on the assets and liabilities was needed. In this case, the insurance industry which had historically used static factor-based approaches created and utilized a new Swiss Solvency Test (SST) - a stochastic risk-based analysis that provided a model-based approach to regulating the issue of insolvency (Cummins & Phillips, 2009). While ratios, static guidelines, and rules-based systems had been used successfully in countries like the United States and Canada, this new system provided a much needed risk-based solution for other countries including Japan, Australia, the United Kingdom, the Netherlands, Switzerland, and the European Union. In another industry benefitting from stochastic behavior, Sharma, Kumar, and Komal (2010) stated that a hybridized technique could be developed using fuzzy analysis, neural networks and genetic algorithms (GAs) for analyzing stochastic behavior at a paper mill. Sharma et al. cited the use of fuzzy methodology in the studies of reliability, fault analysis, and risk engineering. The use of fuzzy numbers provided a means to represent variables such as failure rates, repair times, and other uncertainties to “make the decisions more realistic, generic, and extendable in future… (Sharma, Kumar, & Komal, 2010, p. 954).” The goal of using fuzzy numbers was to better represent each of the reliability indices to improve the operational and maintenance strategies while allowing for improved future decision making. In that study, Sharma et al. (2010) analyzed the behavior of equipment reliability and the effect of each subsystem on the entire system. With the focus on key equipment maintenance where failures were most likely, the research established fuzzy (triangular) values developed by collecting historical records and adding the input of industry experts. The data was analyzed utilizing mathematical computations, and then after “defuzzifying” the values, the experts obtained better results than when only original values were utilized. The addition of fuzzy numbers in the process improved the information used for decision making in a real life situation. In a completely different application, Tsagalidis and Georgiou (2009) used stochastic modeling in a “WHAT-IF” analysis to improve a hail suppression program conducted by airborne means. In this example, a model was developed that considered storms (a priority attribute), the availability of planes, airport wait times, plane interception parameters, costs, and other effectiveness variables for seeding storms with silver iodide nuclei (AgI). The purpose of the simulation model was to minimize crop damages caused by pending hailstorms. The stochastic nature of this model related to the number and duration of the primary attributes. The problem to solve related to whether the storms present were in

Transformers Vol. 1 form and timing such that seeding would be effective, efficient, and financially prudent. In this instance, binominal distributions represented concurrent storms, a Weibull distribution represented inter-arrival times between storms, Kruskal-Wallis homogeneity tests were used for inter-arrival and service times, and lognormal and triangular distributions were utilized to improve the “go-no go” decision making process. In the maintenance of power equipment, Wang and Hussin (2009) utilized stochastic filtering in the study of estimating residual life of marine diesel engines through an oil analysis program. Understanding that lubricating oils begin to degrade the moment placed inside an engine, condition-monitoring analyses could provide insight into the expected residual life of the equipment. Wang and Hussin noted that by detecting degradation or wear items over time, the data collected could be used to determine “if the lubricant itself is a fit for continued use, based on certain performance measures (p. 789).” While the analysis was not a measure of residual life directly, it measured observed characteristics that were a function of the wear, which in turn was a function of residual life. By incorporating a new setup that considered constant variance properties and independent component analysis (ICA), which was defined by Wang and Hussin as a method of calculating “the contribution of each item to the external data”, the researchers generated a new and improved model for determining residual time distribution. After significant mathematical modeling, equation filtering, and recursive manipulation, a predictive model of residual life was fit to the data. In this study, the kinematic viscosity (an important property for reducing wear), water contamination (which increases corrosion and oxidation), total base number (a measurement of the oils ability to neutralize acid contamination), and insoluble combustion-related debris and oxidation products were measured as the test parameters. While Wang and Hussin (2009) stated that residual life was a function of accumulated wear, and that wear metals were also a function of wear, the study focused on four external parameters that could increase or decrease wear, and thus, the residual life of the equipment. With most of the examples given in various industries, the use of mathematical models required the assistance of computer programmers and subject matter experts. Rosalia and Valentin (2008) stated that spreadsheet-based decision support systems (DSS) have been used for hundreds of years and provide a viable option for many applications. Originating on paper and then transitioning to computer-based applications in the 1980s, spreadsheetbased DSS have evolved into more modern versions consisting of three components including model management, data management, and a user interface. Rosalia and Valentin (2008) noted that additional knowledge management components for complex problem solving are increasingly being used by organizations. With the availability of statistical, optimization, and simulation modeling, new spread-

Transformers Vol. 1 sheet based DSS are gaining acceptance. With user friendly interfaces, data importing and query components, the addition of Visual Basic for Applications, advanced modeling functions, WHAT-IF analyses, and many Add-In applications, software like Microsoft Excel provides a tool for complex decision making processes. With the advantages of Excel previously described, its use as a DSS can improve all phases of the decision making process – from improving the manager’s activities to improving their decisions (Rosalia & Valentin, 2008).

SECTION 3: DSS Applications and Advancements in Electrical Insulation Fluid Diagnostic Decision Tools. In regard to model-driven decision support systems, Savic, Bicik, and Morley (2011) stated that the current limitations in their use stems from developers and users. In their study, these researchers discussed the need for developers to consider the social and economic characteristics of the users. The use of Microsoft Excel, a familiar tool for generating model-driven DSS combined with Add-In applications, is bridging the gap between programmers and end users. Studies involving the use of genetic algorithms (GA) are also increasing spreadsheet applications as optimization problems are integrating a biological-based perspective. Considering the evolution of a population, mutations, and random processes of selection and recombination in the technique, Savik et al. presented the idea of utilizing evolutionary algorithms for highly complex problems in the water resource management field. The use of modeling has the potential to solve problems where multiple objectives may be required. This may involve maximizing and minimizing different objectives (e.g., maximizing inflow into a reservoir while also maximizing outflow to meet needs). The concept of multi-objective optimization involves balancing conflicting objectives and seeking a best compromise through the use of advanced DSS generator tools. While Savik et al. (2011) referenced the ideas of a “Pareto-optimal solution” and a “Pareto-optimal set,” where objectives are valued and optimization of multiple objectives are determined, they noted through the example of the operation of a water distribution system that the optimizing of water inflow and outflow, water storage requirements, pump switch operations, and related operating costs were beyond the basic programming skills of most users. This multi-objective analysis utilized Microsoft Excel and integrated GANetXL, an Excel Add-In application that provides for evolutionary multi-objective optimization (EMO), to produce a model application that had a relatively comfortable appearance to the user, was easy to use, and bridged the gap between developers and the end user: which was a significant advantage for small to medium sized applications (Savic et al., 2011). In the electrical maintenance of electrical transformers, circuit breakers, and large oil-filled high voltage equipment, similar multi-objective problems and applications are being investigat-

75 ed. The Institute of Electrical and Electronics Engineers’ (IEEE) Transformers Committee of the IEEE Power & Energy Society generates standards and guides through an industry consensus development process with the goals of improving industry acceptance and maintenance practices. The IEEE Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers, revised as IEEE Std C57.104-2008, is the predominant industry guide utilized in North America. While considered a science, the detection of certain gases generated within the transformer insulation fluid from arcing, partial discharge, low temperature overheating, hot spots, or mechanical failures is considered by many as more of an art. In the IEEE Guide (Perry, 2009), it is stated that the interpretation of these gases is “not a science but an art subject to variability (p. 2).” While transformers may generate gases that are dissolved in the oil under normal operating conditions, and at varying concentrations and different ratios, it has been accepted that the gases dissolved in the oil can be of diagnostic value in determining the type of fault present, the severity of the fault, and the appropriate actions to take. As noted in the standard, the challenge in the interpretation is the consideration of the variability and complexity of the equipment, fluid types, sampling procedures, and the analysis itself. As a general overview, the gases generated during electrical equipment faults have been grouped as either being formed from thermal processes (i.e., pyrolsis), from partial discharge or lowintensity discharges, or from high intensity arcing in the 700C to 1800C range. While each of these three fault types generate specific gases, and at expected ratios, the occurrence of multiple faults or combinations of faults may result in classifications that do not easily fit the characteristics of the simple fault type identification. The IEEE Guide is based on the premise that multiple faults may be present and the complexity of the problem may not be completely addressed in the interpretive guide. As an interpretive guide, IEEE Guide C57.104-2008 provides a six-step operating procedure flow chart for determining the condition of the equipment and the fault types based on the total combustible gases and by the key gases generated by fault type. This flow chart covers the assessment of the transformer following the detection of combustible fault gases. The second part of the assessment involves utilizing established gas ratio values and following a ratio analysis flow chart for fault classification. A topic recently discussed at IEEE meetings is that of determining gas diagnostics based on the statistical analysis of an industry generated database considering manufacturer, design type, voltage class, breathing configuration, and other variables. An additional approach not currently under consideration, but having great potential in this field is the use of a case based analytical approach to improve the value of the analytical process. On the idea of improving the value or maximizing utility of decisions, a topic previously discussed, Hullermeier (2005) referenced the

76 process of satisficing within the context of a case based reasoning approach. Noting that Gilboa and Schmeidler’s (as cited in Hullermeier, 2005) case-based reasoning theory (CBRT) comes from the idea that new problems can be solved by “recalling experience from previously solved problems which are stored as cases (p. 641),” Hullermeier extended CBRT to the concept of experiencebased decision making (EBDM). In EBDM, the goal is not to maximize utility, in as much as it is to find a solution that most closely relates to a past solution, and then to accept it as the solution. The idea of satisficing, while common in instance-based approaches (one that simply compares one new case to past cases), should be a consideration in model-based approaches such as in decision-tree inductive processes where the opportunity for learning occurs. The improvement of the analytical reasoning comes from recognizing the limitations of the satisficing process, combining the learning and predictive benefits of developing models that capture the new decision outcomes, and them using that captured “case” to improve future case considerations. For clarification, an instance-based approach is predominantly a memory exercise which results from the new case becoming an additional case in the database of cases. In model-based case approaches, the results of the current case are determined by evaluating a functional relationship with model-based algorithms. As such, the new case becomes part of the model and the results are incorporated into future algorithms: hence a learning opportunity is offered. With decision tree models, it is possible to maintain the serial decision making process and update the current tree with each new case. With EBDM consideration, the static tree becomes a dynamic decision tree. According to Hullermeier (2005), the use of case based reasoning combined with experience based decision making approaches has the advantage of “learning and improving performance over time (p. 646).” An alternative to improving these decisions was presented by Duan and Zhou (2012) and was based on a modified decision tree approach. Presented as a “fault tree analysis,” Bayesian networks (BN) were used for diagnosing faults and improving maintenance. Their research considered the use of a fault tree model, new diagnostic decision algorithms, and a newly termed diagnostic decision tree (DTT) to provide end-users and maintenance personnel access to an improved decision making tool. This specific and novel fault diagnostic model paired standard decision tree event ordering of respective probabilities of the parent nodes with Bayesian networks to improve the diagnostic process (i.e., having evidence of a fault and then inferring the most likely cause). Directly applicable to the testing of insulation fluids, Duan and Zhou (2012) took the qualitative decision tree model and added a quantitative component. Utilizing the idea of a diagnostic importance factor (DIF), which is an indication of the probability that an event has occurred when a top event has occurred, and considering the costs of conducting the diagnostic tests, the measurement of a “cost based DIF” was utilized. With this approach, Duan and Zhou converted a basic fault tree with “OR” and “AND” gates

Transformers Vol. 1 into a Bayesian network, and then used a clustering algorithm to calculate DIFs for the components. The end result was a combined model utilizing a decision fault tree for modeling and a Baynesian network for inference consideration. For transformer fault analysis, there are several major approaches followed around the world. While the IEEE guidelines and related International Electrotechnical Commission (IEC) and International Council on Large Electric Systems (CIGRE) provide the industry with explicit consensus knowledge tools, another general approach utilizes the use of Artificial Intelligence (AI) and alternatively proposed decision making frameworks. Radzian (2010) stated that due to the complexity of Dissolved Gas Analysis (DGA), and the need to approach the diagnostics from more than one perspective, “an information infusion methodology” was needed. In Radzian’s (2010) research, a decision making framework was proposed that considered the separate Dempster-Shafer (DS) combination theory based on the combining of imperfect information provided by independent evidences, and Yager’s ignorance based combination rule. Radzian developed a new rule termed the threshold belief mass (THB) interpretation rule. Where Weibull functions have been utilized in determining the quantity or degree of belief in transformer fault analysis, this new THB rule was developed to assist in differentiating between major faults (MF) and incipient faults (IF); a complex determination. With incipient faults considered as an accelerated degradation process, and MF represented by an “end of life” condition, Radzian (2010) utilized a basic ground probability assignment (GPA) function with five pieces of evidence, and one resulting single GPA. Radzian’s five belief structures included; (1) the individual concentration of each combustible gas, (2) the rate of total combustible gas increase per week (RGI), (3) the three ratios utilizing five combustible gases (BGR), (4) the key ratio of acetylene (C2H2) to hydrogen (H2), and (5) the key ratio of ethane (C2H6) to ethylene (C2H4). As an outcome of three theoretical approaches presented, Radzian (2010) stated that Demster-Shafer’s combination rule provided the “most probable hypothesis” to determining an incipient fault in a power transformer, and that the THB interpretation rule provided the most probable hypothesis for determining a major fault condition in a power transformer. The research demonstrated that a different approach to determining the type of fault for decision making purposes was available. Specifically, the research gave confidence to the interpretive methods that consider both “belief” functions and “plausibility” functions, where the difference between represents the ignorance in the data set. When considering the THB interpretation rule, and these two functions, a decision-making framework could be applied to existing consensus industry diagnostic methodologies. Zhao and Su (2008), in an attempt to develop a rapid learning model to improve on these fault diagnosis methodologies and

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fault type classification, presented a decision tree model with a focus on pruning the tree to reduce noise and improving the classification process. In reviewing decision trees, Zhao and Su stated that a decision tree was a “tree structure similar to a flow chart, where each inner node expresses test or selection for an attribute, and every branch represents a tested output, but each leaf node represents class or class distribution (p. 6882).” While most trees originate with a top root node and branch to attributes based on TRUE or FALSE, or YES or NO, or other classification criteria, Zhao and Su’s tree was designed to flow to a unique fault classification.

probabilistic theories, Tang et al. (2004) approached the model from a unique ER approach. This involved providing higher and lower weights to those attributes considered in the condition assessment. After considering all of the attributes, and their new weighted “grades”, a total analysis could be conducted by “combining” all the grades together. Tang et al. referred to these inputs as “evidences for evaluation” and were the basis of the MADM solution. Following their ER approach, the following steps were used to rank the transformer’s condition:

For simple decision trees, the selection of the attributes is generally based on statistical considerations. With the attributes determined and the initial tree constructed, statistics can be used to weigh the branches and determine abnormalities in the data. Zhao and Su (2008) refer to this process as “Tree Pruning”. In the application of decision tree models for DGA, Zhao and Su combined classification rules in an IF-THEN format with a model considering Roger’s Ratio gas diagnostics. By developing a decision tree based on the historical data, prior information on fault knowledge, and probabilistic statistical significance, Zhao and Su demonstrated that the model could improve reasoning, response times, and aid with larger scale data base analyses. Noting that there were still flaws and deficiencies in current fault diagnosis methods, Zhao and Su stated that improvements in neural networks, fuzzy systems, and expert systems could result in faster diagnosis speeds and lager data-compression quantity issues.

●● The weights for each attribute are determined and factored.

As Zhao and Su (2008) believed that improvements in neural networks and other advanced techniques applied to DGA diagnostics could be beneficial, Tang, Spurgeon, and Wu’s (2004) earlier work noted that these approaches would be limited to classification problems. Their preferred approach was based on the fact that DGA diagnostic problems actually required a multiple-attribute decision making (MADM) solution. As an extension to traditional decision tree modeling, Tang et al. (2004) presented a decision tree model combined with an evidential reasoning (ER) approach for transformer fault and condition assessments. It combined the results from the major DGA diagnostic methods into one cumulative evaluation. Considering the same theory as referenced by Radzian (2010), Tang et al. combined the Demster-Schafer theory with an evidencebased theory and framework, and an ER decision tree to account for the uncertainty found in the condition assessment information. The decision tree and overall condition of the transformer were based on three attributes (i.e., three pieces of evidence) including thermal condition, discharge condition, and on-load tap changer (OLTC) factors. The supporting data sources were obtained following the IEEE Key Gas Method, CIGRE regulations, and the Rogers Ratio method. With the majority of qualitative fault analysis judgements based on subjective beliefs and uncertainties and traditional Baynesian

●● Subjective judgements are produced using various DGA methods for all the alternatives involved. ●● The subjective judgements are scaled into weighted outputs under an ER framework. ●● Demster-Shafer combination rules are applied to derive the overall evaluation (in predefined grades) ●● The preference degrees for each alternative are generated and the alternatives conditions are ranked. The ER algorithm and approach provided users with a condition assessment and decision making tool that could be extended to other diagnostic fluid tests. Like many evaluation methods that considered similar or even conflicting information from various sources, this approach provided a means to combine evidences and address uncertainties while coming to a solution. An example of the use of artificial neural networks (ANNs) for the classification of fault diagnostics in power transformers was presented by researchers Seifeddine, Khmais, and Abdelkader (2012). In classifying faults by choosing between DGA gas signatures, Seifeddine et al. stated that the use of ANN resulted in superior performance in terms of diagnostic accuracies and power transformer fault classification. In their study of the Tunisian Company of Electricity and Gas (STEG), the six fault types identified in the IEC Publication 60599 were identified and a new model was analyzed along with the generally accepted conventional Key Gas, ratio, and graphical representation methods. The research compared two ANN approaches; the Multi-Layer Perceptron (MLP) and Radial Basis Function (RBF) approaches. With ANN, the development of this model involved a training set (e.g., 160 samples in the STEG case) which included all of the data for the three methods plus the diagnostic results from onsite inspections. With both models developed, the neural network was then tested to determine relative accuracy between each of them. Based on the research with MLP and RBF, Seifeddine et al. concluded that the addition of ANN contributed to improved accuracy in the combination ratios and graphical representation diagnostic approaches. An earlier approach of utilizing ANN that showed great potential in improving the accuracy of fault type classifications came from the work of Wensheng, Zheng, and Zhang (1998). Using an agreed upon decision tree method with an up to down identi-

78 fication order, an improved classifier was created that combined “multiple” artificial neural networks (ANNs) for improved diagnosis accuracy. The approach involved a significant database and understanding of rules-based diagnostics. Recognizing that the IEC method was widely used in the industry, the application of ANN to transformer diagnostics required a large number of training samples (i.e., DGA testing data and prior knowledge of transformer faults) and the complex application of a combinatorial ANN. Wensheng et al. presented 13 common faults and a decision tree that began with an initial rule-based identification of normal or abnormal. Each leaf (or terminal node) represented one of the 13 fault models with one normal node. At 76.9% total accuracy, the decision tree network was developed with 616 training samples, and the model was verified by 256 clearly faulted transformer units. The use of multiple ANN allowed the identification rules from consensus approaches to be “adopted” and the system to become a learning identification system capable of improving complex classifications. With many modern decision tree models still limited to single ANN, this early work presented an opportunity for improving the diagnostic work currently under way. In regard to the improvement in classification, the use of combinatorial ANN provided a total accuracy of more than twice that of similar models utilizing single ANN – an improvement that should be considered in future research applications (Wensheng, Zheng, & Zhang, 1998). As these different approaches and use of advanced technologies are combined, the tools available for aiding in decision making should expand the use of applications across industries. In the application of continuous monitoring systems and fault diagnostics, Sakthivel, Sugumaran, and Nair (2010) stated that the use of decision trees, fuzzy systems, and fuzzy hybrid systems are gaining momentum. They recognized that the use of machine learning for fault diagnostics is gaining acceptance. In a study of centrifugal pumps, for example, faults are detected by vibration analysis generated by bearing, seal, impeller, and cavitation issues where frequency and related harmonics provide location, type, and root cause identification. Studies using fuzzy logic as a classifier, decision trees to identify the major features of a fault, and proximal support vector machine (PSVM) for classifying faults with statistical means have been used successfully for fault classification. Sakthival et al. (2010) approached the fault diagnostic topic with a “feed forward network with back propagation algorithm and binary adaptive resonance network (ART1) which would classify seven categories of faults… (p. 1888).” They did caution that ANN could provide too generalized of a result and over fit the data, and that steps should be taken to minimize this possibility. To address existing limitations, Sakthivel et al. (2010) combined decision tree rule generation with fuzzy classifiers based on different fault states, and also considered a rough set-based prototype system for ranking fault diagnosis based on past diagnostic records. It was concluded that both the use of decision tree and

Transformers Vol. 1 the use of rough set rules each provided a means for classification. When combined with the Fuzzy rules and fuzzy logic (consisting of “imprecise, uncertain and ambiguous terms” and the assigning of values to output vectors), the rules generated were used in the final characterization of fault types. The decision tree-fuzzy method was shown to be highly effective for fault diagnostics in systems where faults develop over time and hard threshold values are not provided. The method was shown to be a good tool in defining when a unit was good and when it is was faulty (Sakthivel, Sugumaran, & Nair, 2010). The centrifugal model presented a similar application to the use of fuzzy logic in the interpretation of fault gases in electrical equipment techniques. Liu, Yao, Chen, Lin, and Wang (2011) provided an integrative fuzzy inference based approach that considered fault conditions, hybrid fault factors, and what they referred to as “identifiable factors”. Noting that existing methods were constructed from rigid classification rules, Liu et al. (2011) stated that the use of the Dornenburg’s ratios, Roger’s ratios, basic gas ratios, Duval’s triangle (referred to as “the percentage analysis”), and the existing number code analyses often provide results that are not in complete agreement. To address this, Liu et al. applied a fuzzy inference system (FIS) to determine three sets of identifiable factors to conclude the correct fault type. If disagreement between the three sets existed, the highest identifiable factor was recalculated and used in the fault type classification. Liu et al. concluded that the development of a fuzzy inference system based on a limited amount of data, and employing a precision rate (the number of correct diagnostics/ number of diagnostics x 100) and a recall rate (the number of correct diagnostics/total number of faults x 100) provided an improved method when compared to existing fault classification methods. (Liu, Yao, Chen, Lin, & Wang, 2011). Guo-wei, Chao,Yan-tao, and De-you (2009, p. 1) offered a new DGA classification approach based on “fuzzy technique of order preference by sunilarity to ideal solutions (TOPSIS)”. To support the currently utilized IEC ratio-based interpretive method, fuzzy theory applied to DGA diagnostics resulted in a multi-attribute decision making problem. Guo-wei et al. presented a mathematical process that involved expressing fuzzy testing data as triangular fuzzy numbers, and then expressing the fuzzy numbers as triangular triples for seven semantic variables (i.e., ranging from “Very Low” to “Very High”). In summary, the process converted fuzzy data and complex reasoning into a simple mathematical calculation, and into “semantic” terms that could be more easily utilized to make a decision. With approaches like this based on the earliest fuzzy work of L. A. Zadeh in 1965, the use of fuzzy theory was extended to problems with incomplete or unclear information, and it was later applied to a decision making matrix model that addressed multi-attribute decision making problems. Methods such as this have been gathering momentum internationally as researchers continue to look for improved methods to improve preventive maintenance programs.

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Transformers Vol. 1 Much of the fuzzy and AI work of investigators has been focused on improved classifications of incipient faults. Current research gaps in this field exist that could benefit from these approaches including work on rates of fault gas generation, acceleration rates of fault gas generation, and the interrelationships between the various insulation fluid tests. While novel approaches to determining the action limits for gas rate determinations have included recommended updates to the current IEEE Guide for the Interpretation of Gases Generated in Oil-Immersed Transformer (IEEE C57.014-2008), future work of this type could be valuable. Accepting that DGA is the “the most significant technique for the identification of faults, electrical and thermal, in fluid-filled transformers,” Jakob, Noble, and Dukarm’s (2011, p. 554) work on providing an energy-weighted dissolved gas analysis (EWDGA) value provides an example of alternative energy-based models that could involve a fuzzy approach. With limited resources in the industry and the need for simple to use tools, certain fuzzy and AI approaches will find limited initial support and acceptance. For many, the ease and use of standard Excel spreadsheets have been found to provide an adequate and easy to use platform for establishing IEEE, IEC, and CIGRE models. While the use of modeling has been presented in a multitude of industries and has experienced significant growth in previous decades, Savic, Bicik, and Morley (2011) stated that the successful use of DSS has more recently been limited by behavioral and technical issues related to performance and implementation of the systems. To improve the adoption and acceptance of DSS, Savic et al. proposed that system development include systems that are less developer and more end-user oriented. Noting multiple software packages available in the market, the recommendation was made to use Microsoft Excel as a standard DSS generator. As a tool, Excel offers the “graphical user interface, database, modeling, data analysis and programming tools for creating small and medium-size DSS with minimal effort (Savic, Bicik, & Morley, 2011, P. 552).” Excel has also been shown to successfully address multiple objective problems. In cases where maximizing a benefit, minimizing a cost, improving reliability, and leveraging an asset are all often considerations in the purchasing, maintenance, and operation of electrical equipment. Savic et al. (2011) reference the ability of Excel and DSS generators add-ins like GANetXL to enable the determination of the “best solution” while optimizing multiple objectives. To illustrate the use of a DSS generator, we provided the reservoir example discussed earlier. Savic et al. (2011) provided a model-based DSS with two objectives for a water supply reservoir operation; the maximization of the water supply outflow (or maximized yield) by the reservoir, and the maximization of water retention (or recreational benefit) for users of the lake. Much like transformers or any operating piece of equipment, optimizing multiple objectives are inherent in the decision making process. Considered an ideal tool By Savic, Bicik, and Morley (2011)

for small and medium-sized modeling, Excel offered the benefits for end-user acceptance, adoption, and implementation. As users gain confidence and the use of these introductory systems offer optimal support over extended periods of time, their acceptance and interest will continue to grow. In their use for analytical diagnostics, similar intuitive and non-expert modeling tools will be gain acceptance and will be utilized to improve the decision making capabilities of users of DGA. Whether one is evaluating new approaches to improving upon IEEE guidelines, identifying manufacturer specific gas threshold values, or introducing new interpretive tools to leverage untapped information, the use of decision support systems will continue to find their place in converting data to information, and information into actionable information.

REFERENCES Anthony, R. N. (1965). Planning and control systems: a framework for analysis. Cambridge, MA: Harvard University Graduate School of Business. Archer, Stephen H (1964). The structure of management decision theory. Academy of Management Journal, 7(4), 269- 283. Asemi, A., Safari, A., & Zavareh, A. A. (2011). The role of management information system (MIS) and decision support system (DSS) for manager’s decision making process. International Journal of Business and Management , 6(7), 164-173. doi: 10.5539/ ijbm.v6n7p164 Baldwin, J. S., Allen, P. M., & Ridgway, K. (2010) An evolutionary complex systems decision-support tool for the management of operations. International Journal of Operations & Production Management, 30(7), 700-720. Chang, N., & Sheng, O. R. L. (2008). Decision-tree-based knowledge discovery: single- vs. multi-decision-tree induction. INFORMS Journal on Computing, 20(1), 46-54. doi: 10.1287/ ijoc.1060.0215 Cummins, J. D., & Phillips, R. D. (2009). Capital adequacy and insurance risk-based capital systems*. Journal of Insurance Regulation, 28(1), 25-72. Davenport, T. H., & Harris, J. G. (2009) The prediction lover’s handbook. MIT Sloan Management Review, 50(2), 32-34. Duan, R., & Zhou, H. (2012). A new fault diagnosis based on fault tree and Bayesian networks. Energy Procedia, 17(B), 1376-1382. Gorry, G. A, & Morton, M. S. Scott (1971). A framework for management information systems. Sloan Management Review, 13(1), 55-70. Guo-wei, C., Chao, P., Yan-tao, W., & De-you, Y. (2009, April) A new method based on fuzzy TOPSIS for transformer dissolved gas analysis. International Conference on Sustainable Power Generation and Supply, Paper presented at the conference of SUPERGEN 2009, Nanjing. doi: 10.1109/SUPERGEN.2009.5347935

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Hullermeier, E. (2005). Experience-based decision making: a satificing decision tree approach. IEEE Transactions on Systems, Man, and Cybernetics, Part A: Systems and Humans, 35(5), 641653. doi: 10.1109/TSMCA.2005.851145

Russell, S., Yoon, V., & Forgionne, G. (2010). Cloud-based decision support systems and availability context: the probability of successful decision outcomes. Information Systems and eBusiness Management, 8(3), 189-205.

Jampani, R., Fei, X., Mingxi, W., Perez, L., Jermaine, C., & Haas, P. J. (2011). The monte carlo database system: stochastic analysis close to the data. ACM Transactions on Database Systems, 36(3), 18-18.41. doi: 10.1145/2000824.2000828

Sakthivel, N. R., Sugumaran, V., & Nair, B. B. (2010). Comparison of decision tree-fuzzy and rough set-fuzzy methods for fault categorization of mono-block centrifugal pump. Mechanical Systems and Signal Processing, 24(6), 1887-1906.

Kingsford, C., & Salzberg, S. L. (2008). What are decision trees? Nature Biotechnology, 26(9), 1011-1013.

Savic, D. A., Bicik, J., & Morley, M. S. (2011). A DSS generator for mulitobjective optimization of spreadsheet-based models. Environmental Modeling & Software, 26(5), 551-561.

Kovacic, S., & Sousa-Poza, A. (2010). Addressing the disparity in decision theory the gestalt imperative. Proceedings for The Northeast Region Decision Sciences Institute (NEDSI), 492-498. Liu, C., Yao, L., Chen, T., Lin, T., & Wang, S. (2011, July) Fault diagnosis for power transformers based on hybrid fuzzy dissolved gas analysis. 2011 Eighth International Conference on Fuzzy systems and Knowledge Discovery, Shanghai, China. doi: 10.1109/ FSKD.2011.6019700 Liu, S., Duffy, A. H. B., Whitfield, R. I., & Boyle, I. M. (2010). Integration of decision support systems to improve decision support performance. Knowledge an Information Systems, 22(3), 261-286. Jakob, F., Noble, P., & Dukarm, J. J. (2012) A thermodynamic approach to evaluation of the severity of transformer faults. IEEE Transactions on Power Delivery, 27(2), 554-559. doi: 10.1109/TPWRD.2011.2175950 Liu, S., Duffy, A. H. B., Whitfield, R. I., & Boyle, I. M. (2010). Integration of decision support systems to improve decision support performance. Knowledge an Information Systems, 22(3), 261-286. Marginean, N., Sîrbu, J., & Racovitan, D. (2010) Decision trees – a perspective of electronic decisional support. Annales Universitatis Apulensis, 12(2), 631-637. Perry, L. (Ed.). (2009). IEEE Guide for the interpretation of gases generated in oil-immersed transformers: IEEE Std C57.104-2008. New York: New York. Radzian, A. M., & Itoh, M. (2010, January). Decision making framework for power transformer dissolved gas analysis on the basis of Dempster-Shafer theoretical approach. Prognostics and Health Management Conference, Paper presented at the conference of Prognostics and Health Management 2010, Macau. doi: 10.1109/PHM.2010.5413443 Roberts, F. (2008). Computer science and decision theory. Annals of Operations Research, 163(1), 209-253. doi: 10.1007/ s10479-008-0328-z Rozalia, R. V., & Valentin, T. (2008) Spreadsheet-based decision

Seifeddine, S., Khmais, B., & Abdelkader, C. (2012, May) Power transformer fault diagnosis based on dissolved gas analysis by artificial neural network. 2012 First International Conference on renewable Energy and Vehicular Technology, Hammamet, Tunisia. doi: 10.1109/REVET.2012.619276 Sharma, S. P., Kumar, D., & Komal (2010) Stochastic behavior analysis of the feeding system in a paper mill using NGABLT technique. The International Journal of Quality & Reliability Management, 27(8), 953-971. Simon, H.A. (1960). The new science of management decision. Englewood Cliffs, NJ: Prentice-Hall. Simon, H.A. (1997). Administrative behavior: a study of decisionmaking processes in administrative organizations. New York, NY: The Free Press. Tang, W. H., Spurgeon, K., Wu, Q. H., & Richardson, Z. J. (2004) An evidential reasoning approach to transformer condition assessments. IEEE Transactions on Power Delivery, 19(4), 1696-1703. Doi:10.1109/TPWRD.2003.822542 Wensheng, G., Zheng, Q., and Zhang, Y. (1998). A multi-resolution system approach to power transformer insulation diagnosis. International Symposium on Electrical Insulating Materials. Symposium conducted at the 30th Symposium on Electrical Insulating Materials, Toyohashi, Japan. doi: 10.1109/ISEIM.1998.741836 Zhao, F., & Su, H. (2008, June). A decision tree approach for power transformer insulation fault diagnosis. 7th World Congress on Intelligent Control and Automation. Paper presented at the conference of WCICA 2008, Chongqing, China. doi: 0.1109/WCICA.2008.4593980. Tsagalidis, E. G., & Georgiou, A. C. (2009). Using simulation modeling to support decisions in hail suppression programmes with airborne means. The Journal of the Operational Research Society, 60(1), 14-22. Wang, W., & Hussin, B. (2009). Plant residual time modeling based on observed variables in oil samples. The Journal of the Operational Research Society, 60(6), 789-796.

Transformers Vol. 1 Nick Perjanik is the Manager of Knowledge Services for WEIDMANN Diagnostic Solutions Inc. Nick received his Bachelor’s degree in Chemistry and his Master’s degree in Business Administration from California State University. Nick is currently earning a Ph.D. in Applied Management and Decision Sciences from the School of Management and Technology at Walden University. He has more than 16 years experience in the testing of insulating fluids and management of analytical laboratories. Nick’s technical experience includes membership in the ASTM D-27 Technical Committee on Electrical Insulating Liquids and Gases, the CIGRE Working Wroup 47 on DGA Interpretation advancements, and multiple IEEE sub-committees. Nick has authored papers on the application of Dissolved Gas Analysis (DGA) to Transformers and LTCs, Silicon Dielectric Fluids, and the use of Sulfur Hexafluoride (SF6) in Circuit Breakers.

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NETA Accredited Companies Valid as of Jan. 1, 2019

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Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

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alabama 1

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4

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

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18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

26

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

36

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

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44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

46

47

48

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

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florida 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

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indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

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Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

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Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

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Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

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missouri 114

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117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

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143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

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new york 139

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141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

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152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

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148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

173

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Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

164

oklahoma

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

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Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

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222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

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SERIES III

TRANSFORMERS

HANDBOOK

VOLUME 2

Published By Sponsored by

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TRANSFORMERS VOLUME 2

HANDBOOK

Published by

InterNational Electrical Testing Association

TRANSFORMERS–Vol. 2 HANDBOOK TABLE OF CONTENTS The Current Transformer – A Valuable No-Outage Tool........................................... 5 Don Genutis

Electrical Safety and Reliability in Substations – Current Transformer Testing Has an Essential Role.................................................. 7 Dennis Neitzel and Diego Robalino

Transformer Testing Techniques and Standard Development................................... 11 Diego Robalino

SEL Relay Commissioning for SCADA Points Using Test DB Command.................... 17 Richard Furman

The Basis for Performing Insulation Power – Factor Testing on Large Cast-Coil Transformers........................................................................ 20 Bruce Rockwell

QA Electrical Testing of Medium –Voltage Global VPI Stator Windings................... 22 Vicki Warren

Life and Death of a Transformer......................................................................... 27 Keith Burges

Bushings That Bite – What You Don’t Know Can Hurt You!.................................... 32 Tony McGrail

Sweep Frequency Response Analysis – Why it Should Be in Your Diagnostic Toolbox...................................................... 34 Keith Hill

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

Application and Commissioning of Online Partial Discharge Technology for Medium Voltage Switchgear........................................................................ 43 Bruce Rockwell, Bruce Horowitz, Christopher Smith

Electrical Commissioning Tips and Trends for Advanced Critical Facilities Applications........................................................................... 51 Corey Dozhier

Reliability of Electrical Systems From Testing to Monitoring.................................... 55 Alan Ross

Electric & Dielectric Condition Assessment of HV Current Transformers................... 61 Diego Robalino

Bushing Replacement – It Fits, But Will it Work?................................................... 67 Keith Hill

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

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Transformers Vol. 2

THE CURRENT TRANSFORMER – A VALUABLE NO-OUTAGE TOOL NETA World, Spring 2015 Issue BY Don Genutis , Halco Testing Services Current transformers (CTs) are versatile components that can be used in many types of instruments to provide technicians with a wealth of information. CTs are so common in the electrical field that they are often taken for granted, and their importance is often overlooked. They are a great example of how no-outage technology can be applied to energized circuits to determine operating conditions. This article will examine some of the more common uses for current transformers and how they are used in no-outage testing.

CT BASICS CTs are typically used to measure current. Their basic construction generally consists of a solid core or split-core toroidal ferrite material that is wrapped with one or more turns of wire. The primary current, represented as I in Figure 1, produces a magnetic field in the core which then induces a current in the secondary winding. The relationship between the primary and secondary currents is proportional to the number of secondary wiring turns, commonly known as the ratio. Solid cores are typically used for permanent applications, while split-cores are typically used for handheld instrument applications.

Fig. 1: CT Circuit

GENERAL APPLICATIONS By far the most common use of CTs in the electrical power industry is to measure current. CTs provide insulation from the primary circuit and reduce currents to manageable magnitudes for instruments. They can be found permanently installed in substations, switchgear, and switchboards to provide current inputs for

ammeters, kilowatt-hour meters, and protective relays. Ratio, accuracy class, burden, and saturation are some of the characteristics that must be carefully considered when designing circuits that employ CTs. CTs are also widely used in field instruments to temporarily measure and record loads and power quality. The temporary measurement of current is one of the most common field tests performed, ranging from simple field troubleshooting in order to identify an anomaly to recording loads over an extended period of time in order to determine available ampacity for future circuit addition projects. CTs are also used with field power quality instruments to measure and record harmonics, swells, sags, and other power disturbances. In addition to the split-core CT, instruments may also utilize flexible core CTs such as those shown in Figure 2. These types of CT’s are based on the Rogowski coil circuit (Figure 3) and have an aircore instead of a ferrite core which allows for the enhanced flexibility. Flexible CTs are especially valuable when one is making measurements in tight areas or when one needs to measure currents in large switchboard bus segments. It should be noted that the output of the Rogowski coil does not produce a direct ratio of the current such as the ferrite core creates, but rather produces a voltage which requires special circuitry that integrates and processes the output signal in order to convert it to a useful current.

Fig. 2: Flex Core CTs

Fig. 3: Rogowski Coil

OTHER APPLICATIONS Current transformers can also be used to determine grounding system integrity in the field. Instruments such as the one shown in Figure 4 provide a resistance measurement of the conductor to ground by using a split-core CT circuit to transmit a test cur-

6

Transformers Vol. 2

rent and another CT circuit to measure the test current back to the instrument, thus allowing resistance to be calculated. These instruments can be valuable for quickly determining circuit ground resistance but require understanding how the test circuit works in order to avoid misapplication or inaccuracies. For instance, attempting to measure a ground rod’s resistance to earth can be achieved if the test device can measure current only in the tested rod. If the test device is connected such that it measures the rod and another ground cable tied to the grounding grid, the result will be incorrectly low with respect to the rod under test.

●● Carefully position the CT around the conductor under test so that the conductor is in the approximate center of the CT loop in order to obtain the most accurate readings. ●● Avoid the influence of external magnetic fields which can cause inaccuracies even though this can be difficult when making measurements in crowded areas.

SUMMARY Operating quietly and reliably, the CT is often taken for granted, but it is an indispensable device with a wide range of uses for nooutage testing applications. Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

Fig. 4: Clamp-on ground resistance tester CTs can also be used to detect partial discharge (PD) activity. PD activity in medium voltage equipment and components create small radio frequency (RF) currents that flow to ground. Specially constructed split-core CTs that are designed to pick up these RF signals can be safely placed around the equipment’s grounding electrode to decouple the signals and send them to an oscilloscope or other instruments for recording and analysis.

PRECAUTIONS WHEN USING CTS ●● Never allow the CT secondary circuit to become open when current is flowing through the primary. This can create a dangerous high voltage condition at the open in the secondary winding. ●● Be careful to avoid contacting an energized bare bus with the open jaws of a split-core CT. Flex core CTs are generally much safer choices when measuring current in these situations. ●● Make sure that the jaws of a clamp-on CT are fully closed before taking a measurement.

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Transformers Vol. 2

ELECTRICAL SAFETY AND RELIABILITY IN SUBSTATIONS – CURRENT TRANSFORMER TESTING HAS AN ESSENTIAL ROLE NETA World, Summer 2015 Issue Dennis Neitzel, AVO Training Institute, Inc. and Diego Robalino, Megger North America Understanding — or at least having an awareness of — electrical hazards is vital to understanding why there are electrical safety requirements from OSHA and NFPA. This understanding is also necessary for the development of electrical safety programs and procedures, as well as providing the required PPE and training for employees who may be exposed to electrical hazards. According to documented accident investigation reports, several hundred injuries and fatalities occur every year as a result of electrical hazards. The hazards of electricity include electrical shock, electrical arc flash, and electrical arc blast. The physiological effects on the human body should also be understood by everyone working on or near, or interacting with, electrical circuits and equipment. These three generally recognized electrical hazards can exist when doing work in electrical substations and equipment rooms. Electrical Shock – Electrical shock occurs when a person’s body completes the current path between two energized conductors of a circuit or between an energized conductor and a grounded surface or object. Essentially, when there is a difference in potential from one part of the body to another, current will flow. The effects of an electrical shock on the human body can vary from a slight tingle to immediate cardiac arrest. The severity depends on several factors: ●● Body resistance (wet or dry skin are major factors of body resistance) ●● Circuit voltage (50 volts to ground or more is considered to be hazardous voltage by OSHA, IEEE, and NFPA) ●● Amount of current flowing through the body ([determined by the circuit voltage divided by the body resistance I (current) = E (voltage) / R (resistance)]) ●● Current path through the body (if it passes through a vital organ, it can be fatal) ●● Area of contact ●● Duration of contact Electrical shock is generally classified as touch potential or step potential, especially when work is performed in a substation yard. Touch potential is where an energized part is exposed and a person touches it with any part of their body while another part of their body is touching ground, thus providing a path for current to flow.

Step potential is where current is flowing through the ground, as in the case of a downed power line. If a person is in close proximity to the line and takes a step, the path for current will be from one foot to the other. Touch and step potentials can be fatal. Never assume that an exposed electrical part or conductor is deenergized. Electrical Arc Flash – Electrical arc-flash energy is referred to as incident energy and is measured in calories per square centimeter (cal/cm2). The level of incident energy exposure depends on three main variables: the amount of available short circuit current, the duration of the event allowed by the overcurrent protective device, and the distance the worker is from the arc when it occurs. Electrical Arc Blast – Arc-blast energy is the pressure developed during an arc event where copper is vaporized and expands at a factor of 67,000 times. This expansion produces an explosion or arc blast and can propel fragmented and molten metal 10 feet or more.

PROTECTION FROM THE ELECTRICAL HAZARDS The first measure to protect workers from shock, arc flash, and arc blast is to control the electrical hazards with an appropriate hazardous energy control procedure (lockout/tagout or clearance). It is recognized that management-approved energized electrical work must be performed on occasion. To protect the worker from the shock hazard, appropriately rated insulation must be used. For typical low-voltage exposures of 480 volts or less, class 00 gloves with leather protectors rated at 500 volts are available. As the voltage increases, so must the level of required protection. The highest insulation protection is class 4 rated at 36 kV. For most medium- and high-voltage work using live-line tools or discharging stored energy (including testing), class 2 insulated gloves are typically used as a precaution. In addition to voltage-rated gloves, electrical hazard-rated shoes are recommended — but their protection is limited, and they are not recognized as adequate for primary protection. Primary protection can be provided with dielectric overshoes, voltage-rated gloves, insulating blankets, and insulated sheeting materials that protect the worker from contact with energized conductors or circuit parts. Appropriate shock protection boundaries are identified in the standards and regulations and must be implemented to limit exposure to the shock hazard. The first protection boundary is the limited approach boundary

8 and is limited to qualified electrical workers using the correct personal protective equipment (PPE). Alerting techniques are used to keep all workers from inadvertently crossing the limited approach boundary and possibly coming in contact with exposed energized conductors or circuit parts. Correct alerting techniques include: ●● Safety signs and tags ●● Barricades ●● Attendants Electrical hazards exist every time a worker enters a highvoltage substation yard or equipment room. An electrical hazard analysis and risk assessment must be performed prior to entering the substation to identify hazards and the appropriate safe work practices and PPE that will be required.

MAINTENANCE & TESTING The first step in properly maintaining electrical equipment and overcurrent protective devices is to understand the requirements and recommendations for electrical equipment maintenance from various sources. Source examples include, but are not limited to, the manufacturer’s instructions, NFPA 70B, IEEE Std. 3007.2, NEMA AB-4, ANSI/NETA MTS, 46 CFR 111, and NFPA 70E. The second step in performing maintenance and testing is to provide adequate training and qualification for employees. NFPA 70E, Standard for Electrical Safety in the Workplace, Section 205.1 states, “Employees who perform maintenance on electrical equipment and installations shall be qualified persons…and shall be trained in and familiar with, the specific maintenance procedures and tests required.” Electrical Preventive Maintenance Program: NFPA 70E, Section 205.3 states, “Electrical equipment shall be maintained in accordance with manufacturers’ instructions or industry consensus standards to reduce the risk associated with failure.” Section 205.4 further states that “Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards. Maintenance, tests, and inspections shall be documented.” Therefore, the third step is to have a written, effective electrical preventive maintenance (EPM) program. NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, makes several very clear statements about an effective EPM program as follows: ●● “Electrical equipment deterioration is normal, but equipment failure is not inevitable. As soon as new equipment is installed, a process of normal deterioration begins. Unchecked, the deterioration process can cause malfunction or an electrical failure. Deterioration can be accelerated by factors such as a hostile environment, overload, or severe duty cycle. An effective EPM program identifies and recognizes these factors and provides measures for coping with them.”

Transformers Vol. 2 ●● “In addition to normal deterioration, there are other potential causes of equipment failure that can be detected and corrected through EPM. Among these are load changes or additions, circuit alterations, improperly set or improperly selected protective devices, and changing voltage conditions.” ●● “Without an EPM program, management assumes a greatly increased risk of a serious electrical failure and its consequences.” ●● “A well-administered EPM program will reduce accidents, save lives, and minimize costly breakdowns and unplanned shutdowns of production equipment. Impending troubles can be identified — and solutions applied — before they become major problems requiring more expensive, time-consuming solutions.” All maintenance and testing of electrical protective devices must be accomplished in accordance with the manufacturer’s instructions. In the absense of the manufacturer’s instructions, the ANSI/ NETA-MTS Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems is an excellent source of information for performing the required maintenance and testing of these devices.

WHO IS MONITORING THE SYSTEM? Current transformers (CTs) serve as a critical and essential interface in the world of electrical power. At first glance, the role of a CT may appear to be a simple one; however, CTs function as one of the most important components of the electrical system infrastructure. The performance of these devices is reflected in the correct operation of metering devices, relays, and circuit breakers. Therefore, a comprehensive yet simple approach to evaluating the condition of low-, medium-, and high-voltage CTs is paramount for testing service companies and utility operators. CT saturation, incorrect polarity, ratio inaccuracies, wrong sizing of burden, and insulation failure can all lead to misoperation of protective schemes, or possibly a failure of protection schemes altogether. Unreliable and perhaps unpredictable CT performance could increase the risk of potentially permanent damage to major devices. Therefore, a complete CT evaluation should consider electrical tests that will verify the function and performance of the CT in relation to nameplate data and industry recommendations. Standards and guidelines referenced in such an evaluation would include IEEE C57.13.1, C57.13.5, the ANSI/NETA ATS, and ANSI/NETA MTS standards. It is imperative to evaluate CTs in the field with highly reliable and accurate results. For this reason, there must be a test plan

that covers the operating characteristics as defined by the

nameplate data. Just as importantly, the condition of the dielectric system must be assessed by tests performed when the equipment is out of service, by neither intrusive nor destructive techniques.

9

Transformers Vol. 2 A proposed basic plan for the implementation of field testing is shown in Figure 1.

plished by applying an algorithm that utilizes either AC or DC current. Elimination of remnant magnetism in the core ensures subsequent testing of excitation and ratio test results will be accurate and reliable. Following the proposed plan to test the CT, and having it fully demagnetized, the next step is to perform excitation and saturation testing. Both excitation current and the RMS voltage of the secondary winding should be clearly observed in the measurement process. Some may incorrectly contend that there is no difference in whether the secondary voltage measurement is the average or the RMS. The two curves essentially overlap in the linear region below the knee (saturation point). However, beyond the knee of the saturation curve, Figure 2 shows that RMS values are higher than the average voltage measurement.

Fig. 2: CT excitation curve RMS current vs. Average responding voltmeter

Fig. 1: Process diagram for basic field testing of CTs With high-voltage CTs, it is especially important to have a historical assessment of the CTs’ insulation resistance. In the absence of an acceptable insulation resistance test result, there is a safety concern regarding electrical shock during testing or operation of the unit. NETA recommends that the testing of insulation resistance between windings or between a winding and the ground connection is made at 1000 V dc or at a tolerance recommended by the manufacturer. Once a CT’s dielectric properties have been verified as acceptable, the next step is to verify the performance characteristics and nameplate compliance of the transformer. A secondary winding resistance test is performed by injecting dc current into the secondary winding. Once the flux density in the CT core is stable, the voltage drop across the winding can be measured (somewhere in the order of 100 mV). Ohm’s law can then be applied to accurately calculate and record the resistance of the winding. Upon completion of winding resistance test, the core of the CT must be demagnetized. Demagnetizing the CT can be accom-

One additional test can prove the ratio and the polarity of the CT. Ratio measurements would need to be collected in the linear portion of the excitation curve, below the point that the CT would begin to saturate. IEEE C57.13.2008 provides two methods of obtaining this information; one requires that primary current be injected into the CT and secondary current measured, and the other allows for the application of voltage to the secondary of the CT with the primary voltage measured. The polarity test, performed during the same step as the ratio test, confirms that the predicted direction of secondary current flow is correct for a given direction of primary current flow. To complement the CT basic test procedure, one should also verify the impedance of the applied load to ensure that the burden of the circuit does not exceed the conditions in which the CT can maintain its specified accuracy and performance.

CT COMPLEMENTARY DIELECTRIC TESTS While the importance of an insulation resistance test as part of the basic test plan has been described, high-voltage (HV) dielectric system devices require additional dielectric tests. For HV CTs, it is important to verify if a test tap is available before performing the test. In the more complex case of a CT, where the insulation system consists of paper wrapped in graded sections

10

Transformers Vol. 2

and immersed with a test tap, all capacitive sections (as shown in Figure 3, page 10) can be tested.

Fig. 3: CT testing capacitances for diagnostics In Figure 3, all possible capacitances to be tested in a CT with a test tap are described below: HV - high-voltage terminal LV - low-voltage terminal D - tap test point C1 - represents the main insulation between HV and D C2 - represents the insulation between the test tap and ground; Typically the test voltage for this capacitance does not exceed 500 V ac, unless the manufacturer provides a different recommendation C3 -  represents the insulation between the test tap and the secondary winding C4 - represents the insulation between LV and ground C5 - represents the insulation between the HV terminal directly to ground, including porcelain surfaces If advanced diagnostic tests are conducted to determine moisture content in the solid insulation system, it is then necessary to apply dielectric spectroscopy techniques— preferably, in the frequency domain. Dielectric response in the frequency domain (DFR) involves a procedure similar to the power factor test method; but in this case, a wide band frequency sweep generates the unique dielectric response of the insulation (capacitance) where the greatest amount of solid insulation is located. For most cases, the capacitance C1 is tested for CTs with test tap and C5 for CTs without test tap.

CONCLUSION Safety in the workplace is mandatory. Electrical equipment operators and all energy-related professionals are required to be

aware of the potential hazards while working in energized environments. To protect electrical equipment and personnel, proper electrical equipment preventive testing and maintenance must be performed. Several available standards and guides assist users with electrical equipment testing and maintenance. Maintenance of overcurrent protective devices is critical, but even more important is ensuring a trustful source of information to trigger any of these devices under an unexpected fault condition in the system. A simple and practical reference to test current transformers has been provided in this document. Dennis K. Neitzel, CPE, Director Emeritus of AVO Training Institute, Inc., Dallas, Texas, has over 45 years experience in Electrical Utility, Industrial facility, and shipyard/shipboard electrical equipment and systems maintenance and testing experience, with an extensive background in electrical safety and power systems analysis. He is an active member of IEEE, ASSE, AFE, IAEI, and NFPA. He is a Certified Plant Engineer (CPE) and a Certified Electrical Inspector-General. Mr. Neitzel earned his Bachelor’s degree in Electrical Engineering Management and his Master’s degree in Electrical Engineering Applied Sciences. He is a Principle Committee Member and Special Expert for the NFPA 70E, Standard for Electrical Safety in the Workplace; member of the Defense Safety Oversight Council, Electrical Safety Working Group – DoD Electrical Safety Special Interest Initiative; Working Group Chairman of IEEE 3007.1-2010 Recommended Practice for the Operation and Management of Industrial and Commercial Power Systems, 3007.2-2010 Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, & 3007.3-2012 Recommended Practice for Electrical Safety of Industrial and Commercial Power Systems; Working Group Chairman of IEEE P45.5 Recommended Practice for Electrical Installations on Shipboard - Safety Considerations; and co-author of the Electrical Safety Handbook, McGraw-Hill Publishers. Mr. Neitzel has also authored, published, and presented numerous technical papers and magazine articles on electrical safety, maintenance, and training. For more information, contact Mr. Neitzel by e-mail at [email protected]. Diego Robalino works for Megger as a senior applications engineer, where he specializes in the diagnosis of complex electrical testing procedures. While doing research in power system optimization with a focus on aging equipment at Tennessee Technological University, Diego received his electrical engineering Ph.D. from that institution. With an international background spanning from South America to Eastern Europe, he’s garnered additional education experience in project management and electric drives/ automation. Diego has many years of management responsibility in the power systems, oil and gas, and research arenas managing the design, construction, and commissioning of electrical and electro-mechanical projects. He is an active member of IEEE, ASTM, and PMI with multidisciplinary engineering interests.

11

Transformers Vol. 2

TRANSFORMER TESTING TECHNIQUES AND STANDARD DEVELOPMENT NETA World, Winter 2015 Issue Diego M. Robalino, MEGGER-AVO Training Institute Transformer manufacturers and field operators have always benefitted when new technologies are applied during design, manufacturing, commissioning, and operational processes that improve the quality and reliability of electrical apparatuses. The new computational tools and the continuous research by individuals in the academic, public, or private sectors have created better materials capable of withstanding demanding service conditions, saving space, and minimizing energy losses. As manufacturing technology advances at this rapid pace, testing methodologies must evolve to keep pace. Advances in power electronics and computer technology lead to more accurate, reliable, portable, and user-friendly instruments in the field. As technological advances and new testing methodologies become more readily available to transformer testing personnel, how can we keep up with this avalanche of new and promising alternatives, which at first glance seem to solve all our diagnostic problems? One way is by following the activities of national and international regulatory institutions that focus their resources on keeping up with the latest technological developments for design, construction, operation, testing, maintenance, and even post-mortem investigations of power and distribution transformers. IEEE, NETA, CIGRE, and IEC are the best references in this area. Starting with a transformer’s factory acceptance testing (FAT) and continuing through its service life, mechanical, dielectric, thermal, and electro-magnetic parameters are evaluated. Once the transformer has passed the FAT, it is ready for shipment to a new site, where a testing crew will commission the unit before energization. The next step is to follow the standards.

IEEE STANDARD C57.152-2013 IEEE is the world's largest professional association dedicated to advancing technological innovation and excellence for the benefit of humanity. The IEEE transformer committee handles all matters related to the application, design, construction, testing, and operation of transformers, reactors, and other similar equipment. The IEEE Transformer Committee met in Dallas in 2007 to revise the existing guide for routine testing in the field, IEEE 62, Guide for Diagnostic Field Testing of Electric Power Apparatus Oil Filled Power Transformers, Regulators, and Reactors (R2005). At the time, a vast number of old and new testing methodologies and practices were used in the field but not covered by the IEEE 62 standard. It was logical to create a new or revised guide under the C57 standard series. The C57 standards already contained other transformer-related guidelines administered and supervised by the IEEE Transformer Committee (Fig 1).

Fig. 1: IEEE C57 series dedicated to transformer guidelines and standards The new guide for diagnostic field testing of fluid-filled power transformers, regulators, and reactors was balloted and approved by RevComm in 2013. The work was led by Jane Verner (Chair), Loren Wagenaar (Vice Chair), Kipp Yule (Secretary), and supported by many members of IEEE who dedicated long hours in revisions and contributions to the new guide. The comparison between IEEE 62 and IEEE C57.152 brings something else to this discussion. The new Diagnostic Test Chart complements the old one, keeping the existing practices and adding those methods not considered previously. A comparative analysis shows the following methodologies were added to the new guide: Windings: ●● Frequency Response Analysis (FRA) Insulating liquid: ●● Furan Analysis ●● Corrosive Sulfur Current transformers: ●● Ratio ●● Polarity ●● Resistance IEEE C57.152 (Chapter 5) also considered the importance of providing a maintenance chart where the end user could select

12

Transformers Vol. 2

the testing practices recommended (REC), as-needed (AN), and optional (OPT) for different stages during the service life of the transformer: commissioning, in-service, after protection trip due to system fault, or after protection trip due to internal fault. In this chart, induced voltage and dielectric frequency response (DFR) are listed as optional techniques. Not only are more testing methodologies listed in the new maintenance and diagnostics charts, but also included are new annexes developed to complement the guide regarding these new additions: ●● Annex D (informative) Dew Point Test ●● Annex E (informative) Furan Testing ●● Annex F (informative) Frequency Response Analysis ●● Annex G (informative) Dielectric Frequency Response ●● Annex H (informative) Other methods to verify polarity from previous field test guide revisions ●● Annex I (informative) Particle Count ●● Annex J (informative) Bibliography Only general information about FRA and DFR was included in annexes F and G because when C57.152 was close to being published, other working groups were developing specific guidelines for the advanced diagnostic techniques of SFRA and DFR. Frequency response techniques have been used in the field for over 20 years. Researchers worldwide have found SFRA and DFR useful not only in transformer diagnostics, but also in other electrical apparatuses in the field. For now, focus is on transformers where the electro-mechanical and dielectric condition can be evaluated and traced for better diagnostics and interpretation of results. In 2012, a new working group was created within the IEEE Transformer Committee to develop a guide for DFR analysis, PC57.161, which is currently under development.

CIGRE Founded in 1921, the Council on Large Electric Systems (CIGRE) is an international nonprofit association that joins forces with experts all over the world to improve electric power systems of today and tomorrow. Of course, the transformer topic is covered by several technical brochures dedicated to particular areas of interest in the scientific and operational fields. CIGRE 445, the guide for transformer maintenance, provides a diagnostics matrix where a line is drawn to differentiate basic electrical testing from advanced electrical testing (Figure 2). In this publication, frequency response techniques in time and frequency domains are grouped together with partial discharge (PD) testing as advanced electrical diagnostic techniques.

Fig. 2: CIGRE 445 - Electrical tests and DGA diagnostics matrix CIGRE pioneered publishing guidelines dedicated to the frequency response methods. In 2008, CIGRE published Technical Brochure 342 — Mechanical Condition Assessment of Transformer Windings Using Frequency Response Analysis (FRA). This document is an excellent reference describing the principles of FRA, the suggested best practices for making repeatable measurements, and guidance for interpretation. CIGRE also undertook a large project to investigate the frequency response of the dielectric components inside the transformer, publishing Technical Brochure 414 — Dielectric Response Diagnoses for Transformer Windings in 2010. As before, CIGRE provided a well-developed document, describing the transformer dielectric response model, the best testing practices, and guidelines for the interpretation of results.

IEC Founded in 1906, the International Electrotechnical Commission (IEC) is the world’s leading organization for the preparation and publication of international standards for all electrical, electronic, and related technologies. Prepared by Technical Committee 14, the IEC 60046 standards series covers technical areas related to transformers. Standard IEC 60046-1 (2011) is the latest revision available for power transformers and IEC 60046-18 Ed. 1 (2012) addresses the methodology, best practices, and minimum requirements for measuring equipment as well as suggestions on formatting the data resulting from the test.

13

Transformers Vol. 2 IEC 60046-18 also includes several annexes. Annex A covers the measurement lead connections. This is sometimes critical, especially when the operator is not applying an adjustable ground braid to the transformer bushing. On subsequent attempts to generate the transformer signature, replicating the high-frequency band is almost impossible. The shortest distance between the bushing terminal and the bushing’s bottom flange is recommended and addressed by CIGRE in Technical Brochure 342. Annex B covers factors influencing FRA measurements including residual magnetization, use of different liquids and the level of liquid filled in the tank, temperature, and others. It also includes a few examples of confirmed damages in the windings detected by the FRA test. Annex C covers the applications of FRA, and Annex D provides examples of measurement configurations.

TRANSFORMER ADVANCED DIAGNOSTICS BY FREQUENCY RESPONSE TECHNIQUES

Fig. 3: SISO – Representation of a transfer function in time and frequency domains In the case of power transformers, the electromagnetic phenomena is well described by different laws (Faraday, Lenz, Ampere); by simple inspection, it is easy to understand that the physical structure of the winding can be represented in the electric language by an RLC complex circuit with multiple series and parallel combinations of these components (Figure 4).

The objectives and scope of each frequency response method must be clearly understood before it can be chosen for the most appropriate application. Frequency response analysis or sweep frequency response analysis (SFRA) is a comparative test to evaluate the electro-mechanical condition of the transformer. Deviations between frequency responses indicate mechanical and/or electrical changes in the active part of a transformer. Dielectric frequency response or frequency domain spectroscopy (FDS) is a test to evaluate the overall condition of the transformer’s insulation. This overall insulation evaluation allows the user to identify: ●● The percentage of moisture concentration in the solid insulation ●● The conductivity or the dissipation factor of the liquid insulation corrected to 25°C ●● The thermal behavior of dielectric parameters at specific frequencies, determining an accurate power factor / dissipation factor correction not based on table correction factors but on the individual dielectric response of the unit under test (UUT) ●● The presence of contaminants creating a distortion of the dielectric response (also called non-typical dielectric response)

Fig. 4: Simplified diagram of the winding configuration The ac input signal applied to one end of the winding at one specific frequency passes through the complex electric circuit of the winding and into the other end. The output voltage is measured in magnitude and phase. This information allows for interpretation and measurement of the effective impedance of the winding at that specific frequency. The frequency sweeps from 20Hz up to 2MHz. Instruments available in the field have frequency bands starting from very low values up to frequencies beyond 20Mhz. Typically, a 2MHz upper limit is sufficient for power transformers, and a clear and repeatable response of the magnetic circuit can be obtained from 20Hz up to approximately 2kHz, depending on the transformer design. IEEE and IEC have set reference boundaries on the frequency response to identify the different sections of the transformer (Figure 5).

A deeper look at each technique is helpful to understand their advantages.

SWEEP FREQUENCY RESPONSE ANALYSIS According to control theory, the behavior of a linear single-input/ single-output (SISO) system can be described with an impulse response h(t) or its transfer function H(jw) (Figure 3). Fig. 5: Frequency Response Analysis — IEEE C57.149

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Transformers Vol. 2

A good grounding connection practice allows for accurate and repeatable readings (Figure 6). Make sure the ground braid connection to the bushing’s bottom flange is solid and that the flange is grounded. Sometimes, oxidation or paint do not allow a good connection to ground, and error messages will come out of the unit not sensing the expected voltage.

The testing procedure is quite similar to that applied for power factor or dissipation factor testing. The main difference is the wide-frequency band used by DFR. The simple example of a twowinding transformer shows the three electrodes needed to complete testing: HV, LV, and ground (Figure 7). An excitation ac signal is applied to one electrode in a wide range of frequencies — typically from 1kHz down to 1mHz — and current is measured on the other electrode. The test is carried out at low voltage (200Vp) for transformer testing. For environments with high interference, a voltage amplifier increases the signal-to-noise ratio. The use of a voltage amplifier is fundamental for the analysis of bushings and instrument transformers. A two-winding transformer can analyze the following:

Fig. 6: CIGRE 342 recommendation for grounding the HF leads One important thing to emphasize regarding an SFRA measurement is that it provides a very clear scan of the electromechanical construction, but interpretation may always be validated with a different testing technique Table 1.

●● CHL — capacitance between HV and LV windings (i.e. inter-winding capacitance) ●● CHG — capacitance between HV winding and ground ●● CLG — capacitance between LV and ground ●● Bushing C1 and C2 capacitances, but only if test tap is available in the bushing ●● Only oil sample DFR

Fig. 7: Hook-up diagram for DFR testing on a two-winding transformer The response is a combination of a two-material complex dielectric system. For the majority of power transformers, the complex insulation is composed of liquid insulation (mineral oil) and solid insulation (cellulose). The dielectric response of these two materials provides an in-depth understanding of the insulation system and allows differentiation between the condition of the liquid insulation versus the condition of the solid insulation.

Table 1: Correlation of SFRA with Other Testing Practices

DIELECTRIC FREQUENCY RESPONSE This technique is already used by many utilities and transformer manufacturers, which have greatly benefited from the vast amount of information gathered from the unique and individual dielectric response of the transformer insulation.

An example of a transformer in excellent condition is presented in Figure 8. Moisture in the solid insulation is only 1% and the conductivity of the oil is 1x10-13. Temperature of the insulation system in this example is 20°C.

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Fig. 8: DFR of a transformer’s liquid-paper insulation (X=20, Y=20, %mc=1%, Σ=1E-13 pS/m, T=20°C) For interpretation of DFR results, the XY model explains the relationship between the solid insulation, the liquid insulation, and the system geometry. The XY model is well described in CIGRE 414 and briefly described below in Figure 9.

Fig. 9: The physical (a) and the modeling (b) representation of the inter-winding insulation Following the XY model and using mathematics to match the readings to those in a well-developed database, users can determine the moisture concentration in the solid insulation and the conductivity (Σ) of the liquid insulation. The information indicates the overall condition of the insulation and is a simple but powerful tool for coordinating and prioritizing necessary actions to be taken on a transformer. Note that DFR is not an invention of the last millennium; it was developed in the mid 1990s and continues to evolve. Because it has a proven effectiveness in the field, its applications grow every day. No doubt, part of this development is the use of a multi-frequency measurement system capable of reducing the testing time by almost 40% in the frequency domain. Testing time is critical for end users who are limited to fast testing procedures before reenergizing a transformer in the field, or as part of a planned shutdown for maintenance purposes. Furthermore, if the transformer was under load but de-energized and set for testing, a long DFR testing time may incur insulation thermal changes that will affect accuracy of the results — the lower the frequency, the longer the time needed to complete the testing procedure.

A correlation between temperature and the minimum frequency to complete the test has been recommended for end users. This allows acquisition of sufficient data to estimate moisture content in the solid insulation and conductivity of the liquid insulation. Interestingly, factors other than temperature influence the response — the thermal effect shifts the dielectric response to higher frequencies at higher temperatures and to lower frequencies at lower temperatures. This phenomenon led to another application: identification of the thermal behavior of dielectric parameters such as Power Factor and Dissipation Factor. In other words, DFR opened the door for transition from the frequency domain into the temperature domain of the insulation system, including using it for an accurate individual temperature correction of power factor values at line frequency or beyond it to reference values at 20°C, or any other temperatures from five to 60°C with very high accuracy.

CONCLUSIONS Technology is moving rapidly. Great advances in power electronics, telecommunications, and nanomaterials opened new opportunities to explore the condition of critical components installed in the electric energy system in more detail. As technology advances, new testing techniques are being developed, and the international community needs to comprehend the benefits and limitations of these techniques. The different institutions working worldwide to provide best practices and guidelines rely on the knowledge and experience of transformer manufacturers, academics, researchers, field users, and instrument manufacturers who work together for the best interests of the technical community. New technologies must be tested and tried in the field before they are brought to the attention of international committees for developing the necessary recommendations based on actual facts and real needs of end-users. The international committees go through a process that may take several years before a new guide is created and published. This is the only way to compile into one document the knowledge and experience of the entire technical community involved in this honorable activity. SFRA is one of the most important tools for diagnosing potential mechanical problems in transformer windings. DFR is clearly gaining more importance within the utilities by providing a complete overview of the dielectric system inside the transformer, allowing end users to identify water contamination issues within the solid insulation or high conductivity in the liquid insulation. More discussion regarding these advanced technologies is needed. A great amount of information has been gathered and published by the most relevant technical publications worldwide and international standards organizations, so use this to keep transformer diagnostics tools up-to-date.

16 Diego Robalino works for Megger as a senior applications engineer, where he specializes in the diagnosis of complex electrical testing procedures. While doing research in power system optimization with a focus on aging equipment at Tennessee Technological University, Diego received his electrical engineering Ph.D. from that institution. With an international background spanning from South America to Eastern Europe, he’s garnered additional education experience in project management and electric drives/ automation. Diego has many years of management responsibility in the power systems, oil and gas, and research arenas managing the design, construction, and commissioning of electrical and electro-mechanical projects. He is an active member of IEEE, ASTM, and PMI with multidisciplinary engineering interests.

Transformers Vol. 2

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SEL RELAY COMMISSIONING FOR SCADA POINTS USING TEST DB COMMAND NETA World, Spring 2016 Issue Richard Furman, Southwest Energy Systems, LLC

Southwest Energy Systems, LLC (SES) recently performed level four Supervisory, Control, and Data Acquisition (SCADA) testing for a building management system utilizing Schweitzer Engineering Laboratories (SEL) relays for the 13.8KV distribution system at a data center. What is level four testing, and what does it take to test this type of system at level four? The United States Army Corp of Engineers (USACE) refers to level four testing as proving the communication interfaces such as SEL fast message, Modbus, Distributed Network Protocol 3.0 (DNP3), and IEC 61850. Level three testing only proves the relays input/output, element, and functional testing. During the commissioning of this SCADA system, several problems were noted, including incorrect bit mapping, flipped bits, and wrong word bits. To perform level four testing, you need the joint effort of information technology (IT) personnel and a qualified relay technician.

SYSTEM DESCRIPTION The electrical system under analysis here is a primary loop service using several 10 MVA, 69kV to 15kV transformers for the primary feeds, with back-up generation consisting of several 2-MW generators coupled with the use of several low-voltage uninterruptable power supplies (UPS), making this a robust system capable of supplying constant load. In this article, only one of the many substations used in the distribution service loop will be examined. This SCADA installation uses a graphical user interface (GUI) and human machine interface (HMI) to monitor and control the system. Communications are via ethernet connection to the real-time automation controller (RTAC) system, which receives its signals from the many SEL relays installed on the system.

COMMUNICATION SYSTEM The communication system is a cost-effective, third-generation or networked architecture. In this example, the main 15kV medium-voltage circuit breaker uses an SEL-351A relay for typical functions such as instantaneous and time overcurrent (50/51) phase and ground. Loop 1 and Loop 2 both use 15kV mediumvoltage circuit breakers with SEL-751A relays for voltage-related elements such as over/under voltage (27/59), negative sequence (47), and sync (25).

Fig. 1: Example of an RTAC System (Source: Schweitzer Engineering Laboratories, Inc.) There are many types of RTAC system configurations (Figure 1). To maintain client confidentiality, the exact system details have been omitted from this discussion. This example merely shows all of the typical systems involved in a SCADA system and is sufficient to convey the complex schemes needed to provide adequate supervisory, control, and data acquisition of an elaborate electrical system.

WHERE IS SCADA USED? SCADA is used to manage any kind of gear. Typically, SCADA systems automate complex processes where human control is impractical — systems where there are more control factors, and more fast-moving control factors, than human beings can comfortably manage (Figure 2). Around the world, SCADA systems control: ●● Electric power generation, transmission, and distribution. Electric utilities use SCADA systems to detect current flow and line voltage, to monitor the operation of circuit breakers, and to take sections of the power grid on or offline. ●● Water and sewage. State and municipal water utilities use SCADA to monitor and regulate water flow, reservoir levels, pipe pressure, and other factors. ●● Buildings, facilities, and environments. Facility managers use SCADA to control HVAC, refrigeration units, lighting, and entry systems. ●● Manufacturing. SCADA systems manage parts lists for justin-time manufacturing, regulate industrial automation and robots, and monitor process and quality control.

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Transformers Vol. 2

●● Mass transit. Transit authorities use SCADA to regulate electricity to subways, trams, and trolley buses; to automate traffic signals for rail systems; to track and locate trains and buses; and to control railroad-crossing gates. ●● Traffic signals. SCADA regulates traffic lights, controls traffic flow, and detects out-of-order signals.

Fig. 3: HMI Example (Source: Schweitzer Engineering Laboratories, Inc.)

TEST DB COMMAND It may be required, as it was in our experience, that all SCADA points are tested and verified on the HMI and GUI. While some of these points are simple to test, others are not and require the use of the test db command, which is embedded within the SEL-351A relays. Below is a modified list of what was required to satisfy the requirements in this project: Fig. 2: Operations Controlled by SCADA Systems (Source: DPS Telecom www.dpstele.com/scada/where-is-used.php)

●● Relay trip ●● 86 trip ●● 50 trip

SECURITY ISSUES

●● 51 trip

It is almost impossible to talk about SCADA these days without mentioning its vulnerability. When you are talking about the United States transportation, water supply, or electrical grid, cyber security against terrorism is a must. Since SCADA sometimes uses Transmission Control Protocol and Internet protocol (TCP/IP), the North American Electrical Reliability Corporation (NERC) and Critical Infrastructure Protection (CIP) have increased security demands on this type of system, resulting in the use of satellite-based communications. The main advantages of satellite-based communications are self-contained protocols, built-in encryption, and no public access to phone lines.

●● Ground trip

The HMI (Figure 3) controls the electrical system while the GUI, also known as a historian, serves as a graphical representation of the system in real-time, displaying events, conditions, and alarms. The HMI allows the user to drill down into the specific parts of the system and actually control that part of the system by opening/closing circuit breakers, resetting relays and alarms, etc.

●● A-phase trip ●● B-phase trip ●● C-phase trip ●● Relay-time sync — normal/fail ●● Relay status — normal/trouble ●● Relay Fail — normal/fail ●● Relay Enable — enabled/disabled ●● Voltage and current for analog metering As evidenced, many of the functions were executed by injecting currents and voltages at appropriate levels with a relay test set. This would trigger the relay word bits to be sent via ethernet to the RTAC and distributed to the HMI and GUI. So, how is relay fail or relay disabled sent on an SEL-351A without tearing out the boards? The answer is the test command. This mode temporarily overrides relay word bits or analog values in the communication interfaces such as DNP. DNP is a set of communication protocols used between components in process automation systems. Its main use is in utilities such as electric and water companies. While not commonly used in other industries, it was used in this system. The actual values used by the relay for protection and control are not

Transformers Vol. 2 changed, but the data or analog value used in the communication interface allows verification of the remote devices to confirm that the proper information from the intelligent electronic devices is received. (IED) To access the test db command, access the relay via hyper-terminal and access the relay at level two. Once granted access, type test db on and press the {Enter} key to enter the test db command mode. From here, sending word bits via ethernet communication is easy; simply enter d for digital or a for analog. The word bit mapped in the DNP can be toggled easily by entering 1 for on and 0 for off. The following is an example of the hyper-terminal string used to toggle the relay-fail status using the word bit stfail: ●● Test db on and press the {Enter} key, which enters the db test mode ●● Test db d stfail 1 and press the {Enter} key, which overrides the word bit stfail on ●● Test db d stfail 0 and press the {Enter} key, which overrides the word bit stfail off ●● Test db off and press the {Enter} key to exit the db test mode and return all overrides to normal While the stfail word bit was set to 1, the HMI and GUI should see whatever word bit is associated with the stfail change state (normal/fail or normal/alarm, etc.) — simple as that. Now, here is the string for analog signals: ●● Test db on and press the {Enter} key. ●● Test db a IA 100 and press the {Enter} key. ●● Test db a IB 150 and press the {Enter} key. ●● Test db a IC 200 and press the {Enter} key. ●● Test db off and press the {Enter} key. Before turning the mode off in the last command string, the HMI and GUI should see 100 amperes (amps) on phase A, 150 amps on phase B, and 200 amps on Phase C. The same can be done for voltage using va, vb, vc, etc. Other uses for the test db command include forcing elements such as 51PT active or toggling a set of bits defined in the relay’s word-bit mapping.

CONCLUSION This test db command mode proved instrumental in satisfying our client's strict requirements. While not widely used, knowing about this mode can prove very helpful in certain situations. It is important to note that not all SEL relays have this mode available. Several other types of SEL relays were attached to this system, which had the same SCADA point requirements. A liability waiver was requested for impending damages to the relays when respective relay boards were removed to activate the HMI and GUI relay disabled or relay fail signals. The client elect-

19 ed to omit these SCADA point verifications from the list. Unfortunately, the specific type of GUI and HMI software used with the specific modeling of the system cannot be disclosed. At any rate, it would just dilute the point of this article, which is to provide another tool in the toolbox — test db command mode — when it comes to commissioning relay SCADA points. Richard Furman earned an Associates of Applied Science of Electronic Engineering Technology from ITT Technical Institute in 1996. Employed at Southwest Energy Systems, LLC since January 14, 2008, Richard is NETA Level 4 Certified. In his current position as Electrical Test Technician/Electrical Specialist, Richard’s responsibilities include the commissioning, acceptance, and maintenance testing of utility generation/distribution substations, data centers, mining sites, and industrial facilities electrical systems. His primary focus for the past five years has been in protective relaying, which includes microprocessor-based, solid-state, and electromechanical relays.

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THE BASIS FOR PERFORMING INSULATION POWER-FACTOR TESTING ON LARGE CAST-COIL TRANSFORMERS NETA World, Fall 2016 Issue Bruce M. Rockwell, American Electrical Testing, Inc. This article discusses the industry basis and value of performing an insulation power-factor test on dry-type transformers, specifically the cast-coil design. The basis for performing this test as outlined in the industry standards is discussed. The value of performing the test based on the transformer application, site conditions, and customer objectives is presented. The intent is to provide insight into when it is prudent to apply insulation power-factor testing to dry-type transformers. The Institute of Electrical and Electronic Engineers (IEEE) publishes a voluntary consensus standard, IEEE Std C57.12.01 (2015), IEEE Standard for General Requirements for Dry-Type Distribution and Power Transformers. This standard was first published in 1979, and its purpose is to provide a basis for establishing performance and interchangeability requirements for dry-type transformers. This standard describes electrical and mechanical requirements of single- and poly-phase as well as ventilated, nonventilated, and sealed dry-type distribution and power transformers or autotransformers with a voltage of 601 volts or higher in the highest voltage winding. This standard applies to all dry-type transformers, including those with solid cast and/or resin-encapsulated windings. Section 8 of the C57.12.01 standard addresses testing. Specifically, paragraph 8.3 addresses routine, design, and other tests for transformers. Dry-type transformer tests are summarized in Table 16. The insulation power-factor test is listed under “other” tests. The standard implies that other tests are those that are specified individually as deemed appropriate. Thus, the standards recognize it is common practice to consider insulation power-factor testing for dry-type transformers. A companion standard to IEEE C57.12.01 is IEEE C57.12.91 (2011), IEEE Standard Test Code for Dry-Type Distribution and Power Transformers. This standard provides information regarding procedures for testing dry-type transformers. It identifies that transformer requirements and specific test criteria are not part of this standard but are contained in appropriate standards such as IEEE C57.12.01 or in other user-developed specifications. Thus, there is some basis that applications vary, and as such, different testing may be applicable for different conditions. Within IEEE Std C57.12.91, the following commentary is noted: While the real significance that can be attached to the insulation power factor of dry-type transformers is still a matter of opin-

ion, experience has shown that insulation power factor is helpful in assessing the probable condition of the insulation when good judgment is used. In interpreting the results of insulation powerfactor test values, the comparative values of tests taken at periodic intervals are useful in identifying potential problems rather than an absolute value of insulation power factor. A factory insulationpower-factor test is of value for comparison with field insulationpower-factor measurements to assess the probable condition of the insulation. It has not been feasible to establish standard insulationpower-factor values for dry-type transformers because experience has indicated that little or no relation exists between insulation power factor and the ability of the transformer to withstand the prescribed dielectric tests. Another factor cited for the inability to establish a standard insulation-power-factor test value is the wide variation in size, type, and quantity of insulating materials used in large drytype transformers. However, practice has proven the value in trending the insulation power factor over time as a predictor of overall insulation quality. Such trend test data is helpful in identifying degradation or verifying insulation quality improvement from drying/cleaning. Such testing is also helpful in identifying potential issues (insulation voids/carbonization) that may not be observed externally. Large (>500 kVA) cast-coil transformers (stand-alone or unit substation types) are generally applied (in lieu of open-wound or encapsulated types) where additional strength and protection is required. These units are intended for harsh environments and/or outdoor applications and are applied for their superior short-circuit strength and short-duration overloads as are typically experienced in industrial process applications. One noted disadvantage when applying or using a cast-coil transformer is that the coefficient of expansion of the epoxy insulation is less than that of the copper (or aluminum) windings. If the transformer is exposed to environmental or operating conditions that create cyclical expansion and contraction by heating and cooling the coils, this can lead to cracking of the cast-coil epoxy-resin insulation over time. General Electric published a service bulletin titled Test Application Data for Secondary Substation Transformers. In this test application guide, the insulation power-factor test is listed as an optional test; however, it is noted that this test is useful for checking the condition of the insulation. This service guide identifies that

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Transformers Vol. 2 comparative measurements made at periodic (i.e., maintenance) intervals are useful in identifying potential problems rather than the absolute test value. Thus, GE is one manufacturer that readily acknowledges the value of using the insulation power-factor test trend data as a maintenance test. The American National Standards Institute (ANSI) publishes the ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, 2015 edition. The ANSI/NETA MTS-2015 test specifications identify the insulation power-factor test as a standard (routine) test. Additionally, the specifications identify an insulation power-factor tip-up test as an option. Industry practice has established the value of performing this additional test when the standard insulation-power-factor test results are suspect. The industry body of knowledge referenced herein provides guidance on transformer testing by considering the type of insulation system: dry-type or liquid-filled. There is some distinction with respect to size. Transformers larger than 500 kVA (threephase) are generally considered significantly more critical to business operations. The standards make no distinction with respect to the test specifications based on the various types of dry-type insulation system designs such as cast coil, resibloc, vacuum-pressure impregnated (VPI), or vacuum-pressure encapsulated (VPE). Industry standards further guide the user toward good engineering judgment and apply reasonable economic justification based on additional factors such as reliability, criticality, environment, and service-aged conditions. Having data on the frequency and magnitude of through-faults experienced by a transformer are criteria that warrant consideration with respect to specifying more or less testing. In facilities and plant sites that have high available fault currents, and in situations where a transformer has been subjected to a through-fault, it is prudent to perform insulation power-factor testing to verify the insulation quality. Doble Engineering Company suggests the following as acceptable, stand-alone insulation-power-factor test values: Ventilated Dry-Type ●● CHL (high-to-low) 2 percent ●● CL (low-to-ground) 4 percent ●● CH (high-to-ground) 3 percent Epoxy Encapsulated Dry-Type ●● CHL 1 percent ●● CL 2 percent ●● CH 3 percent It is important to note that CL power factors as high as 8 percent have been noted in some manufacturers’ transformers, and these

levels may be considered acceptable. Thus, having trend data is very helpful in monitoring/identifying normal and degraded conditions. Literature published by electrical test instrument manufacturer Megger Group Ltd. provides the following insight: “Higher overall power-factor results may be expected on dry-type transformers; however, the majority of test results for PF are found to be below 2.0 percent, but can range up to 10 percent.” The test community universally recognizes applying the insulation power-factor test periodically for maintenance and using the trend-test data to validate the quality of dry-type transformer insulation as an established industry best practice. This practice is also recommended by ANSI/NETA as a routine maintenance test. The insulation power-factor tip-up test is an additional test recognized in the ANSI/NETA MTS-2015 industry standard. This test is performed to further clarify what the insulation power-factor test results may be indicating. When performed, this optional test is useful in evaluating and discriminating whether moisture or corona are present in the insulation system. To perform the tip-up test, the applied test voltage starts at about 1 kV and increases in intervals up to 10 kV or the line-to-ground rating of the winding insulation. If the insulation power-factor does not change as the test voltage is increased, moisture is suspected as a probable cause. If the insulation power-factor increases as the voltage is increased, carbonization of the insulation or ionization in voids is a probable cause.

CONCLUSION It is reasonable to perform the insulation power-factor test on dry-type transformers, including cast-coil designed units. The insulation power-factor test may add two to four hours to the testing scope; thus, it can be significant in the price of the work. It is important to understand how to prioritize the value of this test with customer economic expectations. In some aspects, this is akin to the mindset that transformers only need to be tested on the applied tap setting. However, turnto-turn winding shorts are found often enough to justify testing a transformer on all of its available tap positions, and time added for this testing is minimal. Understanding the value of the test, the added scope/cost, and when it may provide the best value to the customer are all things to consider when specifying testing for drytype cast coil transformers. Bruce Rockwell, P.E. has been Director of American Electrical Testing’s Engineering Division for the last nine years. He has over thirty years of business development, management, construction and engineering experience; specializing in the T&D utility sector. Bruce holds an MBA from Monmouth University and received his BSEE from New Jersey Institute of Technology. Bruce is a Certified Co-Generation Professional with the Association of Energy Engineers and a Continuing Education Instructor for the State of New Jersey.

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QA ELECTRICAL TESTING OF MEDIUMVOLTAGE GLOBAL VPI STATOR WINDINGS PowerTest 2015 Vicki Warren, Iris Power, Toronto, Ontario This research was initially done for presentation at the 2014 Electrical Apparatus Service Association (EASA) Conference in Boston, MA.1

INTRODUCTION If manufactured properly, large squirrel cage medium voltage global VPI stator windings in induction motors (greater than a few hundred horsepower) and synchronous motors typically enjoy 20 years or more of operation. However, if during the motor manufacturing process, the resin did not properly penetrate the tapes, failure may occur in just a few years due to premature aging. Premature failure can also occur as a result of installation errors, such as insufficient spacing or misapplication of surface coatings. [See Table 1] Failure Mechanism

Symptoms

Inadequate bonding

Partial discharge

Electrical slot discharge

Partial discharges, slot discharge, ozone

Semi-con/stress interface

Partial discharge, white powder, ozone

Detection Tests

This paper describes research done by EASA service shops on the effectiveness and practicality of using offline partial discharge combined with a dielectrics characteristic test to evaluate the consolidation of stator windings in medium voltage machines manufactured by GVPI. Advantages and disadvantages of each test and industrial standards will be described as appropriate. Please see the Reference section at the end of this paper for industry standards and recommendations regarding the use of the tests mentioned in this paper.

STATOR WINDING OFF-LINE TESTS For the best test results, the motor should be isolated from the power supply cables. If possible, the winding phases should be tested individually. There are four tests that are recommended by various standards for GVPI insulation systems: capacitance, dissipation factor, power factor, and offline partial discharge.

CAPACITANCE TESTING (EPRI LEMUG) Capacitance, tan ∆ , power factor, tip-up, partial discharge

Table 1: Stator Winding Failure Mechanisms 2 Traditional tests of insulation resistance, polarization index (IEEE 43) and the controlled DC high voltage test (IEEE 95) have been effective in evaluating certain aspects of global vacuum pressure impregnation (GVPI) stator windings; however, they have not proven adequate for determining whether or not the insulation system is well-consolidated. Recently there has been the development of an IEC standard (IEC 60034-27) that defines the test procedures for performing off-line partial discharge testing as part of quality assurance (QA) testing. In addition, globally there has been a move towards using a dielectrics characteristic test, either power factor or dissipation factor, as part of the QA testing for GVPI systems. Partial discharge tests have proven to be effective in locating isolated problems that could lead to failure; whereas, the dielectrics characteristic tests provide a more general condition assessment. Based on experience to date, both are needed to fully evaluate how well the winding is consolidated.

If some of the organic resin is displaced with a void that fills with air this changes the dielectric constant of the insulation system. Caution - the variability in capacitance of newer insulation systems is usually so subtle that unless the winding is severely deteriorated it is difficult to observe any changes. The capacitance can be measured at a low voltage and best done with a bridge that will eliminate the effect of the stray capacitance of the test supply. As the winding cures, there will likely be a notable decrease in the capacitance as the polarizing and conductive currents decrease. This decrease will be observable independent of changes in voltage, that is, across all voltage steps the capacitance should be lower.11 A variation on the capacitance test is the capacitance tip-up test, which is performed on complete windings or preferably individual winding phases, and measures the void content in the groundwall of the stator coils. Measurements shall be taken at 20% of the motor rated line-to-ground voltage (0.2E) and at the motor rated line-to ground voltage (1E).8 The tip-up is based on the fact that line-to-ground voltage, if there are voids in the groundwall insulation, the gas in the void ionizes to produce sufficiently high conductivity to short the void out. This reduces the effective thickness of the insulation producing an increase in capacitance between low and high line-to-ground

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Transformers Vol. 2 voltage. One void would have no impact, but if there are excessive voids due to the inadequate resin impregnation or problems with the tape or bonding material in the insulation system, the change in capacitance would be noticeable.11 Normally this test is performed on each phase of a winding, when practical, with an accurate capacitance bridge. The capacitance Clv is measured at 0.2E where E is the rated line-to-ground voltage and Chv is measured at line to ground voltage which is 1E. The capacitance at low voltage is the capacitance of the insulation with the gaps of the voids; whereas, as at the higher voltage the voids have been shorted, so it is the capacitance of the insulation alone without gaps, which mean a smaller effective distance between the plates. Therefore, an increase in capacitance with voltage is an indication of internal voids. In the absence of voids, the capacitance will not change as the test voltage is increased. The capacitance tip-up is defined as:

DISSIPATION FACTOR (TAN ∆ )

(NEMA MG-1, IEEE 286, EPRI LEMUG, IEEE 56) Like the capacitance test, the dissipation factor (tan Δ) test also looks for any changes in the insulation system of the winding. When a 60-hertz voltage is impressed across the stator insulation, the total current that flows is similar to that of any capacitor. The total current has two components: a relatively large capacitive current (ic), which leads the voltage by 90°, and a smaller resistive current (ir) which is in phase with the voltage. In a perfect insulation system, there would be no resistive current (ir), as all of the current would be capacitive (ic). However, as with the capacitance test, if there are voids, then the dielectric characteristics of the insulation system will change. The dielectric of this simulated capacitor is the insulation system which is embedded between two electrodes: the high-voltage copper conductors and the stator iron core. The dissipation factor is the tangent of δ, the angle between the ir and ic, or the angle between the capacitive current and the total current (Figure 2).3

Δ

Fig. 1: Change of ∆C as a function of the relative volume of voids within the epoxy resin specimen 11 ΔC = (Chv – Clv)/Clv Uncured/moisture contamination ⇒Clv is high Delamination ⇒ ΔC increases with voltage The higher ΔC is, the more voids there are in the winding groundwall. Note that as shown in Figure 1, as the void volume increases, so does the ΔC percentage. For well bonded modern epoxy mica groundwall insulation, typically the ΔC is less than about 1%.8 It should be noted that if the coils have semi-conducting and grading voltage stress control layers, these influence the results of this test. At the higher voltage, the grading layers of silicon carbide material conduct to increase the effective surface area and thus the capacitance of the sections of winding being tested, and so may give a false indication of high void content. However, if the results are trended against time, an increase in ΔC may give a true indication of increased void content in the groundwall insulation.11

Fig. 2: Dielectric of a winding This test is normally done at voltage steps that increase from 0.2E (DFlow) to normal line-to-ground voltage, 1E (DFhigh), preferably on individual phases. The intention of the test is to observe the increase in real power loss due to the presence of voids in a delaminated insulation (Δ tan δ = DFhigh – DFlow). As with the capacitance test, increases as a function of voltage are due to partial discharge and the ionization of the gas in the voids of the insulation system.11 As the applied test voltage increases so will the partial discharge activity in the voids and thus an increase in resistive current (ir) or real power loss. The absolute value of the dissipation factor is also useful in determining the extent of curing in a new insulation system since uncured components have different dielectric characteristics from cured components. DF = tan δ = IR / IC Uncured/moisture ⇒ DFlow is high Delamination ⇒ Δ tan δ increases with voltage

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Transformers Vol. 2

Typically, the DFlow for epoxy mica windings is about 1 - 2% and the Δ tan δ is less than 1%. Trending the results against time makes the best use of this test. As with the Δ capacitance test, voltage stress coatings can lead to ambiguous results obtained at high voltage.8

POWER FACTOR (COS θ)

(NEMA MG-1, IEEE 56, EPRI LEMUG) Similar to the dissipation factor (tan δ) the power factor test is looking for any changes in the insulation system of the winding. The power factor is the cosine of θ, the angle between the applied voltage and the total current (Figure 2). The test is normally done at a specific applied voltage that makes it possible for comparing the results to other machines, 0.2E. This is a valuable test for determining the extent of curing in new coils or winding. Because the presence of the voltage stress control in a complete winding greatly affects the results, tests on complete windings can be ambiguous.3 The tip-up test (Δ cos θ) is done at two voltages, one below the inception of partial discharge activity (PDIV), 20% of lineto-ground voltage, 0.2E (PFlow), and one at 100% line-to-ground voltage, 1E (PFhigh), preferably on individual phases. As with the Δ tan δ test, the difference in the power factors at these two voltages can be attributed to the energy loss due to partial discharges. PF = cos θ = mW / mVA Uncured/moisture ⇒ PFlow is high Delamination ⇒ Δ cos θ increases with voltage Typically, the PFlow for epoxy mica windings is less than about 0.5% and the Δ cos θ is 0.5%, though many suggest the acceptance levels should be the same as for dissipation factor, that is, 1-2% for 0.2E values and 1% for tip-up. As with the capacitance tip-up test, the results of this test are influenced by the presence of voltage stress coatings on the coils, since at high line-to-ground voltage currents flow through it to produce additional power losses. Because this test method measures total energy it is only sensitive to how widespread the PD is and not how close the winding is to failure (worst spot).

OFF-LINE PARTIAL DISCHARGE TEST (IEEE 1434-2000, IEEE 56-2012, IEC 60034-27-2 and EPRI LEMUG)

Partial discharges (PD) are small electrical sparks which occur in stator windings rated 3.3 kV or higher. PD is non-existent or negligible in well-made stator windings that are in good condition. However, if the stator winding insulation system was poorly made, then PD will occur. A PD test directly measures the pulse currents resulting from PD within a winding. Each PD produces a current pulse that has high frequency components to the hundreds of megahertz. Any device sensitive to high frequencies can detect the PD pulse currents. In a PD test on complete windings, the most common means of detecting the PD

currents is to use a high voltage capacitor connected to the stator terminal. Typical capacitances are 80 to 1000 pF. The capacitor is high impedance to the high AC current in the stator, while being very low impedance to the high frequency PD pulse currents. The output of the high voltage capacitor drives a resistive load. The PD pulse current that passes through the capacitor will create a voltage pulse across the resistor, which can be displayed on an oscilloscope, frequency spectrum analyzer, or other display device. The key measurement in a PD test is the peak PD magnitude Qm, i.e. the magnitude of the highest PD pulse, since this is proportional to the largest defect in the stator insulation. Tests are usually taken at increasing voltage steps starting at 0.2E to line-to-ground voltage (1E), preferably on individual phases. Measurements include:7, 10 ●● the voltage at which partial discharge starts, or the inception voltage (PDIV), ●● the voltage at which partial discharge stops, or the extinction voltage (PDEV), and ●● the largest repeatedly occurring PD magnitude at rated voltage Both the PDIV and the PDEV should be above 50% of line-toground voltage, or higher than 0.5E.8, 9

CASE STUDIES Using these tests and acceptance values, several motors were tested at various stages. Tests were done using two different sets of test instruments: ●● Using a PDTech DeltaMaxx™ to measure capacitance, dissipation factor and partial discharge ●● Using a Biddle® power factor/capacitance test instrument along with an Iris Power HF/LF partial discharge test Please be advised that when testing partial discharge, the measuring bandwidth of the test configuration influences results, so standard acceptance values for PD magnitudes are not possible. However, comparison among results using a similar test configuration is possible.

Case Study 1: Coil Resin Impregnation 4kV A single coil 4kV was tested at various stages of the resin impregnation process from before (green) to partial to full impregnation.

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Transformers Vol. 2

●● PDIV: the PDIV was higher than standard recommendation of 0.5E ●● PD max: there is no standard; however, the patterns were typical of internal voids and elevated when compared to the PD instrument manufacturers database.

Case Study 3: Rewound Winding 4kV A 4kV winding tested “as-is” state before a rewind and then after the rewind. Fully penetrated

In the table above, the pink refers to values that would be of great concern, while the yellow values are marginally acceptable and the green values are within expected limits. ●● Dissipation Factor (DF): decreases to between 0.01 and 0.02 as the quantity of resin is increased. The slightly elevated tip-up may be an issue. ●● Capacitance Tip-Up: since this is primarily testing for curing, then it makes sense that the partial (wet) state would have the highest activity along with the elevated DF values. Note that after full impregnation and curing, the values were significantly less than 1%. The increase in capacitance at 0.2E is unusual (see PD Max below). ●● PDIV: in all cases the PDIV was higher than standard recommendation of 0.5E ●● PD max: this was puzzling in that the magnitude of the measurable PD increased with impregnation. It is hypothesized that before resin impregnation the voids were too large to have detectable PD, so the effective thickness of the groundwall was minimal. Void shape and pattern as shown below are typical for small internal voids with the clusters within the first and third quadrants of the AC cycle as shown.

●● Dissipation Factor (DF): decreases after rewinding to levels almost between 0.01 and 0.02; while the tip-up decreases as well it is still slightly higher than the standard recommendation of less than 1%. ●● Capacitance: Behaved as expected with the lower capacitance in the rewound motor and a tip-up less than 1%. ●● PDIV: in all cases the PDIV was higher than standard recommendation of 0.5E ●● PD max: the decrease in PD activity is expected in a new winding with minimal PD activity.

Before

After

Case Study 4: Reconditioned Winding 12kv A 12.5kV winding was tested before and after reconditioning.

Case Study 2: Reconditioned Winding 4kV A reconditioned 4kV motor was tested.

●● Power Factor (PF): was within range ●● Power Factor Tip-up: was outside of standard recommendation of 0.5% which suggests moderate internal voids ●● Capacitance tip-up: was within range

●● Dissipation Factor (DF): decreases after reconditioning to levels between 0.01 and 0.02. ●● DF Tip-up: both before and after the DF tip-up were above the standard recommendation which suggests noticeable internal voids supported by the low PDEV.

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Transformers Vol. 2

●● Capacitance: Behaved as expected with minimal change in the values, but still elevated tip-up values suggesting internal voids. ●● PDIV/PDEV: after reconditioning the PDIV was higher than the standard recommendation of 0.5E; however, the PDEV though better was still lower that acceptable by standard ●● PD max: the decrease in PD activity is likely due to the cleaning and re-varnishing that reduced surface PD activity. The PD patterns are classic and considered very high from the PD instrument manufacturer.

Before

REFERENCES 1

“ Condition Assessment of Stator Windings in Medium Voltage GVPI Machines”, Electrical Apparatus Service Association (EASA) Conference, Boston, MA, 2014.

2

 .C. Stone et al, “Electrical Insulation for Rotating Machines: G design, evaluation, aging, testing and repair”, IEEE Press-Wiley, 2004

3

 uarte, E. “Power Factor Testing of Stator Winding InsulaD tion” http://www.vbook.pub.com/doc/83509152/Power-FactorTesting-of-Stator-Winding-Insulation (cited 9 April 2014)

4

 EMA Standard Publication No. MG 1-2006 Motors and GenN erators

5

ANSI Std. C50 41-1982, American National Standard for Polyphase Induction Motors for Power Generating Stations

6

IEEE 286-2000 Recommended Practice for Measurement of Power-Factor Tip-Up of Rotating Machinery Stator Coil Insulation

7

IEEE P1434-2010, Guide to the Measurement of Partial Discharges in Rotating Machinery

8

 PRI LEMUG Report 1000897 (Dec. 2000) Repair and ReE conditioning Specification for AC Squirrel-Cage Motors with Voltage Ratings of 2.3 - 13.2 kV.

9

IEEE 56-2012 (Draft) Guide for Insulation Maintenance of Large Alternating-Current Rotating Machinery (10,000 kVA and Larger)

After

PD tests using the same test configuration were taken while the machine was off-line and on-line. The results show activity originating around the zero crossings of the line-to-ground cycle with a “rabbit ears” pattern. PD of this magnitude and pattern are indicative of deterioration of the voltage stress coatings, and as such would not be “fixed” with cleaning and re-varnishing.

Off-Line

On-Line

SUMMARY Though it is premature to establish acceptance criteria for the capacitance results at 0.2E or the PD Max values at 1E, it is obvious based on these case studies that these five (5) tests in combination provide valuable information about the quality of a GVPI insulation system before and after refurbishment or rewind. Each test evaluates a different aspect of the insulation, so it requires all five for a full evaluation: ●● DF or PF at 0.2E – curing state (<0.01 - 0.02) ●● DF/PF tip-up – widespread voids (< ~1%) ●● Capacitance at 0.2E – curing state ●● Capacitance tip-up – widespread voids (<1%) ●● PD – isolated problems ●● PDIV/PDEV (< 0.5E) ●● PD magnitudes (depends on test)

10

I EC/TS 60034-27-2 Rotating electrical machines - Part 27-2: On-line partial discharge measurements on the stator winding insulation of rotating electrical machines

11

Farahani, Mohsen, et al. “Study of capacitance and dissipation factor tip-up to evaluate the condition of insulating systems for high voltage rotating machines” Electr Eng (2007) 89:263-270.

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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Transformers Vol. 2

LIFE AND DEATH OF A TRANSFORMER PowerTest 2015 Keith Burgess, Senior Utility Consultant Shermco Industries Canada

ABSTRACT

DISSOLVE GAS ANALYSIS

The purpose of this paper is to outline two distinct faults on the same transformer. ●● The transformer suffered a short circuit on X3 winding. ●● The transformer suffered an open circuit on X2 winding.

The paper will evaluate the test results, showcase the tear down of the transformer and compare test results of the short circuit compared to the open circuit. SHORT CIRCUIT WINDING A new transformer was installed for our client in 2012. Transformer was a Pacific Crest Transformer built in 2012.

Table 1: Dissolve gas limits

Limits Hydrogen Methane Carbon Monoxide Acetylene Ethylene Ethane Fig. 1: Nameplate Transformer was showing signs of a problem with dissolve gas analysis. The Hydrogen and Methane values were rising. These are key gases associated with Partial Discharge. The Partial Discharge Test was performed with no significant values.

100 120 350 35 50 65

Table 2: Dissolve gas limits These are the minimum values used for determination of key gases.

On November 2nd, 2012 a cable fault occurred on the low side bus connected to the transformer. This led to the decision to further test the transformer to evaluate the health.

Table 3: Transformer Duval Triangle

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Transformers Vol. 2

The last sample was taken after the fault. There was no significant rise in gases after the fault. It can be observed through the analysis the reason why it was determined the transformer was likely to fail.

TESTING PERFORMED The tests performed were the Doble Power Factor, Excitation, Leakage Reactance, Ratio, SFRA and DC Resistance. The test results for excitation and SFRA changed all others showed no significant difference.

Table 4: Excitation results

Fig. 2: SFRA high voltage winding figure short circuit tests Notice no difference in High Voltage short circuit tests.

Fig. 4: SFRA low voltage winding open circuit tests

Table 5: DC resistance Notice minimal difference in resistance values. The manufacture and our company agreed that the transformer should be sent back to manufacture facility for further investigation. A temporary replacement was installed to allow the client back in production.

MANUFACTURE TEARDOWN When the transformer arrived at the factory, it was energized at rated voltage with no load. Shortly after the transformer was energized it failed.

Fig. 3: SFRA high voltage winding open circuit tests

Fig. 5: After transformer failed

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Transformers Vol. 2

Fig. 6: HV conductor

Fig. 10: LV layer 4

CONCLUSION OF SHORT CIRCUIT WINDING It is fair to conclude that a major failure was adverted by using all the tools available to assess the health of the transformer. This shows the benefits of thoroughly testing a transformer during an investigation. Transformer was completely rewound and commissioned into service again on March 13/2013.

OPEN CIRCUIT WINDING

Fig. 7: Shield removal

On March 10/2014 there was a fault on the load side bus which tripped load side breaker. About two minutes later the high side fuses went on the transformer. The transformer faulted due to an internal open circuit.

Fig. 8: LV layer 2

Fig.11: Substation drawing

TESTING PERFORMED After the fault tests were performed to show health of the transformer. Doble Power Factor and Excitation could not be performed because the test set would trip. Leakage Reactance, Ratio, SFRA and DC Resistance all showed issue with X2 winding. Fig. 9: LV layer 3

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Transformers Vol. 2

Current

Voltage

Reactance

Resistance

H3 - H1

1.547

285.186

160.007

90.879

H1 - H2

0.653

290.410

312.813

312.565

H2 - H3

1.570

286.110

158.300

89.251

Phase

Amps

Volts

Ohms

Ohms

Table 6: Leakage reactance

H to X Tap Position

High Side Volts L-L

Low Side Volts L-L

Calc. Ratio

H1-H3

H2-H1

H3-H2

1

Fig. 13: SFRA low voltage winding open circuit tests

2 3

72000

4160

29.98

30.012

61.891

30.052

4

MANUFACTURE TEARDOWN

5

The transformer was removed from tank. The middle winding was removed from core and unwound for verification of problem.

Table 7: Transformer ratio

H3 - H1

H1 - H2

H2 - H3

2.81

2.81

2.8

X1 - X0 mOhms

X2 - X0 Ohms

X3 - X0 mOhms

4.021

1.758

4.026

Ohms

After Fault

After Fault

The transformer clearly has fault on low side of X2 winding transformer was sent back to factory for teardown.

Ohms

Ohms

Table 8: DC resistance

Fig. 14: Winding removed from core

Fig. 12: SFRA high voltage winding open circuit tests Fig. 15: High side winding

Transformers Vol. 2

Fig. 16: Low side winding

COMPARING SHORT CIRCUIT AND OPEN CIRCUIT RESULTS We can clearly see the difference in test results between the two different faults. Since SFRA is new tool in our tool box let us see the difference between a short and open circuit graph on the low and high side of transformer.

Fig. 17: SFRA low voltage winding

Fig. 18: SFRA high voltage winding Keith Burgess has been employed at Shermco Industries in Regina, Saskatchewan, Canada since 2012. Before that he was employed by SaskPower starting in 1981, working in testing field since 1985. He received a diploma in Electrical Engineering Technology from Saskatchewan Technical Institute in Moose Jaw, Saskatchewan in 1984.

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Transformers Vol. 2

BUSHINGS THAT BITE – WHAT YOU DON’T KNOW CAN HURT YOU! PowerTest 2015 Tony McGrail, Doble Engineering

INTRODUCTION Bushings are generally well tempered and well behaved, but occasionally their behavior deteriorates and the consequences can be unpleasant. A bushing is a device that allows a conductor to pass through a barrier which is usually grounded; the bushing has an insulating medium, which must be sustained to prevent the passage of excess current to ground. Bushings are like the tires on your car: they enable the car to do what it is supposed to do, but they are not the reason why you buy the car - they are enablers, and when they fail the results can be catastrophic. Generally, bushings have a low failure rate, less than 1% a year while in service. Some individual designs may be more prone to failure; some less. Managing the population through a combination of off-line testing and targeted on-line condition monitoring can reduce both failure rates and risk.

BUSHING CONSTRUCTION Bushings are not perfect and do allow a current to flow through the insulating medium to ground – the bushing leakage current. By measuring these currents we can learn much about the state of the bushing insulation and its "fitness for function".

As insulation deteriorates there is a change in bushing leakage current – usually a rise. In an ideal world, each of three bushings in a three phase set would have identical sinusoidal leakage currents, driven by the system voltage, and with 120o phase difference: the theoretical instantaneous sum of three such sinusoids is zero. In practice this rarely happens due to variation in bushings, system voltage and ambient conditions.

OFF-LINE TESTING In off-line testing, with the transformer out of service, we may apply a controlled voltage to the bushing conductor and measure the leakage current through the bushing insulation. These allow us to determine the capacitances, C1 and C2, and power factor of the bushing insulation. Guidelines exist for the acceptable range of these values: it is often asserted that when C1 reaches more than 1% or double the original value, a bushing should be changed out as the deterioration is such that failure is imminent. A review of reported Doble power factor testing data in 2013, for over 65,000 individual bushing C1 values, showed that approximately 1% were in a deteriorated condition requiring replacement. Many of these bushings cannot be replaced immediately and must be risk managed until such time as a replacement is possible. This is where condition monitoring plays a role in an asset management framework. First we need to understand bushing failure modes, and then the consequent risk.

ON-LINE CONDITION MONITORING The motivation for applying condition monitoring is to learn about the status of the bushings between off line tests. Where a bushing is known to be in a poor condition, or where a bushing is one of a population which is known to have a higher failure rate, condition monitoring allows for management of the bushings and the population. Fig. 1: Construction of a bushing Figure 1 gives an example construction for a paper insulated bushing, with stress grading foils to even out the electrical stress on the insulation. There is usually a "test tap" at the bushing flange to measure leakage current and test the bushing; the capacitance between the conductor and the test tap is usually referred to as C1, while that between the test tap and ground is C2.

Additional information about insulation performance and how that insulation is degrading over time is key to making informed decisions about the bushings. There are several parameters which can be measured – Infra Red scans may show localized overheating; visual inspections may show oil deterioration. Direct measurement of the leakage current is the most direct way of monitoring bushing insulation: usually on a set of three bushings to give relative phase information, but individual bushings may also be monitored.

33

Transformers Vol. 2 Additional information may also be useful: the system voltage varies and causes variation in leakage current. If we can get the actual system voltage on each bushing that can be used to derive a more precise power factor or capacitance values. It must be noted that we may still be very inaccurate in these values unless we have microsecond or better time stamps on both current and voltage measurements so as to allow accurate results. Integrating all available data helps identify failure modes which are in progress, and likely timescales requiring action.

The tip-up is based on the fact that line-to-ground voltage, if there are voids in the groundwall insulation, the gas in the void ionizes to produce sufficiently high conductivity to short the void.

A monitor is not just a ‘box with lights on’ but a device to give us warning of incipient bushing deterioration. Consequently, we need to have a plan in place to address any variation in results: where a monitor – and this applies to any condition monitoring device – has default or user set values for notifications, a plan should be in place and agreed by relevant parties before any notifications are ever given. Working out what to do after an alarm is received is always more difficult. We do not have perfect knowledge of all causes of possible variation in measured parameters. Consequently, there is a possibility of false positives being generated. Dealing with the likelihood of false positives is an asset management requirement, making sure that the value of the monitor is achieved.

BUSHING FAILURE MODES How quickly might a bushing deteriorate? We have applied bushing condition monitoring to several thousand bushings and have found that there are generally two types of bushing failure mode: graceful and rapid onset. Graceful failures are ones which give plenty of warning of impending bushing failure – possibly weeks to months of advance warning so replacement bushings can be identified and strategically placed to be used at an opportune moment before failure occurs. Rapid onset failures occur such that the measured parameters give only a few hours’ notice. We have found such variations in different bushing types, and have seen bushings taken out of service ‘just in time’ saving a multi-million dollar transformer as a result (1). It is possible to have a graceful failure mode, indicating an incipient deterioration, which turns into a rapid onset failure mode. In Figure 2 we see the leakage current magnitude for one phase increasing gradually over a period of several months, only to rise dramatically in a period of a few hours. This bushing was removed from service in a controlled manner and replaced. A variation on the capacitance test is the capacitance tip-up test, which is performed on complete windings or preferably individual winding phases, and measures the void content in the groundwall of the stator coils. Measurements shall be taken at 20% of the motor rated line-to-ground voltage (0.2E) and at the motor rated lineto ground voltage (1E).8

Fig. 2: Variation in leakage current magnitude for a deteriorating bushing For the bushing in Figure 2, off line testing confirmed the results and subsequent forensic tear down showed the deteriorated insulation. This would have likely led to a catastrophic failure on a GSU transformer (2).

CONCLUSIONS: WHAT MAKES SENSE? Applying condition monitoring to bushings can bring great value – failures prevented and transformers saved. The key is to target those bushings where a benefit may be achieved, and then link measured parameters through to failure modes and consequence. By applying monitoring with appropriate notifications, each with a timescale and action, value can be gained. Integrating available data may increase value, if that data is of sufficient quality to improve the diagnoses. Tony McGrail is the Doble Engineering Solutions Director: Asset management and Monitoring Technology. His role includes providing condition, criticality, and risk analysis for utility companies. Previously Tony has spent over 10 years with National Grid in the UK and the US. He has been both a substation equipment specialist and has also taken on the role of substation asset manager and distribution asset manager. Tony is a Fellow of IET, a member of IEEE, ASTM, CIGRE and the IAM, and is currently on the executive of the Doble Client Committee on Asset and Maintenance Management. His initial degree was in physics. He has an MS and a PhD in EE and an MBA. Tony is an Adjunct Professor at Worcester Polytechnic Institute, Massachusetts, leading courses in power systems analysis.

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Transformers Vol. 2

SWEEP FREQUENCY RESPONSE ANALYSIS WHY IT SHOULD BE IN YOUR DIAGNOSTIC TOOLBOX PowerTest 2015 Keith Hill, Doble Engineering Company In the last several years Sweep Frequency Response Analysis (SFRA) has evolved from tests that were once performed only by a handful of highly specialized personnel to a test that has become recognized as a valuable tool to power personnel around the world. SFRA tests have proven to be a powerful and sensitive tool to evaluate the mechanical integrity of core, windings and clamping structures within power transformers by measuring their electrical transfer functions over a wide frequency range.” The theory of using Frequency Response Analysis has been around for decades but only became “commercial” in the 1990’s. Frequency response analysis, better known as FRA, came about by two Polish physics, (Lech & Tyminski in 1966) as a by-product of low voltage (LV) impulse test and since then has thrived as an advance non-destructed test for detecting mechanical faults of transformer windings. One of the first papers on using FRA was presented in 1976 at the International Conference of Doble Clients by Mr. A. G. Richenbacker, Pennsylvania Power and Light, “Frequency Domain Analysis of Responses from Low Voltage Impulse Testing of Power Transformers”. It is interesting to note that in this paper Mr. Richenbacker stated that these first tests were performed using a Hewlett-Packard 9830 programmable calculator with a peripheral digitizer. In the last 15 – 20 years, several companies have developed various models of FRA test equipment and software which is often times very user friendly. Personnel performing these tests should be aware that SFRA is used to evaluate the mechanical aspects of a transformer and does not indicate the overall insulation of the unit being tested. It is possible for a transformer to have acceptable tests such as power factor and low voltage turns ratio and still have a mechanical problem that can result in a failure if placed into service. SFRA tests have identified displacement and deformation of windings, core defamation, magnetized core, shorted turns and other mechanical conditions that may affect the safe and reliable operation of the transformer being tested. These problems can be caused by mechanical failure when a fault occurs or by damages incurred during shipping. It is advised that SFRA tests should be performed on a new unit before leaving the factory so that the signature can be compared to tests that may be performed during shipping and once arrival on site has taken place. One large Texas utility has a very aggressive program in place that requires SFRA testing at various stages of shipping. SFRA tests are performed at the factory and again when

the transformer(s) arrives at The Port of Houston. The factory tests and shipping tests are then compared by their diagnostics testers to make sure that damage did not occur during ocean transport. The transformer is then loaded onto a rail car with SFRA tests being performed once the rail car arrives at their site. This may appear to be “over kill” to some companies, but when you have a four million dollar transformer that arrives with shipping damage you have a signature for each transfer of “ownership”. Performing multiple tests and having these signatures allows the owner to pinpoint when the damage occurred and which shipper may be at fault for the damages. Interpretation of the data can be challenging, if not impossible for the novice user if baseline data is not available. Performing the tests is less challenging, as the setup and connections for a SFRA test are rather simple (Figure 1). Various templates are often part of the software from the test equipment manufacturer which guides the tester to the proper connections required to perform the various tests for different transformers. The connections are straight forward; however, improper connections and grounding may affect the accuracy of the test results.

SFRA test set

Fig. 1: Typical setup for a three lead system SFRA is another tool in the diagnostic’s toolbox (Figure 2) that provides the tester or the owner of the transformer additional data that is often critical when having to make an informed decision on what steps should be taken on placing a transformer into service. This decision is often based after the data from various tests are analyzed and compared to previous tests or tests on identical equipment. It may be advised to perform DGA, excitation current tests, leakage reactance, and power factor when investigation a possible problem with a transformer. Performing a Transformer Turns Ra-

35

Transformers Vol. 2 tio (TTR) at a higher voltage will sometimes reveal a problem that a low voltage TTR did not identify as demonstrated in Case Study 1. SFRA data did confirm the excitation and volatge ratio tests. Z=2ΠfL

Fig. 4: Response of a inductor

Fig. 2: Diagnostic’s toolbox Inductive roll off

0 dB down at low frequency means it

COMPONENT CHARACTERISTICS looks like a dead short There are three basic components in a transformer: ●● resistors

0 dB down at low frequency means it 0 dB down at low frequency means it looks like a dead short looks like a dead short

●● capacitors ●● inductors Each component has a different response to an AC signal, with its response being closely related to it's geometry; both internal and in relation to other components. The impedance of the three components is shown in Figure 3.

Inductive roll off Inductive roll off

Larger inductances start to roll off at lower frequencies Larger inductances start to roll off at Larger inductances start to roll off at lower frequencies lower frequencies

Resistor

Fig. 5: Response of an ideal inductor

The resistance of a resistor (Figure 3) is not frequency dependent as the resistance will remain the same with a change in frequency. There will be a straight line from a low frequency to a higher frequency.

Capacitor A capacitor will be the opposite of an inductor as the capacitance will increase with an increase in frequency. Response of an ideal capacitor: Figures 6 & 7- Page 36). ●● Low frequency means it looks like an open circuit ●● 0 dB down at high frequency like a dead short ●● "Knee" point depends on size of capacitor’

Fig. 3: Response of a resistor

Z =1√ 2Π F C

Inductor At a low frequency, the inductor will act as a short and the inductance will increase as the frequency increases. Response of an ideal inductor: Figures 4 and 5: ●● 0 dB down at low frequency means it looks like a dead short ●● Larger inductances start to roll off at lower frequencies

Fig. 6: Response of a capacitor

36

Transformers Vol. 2

Knee point depends Knee point depends on on thethe of the capacitor sizesize of the capacitor Knee point depends on the Knee point depends on the size of the capacitor size of the capacitor

0 dB down at high frequency 0 dB down at high frequency a dead short likelike a dead short 0 dB down at high frequency 0 dB down at high frequency like a dead short like a dead short

frequency response LowLow frequency response is is an open circuit likelike an open circuit Low frequency response is sponse is like an open circuit it

Impedance of the parallel RLC Circuit

Capacitive climb back Capacitive climb back Capacitive climb back Capacitive climb back

Fig. 7: Response of a ideal capacitor A real transformer has many inductances and capacitances, (Figure 8), which can result in numerous resonant frequencies when performing a SFRA test as each LC pair has its own resonant.

Fig. 9: Response of the parallel RLC circuit

TEST SETUP Once the nameplate data and templates have been selected the tester must make the connections. The tester must remember that signatures can be affected by some of the followings: ●● The first resonance frequency can be affected if the transformer is tested with insulating fluid and without insulating). Removing oil lowers capacitances and resonances shift to higher frequencies (Figures 10 and 11). ●● A magnetized core can affect the signatures (Figure 12). Fig. 8 Constant dBs down v. frequency

Dead short at low frequency

Open circuit at high frequency

Open circuit at low frequency

Dead short at high frequency

Parallel RCL circuit

●● How the neutral position of the Load Tap Changer (LTC) was reached as there have been cases in which reaching neutral position from the raise or from the lower taps affected the signatures. ●● If LTC or DETC are not on neutral, the signatures can change. ●● Test on 16R if only one test is being performed. ●● Shorting of the secondary windings for the short circuit test can be affected if the secondary windings are not “closed” It is recommended to jumper X1 – X2, X2 – X3 and X3 – X1 thus closing the delta or wye windings. ●● Make sure that the transformer being tested is grounded. ●● Make sure that the test leads grounds are properly terminated.

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Transformers Vol. 2 INTERPRETATION OF SIGNATURES

With Oil Lower resonant frequencies

Without Oil

Higher resonant frequencies

Fig. 10: Wye connected - with oil and without oil

Most users of power factor equipment are aware that the power factor test is a reference test and allows the user to compare results to past tests and also to tests results of identical equipment. If “benchmark” power factors or watts loss limits have not been established it can often be difficult to determine the condition of the apparatus being tested. This is true for SFRA test results as the signatures before and after an event can often help to identify a problem. The frequency range in which the changes take place will assist the tester in determining what component or components have changed since the benchmark tests were performed. This signature can often be used as a tool in determining if the transformer can be returned to service. If a thru fault occurs the windings may be deformed but may be suitable to be placed back into service. The ability to sustain additional faults may have been compromised, but the analysis of the data may allow for the decision to return to service. Dr. Tony McGrail, Doble Engineering Company, has used the signatures of a single phase transformer, (Figure 13), to point out that the “transformer was bent - but not broken”. This transformer was returned to service for several months until a replacement could be located. Once the unit was removed from service the inspection of the windings revealed winding defamation that is classified as “hoop buckling” as seen in Figure 14 photograph.

With Oil Without Oil

Fig. 11: Delta connected - with oil and without oil This phase appears to have symptoms of hoop buckling

Fig. 13: Signature

Fig. 12: Magnetized core

Suspect unit shows same increased impedance (more dB’s down) for one phase - the same one with the shift left on open circuit results.

In figure 12, the same phase was tested on arrival at site. The low frequency responses show offset due to core magnetization while the high frequency responses are unchanged. Often times a magnetized core can be detected by performing excitation current tests. Several manufacturers have winding resistance test sets that have the ability to de-magnetize the core. It is recommended to demagnetize and repeat the test to confirm that the core was magnetized and is the reason for the shift.

Fig. 14: Hoop buckling

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Transformers Vol. 2

The following four zones (Figure 15) are utilized by one equipment manufacturer for the analysis of SFRA results. ●● Region 1: <10kHz: Core deformation, open circuits, shorted turns, residual mag. ●● Region 2: 10kHz to 150kHz: Bulk Winding movement relative to each other. ●● Region 3: 150 - 400kHz: Deformation within main and tap windings. ●● Region 4: 400kHz - 2MHz Movement of main and tap winding leads. Fig. 17: Wye – Wye – high voltage - open circuit test

Fig. 15: Response zones

EXAMPLES OF TYPICAL TRACES

Fig. 18: Wye –Wye low voltage - open circuit

Figure 16 is a typical signature for open circuit and short circuit tests on Wye connected windings. The core is removed from the test when the secondary winding is short circuited. This results in a lower impedance as the signature starts at “zero”. When the secondary is “open circuited” the signature will have a higher dB.

Short circuit

Fig. 19: Wye – Wye high voltage – low voltage windings shorted

Open circuit T

s

h

y

i

m

s

p

p

h

t

o

a

m

s

e

s

a

o

p

f

p

h

e

o

a

o

r

s

p

t

b

o

h

u

c

a

k

v

l

e

i

n

g

Fig. 16: High voltage winding short circuit and open circuit

Fig. 20: Delta – Wye – high voltage - open circuit test

39

Transformers Vol. 2

Fig. 21: Delta – Wye – low voltage - open circuit test

Fig. 25: Auto transformer – tertiary – open circuit

16 Lower

8 Lower

Fig. 22: Delta – Wye - high voltage – low voltage windings shorted

Fig. 26: Variation with Load Tap Changer (LTC)

Tap 18

8 Lower

Fig. 27: Variation with Load Tap Changer (LTC) Fig. 23: Auto transformer – high voltage – open circuit

Tap Position E

Tap Position A

Fig. 28: Variation with De-Energized Tap Changer (DETC) Fig. 24: Auto transformer – low voltage – open circuit

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Transformers Vol. 2

One Winding – Neutral from raise and lower

Fig. 29: Variation with reversing switch Case Study Fig. 2: Shorted turn As demonstrated in Case Study Figure2, one phase has clear inductive roll off associated with short circuit measurements. Case Study Figure 3 is a photograph of the shorted turn in the windings.

Fig. 30: Effect of poor grounding

ANALYSIS OF DATA Transformer 1

Case Study Fig. 4: Shorted turn

Transformer 2 Normal test results for the power factor (Case Study Figure 5), and low voltage TTR (Case Study Figure 6). Excitation current tests (Case Study Figure 7) indicated a possible problem. Test Eng. Ground Guard UST

Case Study Fig. 1: Normal response

1

High

2

High

3

High

4

Cal.1

5

Low

6

Low

7

Low

8

Cal.2

Low Low Low

High High High

kV

mA

Watts

Meas. Corr. Corr. PF Factor 20°C

10

113.75 4.716

0.41

1.0

0.41

10

15.782 0.802

0.51

1.0

0.51

10

97.979

3.99

0.41

1.0

0.41

97.968 3.914

0.40

1.0

0.40

2.0 133.91 4.972

0.37

1.0

0.37

2.0 35.931 1.046

0.29

1.0

0.29

2.0 97.975 3.940

0.40

1.0

0.40

97.979 3.926

0.40

1.0

0.40

Case Study Fig. 5: Transformer overall power factor tests

Transformers Vol. 2

41 The SFRA traces in Figures 5 show the tests when high voltage winding is energized with the low voltage winding short circuited. The traces are expected to exhibit a similar starting point and an expected trail-off, followed by the more complicated form above 20,000 hertz which is typical of the short circuit tests. By shorting the low voltage winding the effect of the core is removed. The waveforms in Figure 5 are typical for the short circuit test.

Case Study Fig. 6: Low voltage TTR

Case Study Fig. 9: SFRA – HV tests with LV winding short circuited. Windings Appear to be Normal Figure 6 plots the SFRA open circuit test results for the low voltage winding. As was observed in the high voltage winding open circuit (Figure 4), there is a deviation in the low frequency range of the X3-X0 trace confirming abnormalities with the magnetic circuit. Case Study Fig. 7: Exciting current tests Efforts to de-magnetize the core did not result in any changes to the excitation currents. Due to the very high excitation current for H2 – H3 it was decided that SFRA tests should be performed in an effort to identify a problem with the core of coil. The Swept Frequency Response Analysis (SFRA) test results for this transformer are shown in Figures 8 through 10. Figure 4 shows the results of the open circuit scan performed on the high voltage winding. The H1-H3 phase and H2-H1 phase exhibit expected pattern for this configuration of windings. H3-H2 phase reveals a deviation in the low frequency range which indicates irregularity with the transformer’s magnetic circuit.

Case Study Fig. 10: SFRA -LV Open Circuit TestsX3 – X0 Appears to be Abnormal and is the Same Phase as H3 – H2 The transformer was returned to the factory, and the coil was removed from the 3rd phase, and the conductor in the high voltage winding was unwound layer by layer, with a careful examination of the condition of each layer. An initial evidence of arcing (Case Study Figure 11) was detected in layer 16 between adjacent turns. Similar evidence of arcing was also detected at the first two turns on layer 11.

Case Study Fig. 8: SFRA - HV open circuit tests. H3 – H2 Appears to be abnormal

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Transformers Vol. 2

Case Study Fig. 11: ARCING

Keith Hill has been employed at Doble Engineering since 2001, and currently works as a Principal Engineer in the Client Service Department. Keith has over 38 years of experience in substation maintenance, electrical testing, and project management. Mr. Hill is a member of IEEE, a former NETA certified technician, and is a level I and II certified thermographer. Prior to Doble, Mr. Hill was the Electrical Supervisor of Engineering Services for a major refinery. Mr. Hill has published several papers relating to equipment testing and maintenance for various conferences and publications. At the present time, Keith serves as the secretary of the Doble Arresters, Capacitors, Cables, and Accessories committee. Keith received his BS from the University of Houston with a major in Electric Power.

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Transformers Vol. 2

APPLICATION AND COMMISSIONING OF ONLINE PARTIAL DISCHARGE TECHNOLOGY FOR MEDIUM VOLTAGE SWITCHGEAR PowerTest 2016 Bruce Rockwell, P.E., Bruce Horowitz, P.E., Christopher Smith, NETA IV, American Electrical Testing Company, Inc.

INTRODUCTION Partial Discharge (PD) is a localized electrical discharge or spark resulting when ionization partially bridges the insulation between two conducting electrodes. PD may occur at any point in the insulation system, if the electric field strength exceeds the breakdown strength of the insulating material. Electrical equipment operating at or above 2,400 volts ac is susceptible to partial discharge/corona activity.

of the dielectric. When voltage stress across the void exceeds corona inception voltage (CIV), for the gas in the void, PD activity is initiated.

Left unchecked, this unwanted electrical activity can lead to total breakdown of the insulation system and catastrophic failure. PD activity can be short lived or occur over an extended period of time before it results in a phase to ground or phase to phase fault. PD appears in one of two forms in the insulation system: ●● Internal PD - Occurring in defects: voids or cavities within solid insulation ●● Surface PD - Occurring across the surface of the insulation PD activity emits energy as follows: ●● Electromagnetic Emissions ○○ Radio Waves (3 Hz - 300 GHz) ○○ Heat (300 GHz - 430 THz) ○○ Light (430 THz - 770 THz) ●● Acoustic Emissions ○○ Audible (20 - 20 KHz) ○○ Ultrasonic (20 KHz - MHz / GHz) ●● Gases ○○ Ozone ○○ Oxides of Nitrogen (when combined with water produces Nitric Acid) PD occurs in voids, cracks, or inclusions within solid dielectrics, at conductor-dielectric interfaces within solid or liquid dielectrics, or in bubbles within liquid dielectrics. PD is limited to a portion of the insulation so discharges only partially bridge between electrodes. PD in insulating materials usually initiates within gas-filled voids in the dielectric. The dielectric constant of the void is much less than the encompassing dielectric, so the electric field across the void is substantially greater than across an equivalent distance

Fig. 1: Partial discharge in solid insulation As illustrated in figure 1, when a discharge occurs, a small current flows in the conductors and is attenuated by the capacitive voltage divider network C1, C2, C3 in parallel with CT (total or bulk capacitance). PD along the surface of solid insulating materials occurs if the surface tangential electric field is elevated, causing breakdown along the insulator surface. This is common for overhead line insulators and can occur in switchgear insulators. This is particularly true when insulators are defective, contaminated and/or exposed to high humidity.

APPLICATION PD causes sub-cycle high frequency current pulses (nanoseconds to microseconds transients). These appear and disappear repeatedly as voltage goes through zero crossings. PD occurs at or

44 near both positive and negative voltage waveform peaks. These PD current pulses can be easily measured with a high frequency current transducer (HFCT) clamped around case ground of the tested component. PD severity is attained by measuring the burst interval; the interval between the end of a burst and beginning of the next burst. As insulation breakdown accelerates, burst interval decreases because breakdown occurs at lower voltage. Burst interval is critical at two (2) milliseconds since discharge is near the zero (0) crossing and facilitates propagation to continuous discharge causing major component failure. The arcing and sparking that occur during PD activity creates high frequency electromagnetic waves that propagate away from the fault point in all directions. Measuring these high-frequency pulses identifies the presence of PD. The next step is to locate the actual point of fault. Applying acoustic emission detection, ultrasonic sensors, is effective to detect and locate PD. Bandpass filters are typically required in order to remove interference from background / system noise. When PD activity occurs in switchgear insulation, it generates electromagnetic waves in the radio frequency range. The signal can travel through insulating materials or components. The radio frequency signal is attenuated as it passes through each surface or medium. Most of the electromagnetic pulses are conducted by surrounding metalwork but a small proportion encroaches onto the inner surface of the casing. These PD charges are small with voltage magnitudes of 0.1 millivolt to one (1) volt. This phenomenon was discovered by Dr. John Reeves in 1974 and he labelled them Transient Earth Voltages (TEVs). TEVs occur because the partial discharge creates current spikes in the conductor and these can appear in the grounded metal surrounding the conductor. This current flow escapes through metalwork joints (or gaskets in gas insulated equipment) and impinges an elevated voltage on the surface of the apparatus referenced to ground. Dr. Reeves established TEV signals are directly proportional to the condition of the insulation for switchgear of the same type when measured at the same point. TEVs are measured in units of dB-mV. These voltages are high frequency pulse type signals flowing in the switchgear metalwork. The metalwork represents a high impedance to ground for these signals. The current flow into high impedance facilitates generation of detectable voltage spikes. This voltage is impressed on the interior of the metalwork (to a depth of approximately 0.5 µm in mild steel at 100 MHz) and loops around to the outer surface where there is are electrical discontinuities. Electromagnetic waves generated by the partial discharge frequency create TEVs on adjacent enclosures. The surrounding enclosures act like an antenna. TEVs are a very convenient phenomenon for online measuring and detecting of partial discharges since they are easily detected without removing panel covers and do not require connection to the energized conductor. TEV detection methodology is useful to detect PD in switchgear and surface tracking on internal compo-

Transformers Vol. 2 nents; however, its sensitivity is insufficient to detect issues within solid dielectric cable systems. Test and maintenance programs use offline and online test methods to detect PD. Offline testing is typically a periodic test for factory and/or acceptance purposes. Online testing can be periodic or continuous and is typically used for maintenance testing. Offline testing requires the equipment under test to be removed from service so high voltage ac can be applied directly to the equipment to collect test data. PD can persist for years before manifesting into failure. Such failures can be catastrophic. It is important to verify if PD is present in newly manufactured equipment and prior to being placed into service. Verifying presence / absence of PD aides in confirming warranty conditions. Specifying offline PD testing should result in equipment that has a much higher reliability assuming tests are properly conducted. Industry standards, subject matter experts and the manufacturer should be consulted to properly define such testing specifications. A two (2) sensor remote TEV monitor can be extremely useful in locating the source of PD. The sensors can be installed on two (2) pieces of equipment or two (2) adjacent cubicles. The HMI will display the TEV severity detected at each location and more importantly it will display which location sensed the TEV first. The sensors can be moved quickly to another location until the source of the PD is located. In most situations this style of diagnostic testing located the source of PD within a few minutes. Online PD testing technology has rapidly evolved in recent years and can be performed periodically or continuously. Periodic monitoring consists of using hand held devices that are capable of detecting acoustic and electromagnetic signals. The use of TEV probes is a more recent technology tool. Handheld equipment provides instantaneous feedback allowing detection of the presence of PD. These tools allow the technician to detect and narrow the focus to better pinpoint the location of PD when it is internal to an apparatus. Continuous online monitoring incorporates sensors, data collectors, system monitors and data analyzers; to collect analyze and report on a voluminous steady stream of data reporting on the health of an insulation system. This type of PD monitoring system is not fool proof. Outside influences (florescent lights, local equipment operation or construction activity) can emit noise that is recorded by the system some that can emulate PD. Expert analysis and interpretation of the data is required.

DESIGN This paper highlights design of online PD monitoring systems for two (2) 38 kV / 200 kV BIL metal clad switchgears operating at 33 kV nominal: ●● Existing outdoor walk-in aisle switchgear: (2) Bus Sections - (14) Total Cubicles ●● New indoor switchgear: (3) Bus Sections - (30) Total Cubicles

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Transformers Vol. 2 The PD systems consist of the following components: ●● HUB - Host computer with system program and visual presentation of data ●● NODES - Sensor data collector ●● SENSORS ○○ TEVs ○○ Microphone (Ultrasonic Detector) ○○ Environmental Monitor (Temperature and Humidity) ○○ RFCTs (Monitors Cables) ○○ External Antenna - (Noise Cancellation / Outside Influences) Miscellaneous Equipment ○○ Ultrabus Cables (Nodes to Hub Data Link) ○○ Coax Cables (RCFTs, External Antennas and TEV to Nodes Data Link) ○○ LEMO Cables (Microphones to Nodes Data Link) ○○ SCADA Interface (Transmits Alarms from HUB to Local Alarm System)

Fig. 4: PD monitoring system - outdoor switchgear layout Figure 4 shows the layout for one of the installations. The system includes output contacts for alarming and is configured for remote monitoring. Each feeder compartment (incoming and outgoing feeders) contains an overall feeder RFCT, a TEV sensor and a microphone. The breaker compartments contain a TEV sensor and a microphone sensor. An environmental monitor (temperature and humidity) sensor is located in an area that reports on the switchgear environment. External antennas are mounted several feet away from the switchgear. The following design constraints were identified by the user and the manufacturer: ●● Interconnecting cable from NODE to HUB & NODE to NODE can’t be longer than 30 meters ●● Nodes mounted on switchgear and interconnecting cables can’t interfere with normal day to day operation or maintenance of the equipment

Fig. 2: System layout (concept) The PD selected provides a comprehensive system that monitors the key indicators for PD (except the gases). The system monitors each bus section and individual cubicle in order to capture the overall condition of the switchgear. Continuous data collection, alarming and expert analysis provides preemptive capability to identify any potential PD issues.

●● Existing switchgear - only individual feeder outages allowed for PD system installation ●● Existing switchgear - no overall equipment outage allowed ●● Location of sensors / equipment can’t jeopardize switchgear reliability (short / long term) ●● Installation of PD system can’t void manufacturer’s warranty ●● Installation needed to comply with NEC (Requires NRTL field listing) ●● Installation can’t reduce switchgear design ratings / capabilities (i.e. BIL)

Fig. 3: Selected sensors (metal clad - vacuum / air insulated)

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Transformers Vol. 2 external power source. In order to ensure continuously reliable power a small stand-alone UPS was installed.

Fig. 5: PD monitoring system - indoor switchgear layout

Once the location of the sensors, nodes and hubs were identified, a methodology needed to be developed to routes all the cables. The manufacture’s literature depicted nodes on the front door of the circuit breaker compartment with cables draped in front of cubicle doors from node to node. The manufacturer indicated on systems with such a design, when the circuit breaker doors needed to opened the associated node and cables would be disconnected. This is not acceptable for many customers. It is not desirable to disturb the system to perform inspection or operation of the circuit breaker cubicle. To address this issue, holes were drilled in the doors and grommets were used to route interconnecting cables between cubicles. This allowed doors to be easily opened to avoid system disruption for operating or maintenance. An additional installation challenge was the routing of sensor cables from the feeder compartment (rear cubicle) to the front of the switchgear. Several ideas were considered: ●● Up and over the switchgear and through the roof ●● Up and around the switchgear ●● Through the switchgear interior ●● Under the switchgear



Fig. 6: Node

Fig. 7: Hub

INSTALLATION The PD system uses various types of sensors that are connected to nodes via coax or LEMO cables. The nodes connected in a daisy chain and ultimately connect to the HUB using Ultrabus cables (Cat 7 cables). All of the devices are equipped with a strong magnetic base, making installation very simple. Each node accommodates two (2) ultrasonic microphones, one (1) RFCT, one (1) environmental monitor and either an external TEV or external antenna. Each node also contains a built in TEV and temperature sensor.

Photo 1: Node installed on exterior cubicle door

For the larger indoor switchgear installation the nodes were mounted on the front of the circuit breaker cubicles. Cables for sensors located in rear cable compartments needed to be brought to the front of the switchgear for connection to the node. The manufacturer supplied all the hardware, including interconnecting hardware (cables). Because there were so many cubicles to monitor and cable design is constrained to thirty (30) meters the system required two (2) hubs. The cable limitation is due to attenuation of the small signals to avoid data or system errors. Each hub is also limited to a polling capability of (22) nodes. Since the manufacturer provides all interconnecting cables preliminary system design layout is critical. The system has to be designed and laid out so cable lengths can be identified before ordering equipment. This requires locations for the sensors, nodes and hubs to be identified early. The hub needed to be located within a (30) meter cable run. The hub also requires a reliable 115 VAC

Photo 2: Cable routing to node through the door For the outdoor switchgear, routing up and over the switchgear and through the roof or up and around the switchgear were not

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Transformers Vol. 2 feasible since the cable length constraint could not be met. Routing cable through the switchgear was not safe since the line bus and line side stationary breaker stabs were energized. That only feasible option was to route under the switchgear. The switchgear is an outdoor, walk-in enclosure. The entire assembly sits on an I-Beam frame on a concrete foundation. When the switchgear was installed, the I-Beam frame was elevated two (2) inches above the concrete pad. This provided a gap that accommodated a 1-1/2 inch conduit. The conduit was fished under the structure between the rear cable compartment and the front circuit breaker compartment. This allowed sensor cables to be routed rear to front to the nodes.

COMMISSIONING Commissioning of this system was relatively simple. Table 1 is a representative commissioning data sheet used for programming the system configuration. When starting up the system, a “System Discovery” is initiated that polls all connected devices. This polling identifies the number of nodes connected to the hub and the type and quantity of connected sensors. During discovery all of the nodes will display red and Green LEDs to assist in troubleshooting nodes that are not communicating with the hub. If this information is confirmed as correct, an ID tag for each node and each sensor is entered into the system. The length of cable for any External TEV, External Antenna and RFCT must also be entered into the system configuration. The cable length is used to provide timing the sensors to time stamp the acquired signals. Once all the data is entered, the configuration is saved and the system is put into the monitoring mode the system is operational. Alarms are used to provide early warning / detection of PD. There are several alarms that can be set: ●● TEV dB Mean Level ●● TEV Mean PPC (pulse per cycle)

Photo 3: Conduit penetration - under floor

●● Ultrasonic Mean Level ●● CPD (cable partial discharge) PC Meal Level Table 2 shows the set points used for each alarm. Alarm level and alarm span were developed in conjunction with the manufacturer’s recommendation. The alarm span indicates how long the level needs to be at or above the alarm point in order for the system to consider it a valid alarm. Outside influences, localized noise and transient over voltage can cause the measured parameter to temporarily exceed the alarm level. Alarm span prevents/minimizes false alarms by ensuring the parameter has exceeded the value and is a valid alarm.

Photo 4: Cable pulled in underfloor conduit The new indoor switchgear has three (3) bus lineup sections. This switchgear was installed directly on a concrete foundation. Two (2) of the new sections were installed first inhibiting modification to the switchgear. For this installation half of the nodes were installed on the rear of the switchgear so that routing of cable rear to front was minimized. External wireway was installed to route cables between the front and rear cubicles. Existing wireway was used in the front of the switchgear to route the cables. The last section of the switchgear was still in manufacturing when the PD project was initiated. The manufacturer was asked to install provisions for routing cables between the front and rear cubicles for the sensor to node connections. This greatly simplified the installation of nodes and cable routing.

The original system design incorporated a general alarm (dry contacts) when any monitored point alarmed. This alarm signal was sent to the site’s central alarm command center, which is monitored 24/7. When alarms are received by the command center, they reach out to the appropriate department / personnel to respond. Since the owner had no prior experience with this type of system and the PD alarm data requires expert analysis relying on the command center and responding personnel was deemed insufficient. The hub is a computer running windows that has the capability to be networked. For security reasons, the owner’s IT Department would not approve access to the LAN or allow connecting the hub to the central network. To address this concern, a wireless router was installed and connected to each of the HUBs.

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Transformers Vol. 2 reading had increased above the other sensors. However, this sensor was below the alarm point (Figure 8). Looking at the data it appeared to be impacted by humidity. The user was notified of the potential situation. However, because the system was relatively new, the user was reluctant to remove the equipment from service just on this increased sensor reading. Separate ultrasonic readings were performed using a hand held instrument, which confirmed electrical activity. The feeder was removed from service and an inspection performed. An insulating barrier board was found rubbing against a 33 kV insulated conductor, causing corona to be emitted. Photos 5-7 show the inspection findings. The barrier board was removed, modified, cleaned and re-installed.

Table 1: Online PD commissioning data sheet

Table 2: Alarm settings TeamViewer (remote access program) was installed on the hub and remote computers. This system provides remote communication with the hub. The hub was programmed to send a daily email indicating that the system was functioning correctly. Also, an email would be transmitted if any monitored point alarmed or cleared. The email delineates what sensor alarmed and provides the actual level of activity. When an alarm is received, the system can be remotely accessed and viewed in one of two ways. The data can be viewed on the computer screen in real time as it could be on the local hub’s monitor or the data can be downloaded. Once downloaded, the data can easily be analyzed using the manufacturer’s data analysis software tool. This tool allows specific sensors to be highlighted and compared. This speeds up the data review and analysis process. This configuration also provides the OEM with direct access to the operating system which facilitates analysis of alarms, system updates and system adjustment. Teamviewer can also be downloaded as an application for both Android and Apple devices, allowing full access to the system from mobile devices.

LESSONS LEARNED During a periodic review of stored data, after one of the systems had been installed for several months, one (1) ultrasonic detector

Fig. 8: PD system data Ensure that the location selected for the hub installation is cool, dry, and clean.  The hub is susceptible to overheating and difficult to clean if dirt enters the cabinet. If more than (12) nodes are utilized in one installation the Ultrabus cable must be connected in a continuous loop from hub, node-to-node, and back to the hub.  If there is a break in the Ultrabus communication the hub will only communicate to the first (12) nodes.  This also makes troubleshooting a communication failure difficult if the failure occurs past the (12th) node.  In this situation all the nodes beyond the (12th) node will not communicate with the hub and will appear failed.  A long Ultrabus cable can be utilized to jump from the hub to the (12th) node to make discovering which node or cable is defective. Maintenance testing was performed on the cubicle and it was returned to service. Upon return to service the ultrasonic readings returned to normal levels consistent with other cubicles. Without this PD system, it may have been years before this activity might have been detected, which could have ultimately led to an uncontrolled catastrophic in service failure. A subsequent alarm investigation identified that the system was reporting elevated ultrasonic levels on a CPT Transformer used for supplying station service light and power. The hand held ultrasonic instrument was used and it confirmed low levels of electrical activity. The hand held instrument allowed the activity to be pinpointed

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Transformers Vol. 2 to a cable pass-through insulator. A bare conductor was used to connect the primary of the transformer to the load side of the fuse. Because the alternate CPT was out-of-service at the time this CPT could not be removed from service for repair. Three months later, smoke was seen coming from the CPT cubicle. It was immediately removed from service. The PD system was interrogated and it showed that the ultrasonic detectors had gone into alarm just prior to the smoke being reported. The trouble was tracked to a defective high side fuse that had operated single-phasing the transformer. The issue with the fuse is it was tracking on the inside of the tube (the tube was made of fiberglass). This event precipitated the owner’s decision to install the remote access capability. Photos 8-9 show the CPT.

Photo 8: CPT (top)

Photo 9: CPT

Photo 5: Insulation emitting PD

Photo 6: Insulation emitting PD

The RFCT is installed over the overall cable sheath ground. This RFCT is then connected to a node via a coax cable that has a metallic connector. Initially, some of the RFCT’s were installed at the floor level of the cubicle. After approximately three (3) months in operation, a feeder fault in the substation feeding this switchgear resulted in the ground cable melting on the feeder compartment. The root cause was the cable sheath ground cable was not sized adequately for the design fault current levels. When the ground cable burnt open, it caused a high voltage transient which flashed to the metal connector of the RFCT. This resulted in damage to the PD system. Repairs were made to the system, and all metal connector associated with any of the sensors in the high voltage compartments were insulated with Raychem 130o C tape. Adequate layers of tape were applied to protect against full line-to-line voltage. Advanced planning is critical for a project of this complexity to be successful. The following key items should be followed to simplify the overall project, in particular the installation: ●● Pre-identify the location and proposed labeling of each sensor and the length of the cable connecting that sensor. ●● Once the sensor, node and hub locations are identified, carefully determine how the system will be interconnected. This phase is very critical if the system is being applied to in-service switchgear. In some cases, a total outage of the switchgear will not be possible. Identifying routing of communication cables is an important consideration - methods to consider are under the gear (if there is access), external wireways and existing wireways.

Photo 7: Insualtion emitting PD

50 ●● Layout the design and sit review it with the user to fully explain the design and installation process. Don’t assume the user is going to agree with the initial design approach. Owner input can have significant impact on the design and installation. ●● After design is complete and cable routing identified, layout out the cable length requirement for each interconnecting cable. In some cases general cable lengths work, but, do not use a 10 meter cable when a seven (7) meter cable is suitable. ●● Label each cable as you install them so they can be identified during commissioning. Each should be tested to confirm functionality prior to polling the system. ●● Where nodes have two (2) ultrasonic detectors connected (A & B), the system will request where each of the detectors are located and a name for those detectors.

REFERENCES Brown, P. (1996). Non-Intrusive Partial Discharge Measurements On High Voltage Switchgear. The Institution of Electrical Engineers (pp. 1-5). Leatherhead: EA Technology. Davies, N. (n.d.). upload/PD-Techniques-For-Measuring-Condition-Of-MV-and-HV-Switchgear.pdf. Retrieved December 29, 2015, from http://www.cablejoints.co.uk/: http://www.cablejoints.co.uk/upload/PD-Techniques-For-Measuring-ConditionOf-MV-and-HV-Switchgear.pdf Garnett, J. M., McGrail, A. J., & Doster, P. J. (2010). Substation Metal Clad Assessment Using Handheld Ultrasonic and Transient Earth Voltage Testing Devices. TechCon 2010 (pp. 1-12). Santa Clara: Semiconductor Research Corporation (with Permission by National Grid). Kennedy, M. (2009). Partial Discharge - Electrical & RFI/EMI Detection Basics & Principles. Doble Fall Committee Meetings (pp. 1-94). Calgary: Doble Engineering Company. Lowsley, C., Davies, N., & Miller, D. (2012, July/August Volume 27, Number 4). Effective Condition Assessment of Medium Voltage Switchgear. Maintenance & Asset Management, pp. 46-51. Renforth, L., Seltzer-Grant, M., Mackinlay, R., Goodfellow, S., Clark, D., & Shuttleworth, R. (2011). Experiences from over 15 Years of On-line Partial Discharge (OLPD) Testing of InService MV and HV Cables, Switchgear, Transformers and Rotating Machines. IEEE IX Latin American Robotics Symposium and IEEE Colombian Conference on Automatic Control (pp. 1-7). Bogota: IEEE. Unknown. (n.d.). Upload/casestudies/cost%20benefit%20 analysis.pdf. Retrieved Dec 29, 2015, from:www.irispower. com:http://www.irispower.com/Upload/casestudies/cost%20 benefit%20analysis.pdf

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ELECTRICAL COMMISSIONING TIPS AND TRENDS FOR ADVANCED CRITICAL FACILITIES APPLICATIONS PowerTest 2016 Corey Dozhier, Oracle

INTRODUCTION The intent of this paper is to explain and solidify the position that commissioning is not just a “good idea,” but is actually something that should be considered a “must do” for your next missioncritical build.

before that you will at least consider it as an option now or, if you already believe in the benefits that you will learn how to leverage the process even further.

UNDERSTAND THE BASICS

Experience has shown that most owners and operators of mid to large scale critical facilities DO NOT consider commissioning to be a critical part of their project scope. In fact, my personal experience has been this, when the subject of commissioning was brought up most people did not understand it at all. Most did not think it was worth the extra capital expense or did not believe it was worth the time required in the construction schedule.

Without a basic understanding of the terms and definitions of commissioning, it would be difficult for anyone to understand the process and benefits. So let’s take a minute to learn some of the key definitions so that you may better follow along during the rest of this paper.

These examples are not made up; they are drawn from more than 20 conversations with 20 different colocation and cloud providers over a 6 month period in 2015. These conversations included CEOs, Engineers, Facilities Directors, Facilities Managers and facilities personnel, none of whom had considered commissioning as an option for their past or future projects. I was caught off guard, surprised each and every time someone told me “no, we did not commission,” or “no, we have not considered that as an option.” I once had a Director roll his eyes, laugh and shake his head and say “no, we don’t do that!”

“You, as the client, will be required to secure a 3rd party Commissioning Agent (CxA), someone who reports directly to you and is in no way affiliated with the Engineering Firm, General Contractor or any subcontractors. The CxA will be required to develop and execute a Commissioning Plan (CxP). This plan spans the entire life cycle of the construction process, from design through the end of the project. The CxP is made up of various steps, each built upon the previous, with the express intent of testing and proving each component and system within your facility to ensure the design intent was met and the systems will function as promised.”

It became clear to me that my peers in the industry did not view commissioning as I did. They either had not seen or experienced the benefits, had never had the option presented to them, or had been told that commissioning was not necessary. No matter the reason, building a data center and NOT fully commissioning it is like buying a used car without test driving it first. Sure you have the car, but you really have no idea how it is going to handle or what unforeseen electrical or mechanical problems may soon arise. Commissioning, when done effectively, can provide you, as the owner, with a kind of reassurance that can only be described as this, a peaceful satisfaction. You will be satisfied that all of the electrical and mechanical systems WILL function as designed, WILL handle any load variable up to 100% of design capacity, WILL meet or exceed your efficiency standards, WILL function correctly for your facilities staff during maintenance windows and WILL live up to the expectations of your customers. I invite you to explore the ideas presented in this paper, ask questions, criticize and critique my examples and form your own opinions. My hope is this; if you did not believe in commissioning

Below is a short paragraph describing the commissioning process and containing all the key terms we will be defining.

Term number 1 is “Commissioning.” As the paragraph above states, this is a detailed and methodical process of testing and evaluating systems, both individually and as a whole, in order to ensure proper performance and integrated reliability. Term number 2 is “Commissioning Agent.” The CxA is a 3rd party, independent vendor, hired by the customer to develop, coordinate and execute a detailed commissioning plan. Term number 3 is “Commissioning Plan.” The CxP is a step by step testing and evaluation plan, that begins with the individual components and equipment and ends with a Fully Integrated Systems Test. The first two definitions are fairly straight forward, so I would like to elaborate a bit more on the 3rd. A detailed and in-depth commissioning plan is not necessarily as complicated as it may sound. You don’t need to start from scratch each time because luckily there is already a proven framework available that is widely accepted and widely used. This is called the Level 5 Commissioning Plan.

52 The Level 5 Commissioning Plan, in its purest form, contains exactly what the name implies, 5 separate and unique steps that provide a framework for a complete commissioning plan. These include: ●● Level 1: Factory Witness Testing. This is usually only done on large scale projects with multiple large pieces of pre-purchased equipment. For instance, you as the owner may attend a factory witness test for a generator you purchased. These tests usually occur at the factory under highly controlled environments and prior to any equipment being shipped to the construction site. However, the advantage to including your CxA is that they are able to gain key information on how the systems are controlled and operated which aides them in developing their commissioning scripts later in the project. They may also note abnormalities in the trials at the factory, which they will then verify have been corrected on the construction site prior to implementation. ●● Level 2: Component Verification. Level 2 Verification generally begins as soon as the equipment arrives onsite. During Level 2, testing the individual components of each major piece of equipment are tested. This would include the breakers, CT’s, PT’s, transformers and relays to name a few. It won’t always necessarily be your commissioning agent who performs this step, although it could be depending on their capabilities. Your CxA will be responsible for collecting all of the documentation from any vendors performing acceptance testing at this time. The CxA will also verify that all the equipment and nameplates match the one line and meet the requirements of the design documents. This requires a lot of coordination with equipment vendors and onsite subcontractors and is one of the most time consuming portions of the CxP. However, it is also where most of the small problems are found and corrected and it generally happens early enough in the project to allow for major corrections if needed. ●● Level 3: Vendor Startup. During Level 3, you will generally see equipment vendor’s onsite. For instance, if you purchased a Cummins Generator or an Eaton UPS System, you likely purchased what is referred to as “start up” support. During this time, a representative from each key supplier will be onsite to assist the contractors in starting up and calibrating the critical equipment. Your CxA agent will likely be involved in this process as well, providing onsite support and document collection. Generally the CxA requires that a startup form be completed and turned in for each major piece of equipment prior to moving forward with Level 4 testing. ●● Level 4: Systems Commissioning. At this point you will begin to see the full value of your CxA and it is also at this point that they should begin to take over all testing activities and documentation. For Level 4 testing, your CxA will have developed testing “scripts.” These are step by step procedures for testing individual systems, like generator paralleling systems, UPS Systems or Cooling Systems. You should expect to

Transformers Vol. 2 see resistive load banks being used to induce sustained burnins, IR Scanning and full range of motion testing to verify system functionality. Scripts can be as short as 30 steps and as long as 350 steps, depending on the complexity of the system being tested. You should expect a UPS Level 4 script to be much longer than a simple ATS script. This will also be the time when your CxA should begin verifying the accuracy of any external BMS or EPMS monitoring systems. They will be looking for these systems to report the same values as they are seeing at the equipment and on their own external Power Quality Meters. Lastly, you should expect to see an active Issues and Resolutions log being developed. This is a record of issues discovered during commissioning, noted by the CxA and provided to the appropriate vendors for immediate action. ●● Level 5: Fully Integrated Testing. Level 5 testing brings all the systems together, mechanical, electrical, fire alarm, monitoring and controls. Again, you will have Level 5 scripts created by your CxA that will be designed to verify the survivability and maintainability of your site. In a Data Center style environment, it is common at this point to see resistive load banks on the data hall floor, mimicking server racks. The Cooling systems and Electrical systems are fully functional. The load banks will be set to various load levels to mimic servers, generally going as high as 100% of design load to verify that all of the installed systems function as designed. It is also during this time that your CxA will, for instance, fail your primary utility source and verify that all systems transfer to their emergency source, typically a generator. All of the level 5 tests should be conducted under conditions that mimic the finished environment as closely as possible. You don’t want half of your UPS system offline or 3 out of the 5 air handlers operational during Level 5’s. The Level 5 Commissioning plan may be expanded to include other levels if desired. For instance, Level 0 might be design participation and plan review. This ensures your CxA will be in on the ground floor of the design, which is highly recommended. Level 6 may be seasonal testing. If your facility was commissioned in the winter months, it may be wise to have some or all of it recommissioned in the summer to ensure proper functionality of all systems throughout the year. The final part of this discussion on the basics of commissioning, centers on budgeting. As is often the case, most arguments against commissioning focus on the “extra” cost. It is TOO expensive to seriously consider. The truth is you should never see your commissioning budget climb higher than 3% of your overall project budget. Real world experience shows a range between .006% up to 3% of your total project budget should be set aside for commissioning agent fees. The larger the project budget, the smaller the Cx percentage becomes. For instance, for a new build Data Center Project with a $35.000k budget, you should expect the Cx budget to be about .006% or roughly $218k. That is a small price to pay for the peace of mind it provides.

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Transformers Vol. 2 CHOOSE TO BE INVOLVED I believe the most successful commissioning projects are the ones that have a high rate of owner involvement. If an owner is involved early, and stays involved throughout the process, it guarantees a few things. It guarantees the owner will be able to provide input and opinions along the way, it guarantees that the owner will be aware of any issues that arise and how they are resolved and it guarantees that the owner will have the opportunity to have some hands on time with the equipment prior to any critical load being introduced. As you are preparing budget numbers for your upcoming project, remember to include a small percentage for commissioning. As we discussed earlier, 3% should be on the high end and a fairly safe number to include in a preliminary budget proposal. This will ensure a place holder and, if approved, allow you to move forward once the time is right. As the owner, it will primarily be up to you to begin the work of on boarding a CxA. The proper way to do this is to begin by developing a Request for Proposal and distributing that to 3 or 4 potential CxA for bids. One of the most important details to provide in an RFP is a deadline for bids to be completed. Most often, construction schedules are tight and you don’t want to be waiting for an RFP response longer than you need to. Keep your timeframes short to weed out vendors who aren’t on their A game. Two to three weeks to return a proposal is plenty of time for most qualified CxA’s. Referrals are a great way to identify CxA’s if you are not familiar with any. The engineering firm or general contractor should be able to provide a few contacts and it is also wise to reach out to your peers to see who they have used and if that vendor provided an acceptable service. Once a CxA has been chosen and a purchase order has been obtained, it is critical that you begin the process of integrating your CxA into the construction team as quickly as possible. Most CxA will begin a weekly commissioning call, to bring themselves up to speed on the various schedules and processes. If they don’t, you should. Make sure your CxA is “plugged in” as soon as possible. This is a good time to remember that your CxA works for you, not the Engineer, not the General Contractor. They work for you. So sit down with them and begin a dialog of things you would like to see done. You may know the systems and the design, or you may not, but either way, there may be certain tests or procedures you want to see done. Or there may be experiences with certain equipment or vendors you have had in the past that you don’t want to see repeated. Now is the time to lay it all on the table with your CxA to make sure all of your ideas are heard and all of your concerns are voiced. Always make sure you fully support your CxA. I can’t stress this enough! It is not necessarily the case with smaller projects, but with larger projects there will almost always come a time when your CxA and another contractor are butting heads. Finger pointing, late nights, missed deadlines, all add up to heightened frustra-

tions and foggy decision making. If you have confidence in your CxA, make sure they are 100% aware that you fully support them. Remember, their only purpose is to ensure your facility operates as it was designed. And no matter how well planned a project is, there will always be things that were missed, holes that need to be filled. It is the job of the CxA to find those holes and point them out and that doesn’t always sit well with the other contractors. Trust your CxA and support them. Finally, include your facilities staff in the Level 4/5 commissioning process as much as possible. The men and women who will ultimately be responsible for the day to day operation of the equipment can gain valuable experience during this time. Watching the testing will not only teach them how the equipment operates, but also, give them confidence that when it comes time to operate it themselves, that it will function as intended.

ENGINEER A CLEAN FINISH In this final section we will discuss some tips to help engineer a clean and successful finish, both to your commissioning project and to your contract with your commissioning agent. Let’s begin with the project itself. Here are some helpful hints to that should help bring your next commissioning project of a successful end: ●● Keep Roles and Responsibilities Clear. It may not seem like an issue, but it can turn into one fast. A perfect example is load banks. They are expensive to rent and sometimes very hard to find and somehow get forgotten until you nearly need them. Then it is a mad scramble to figure out who is responsible to rent them. Sometimes it is the CxA, sometimes the GC, sometimes the electrical vendor. Make sure all of the vendors understand their particular roles in the commissioning process. Some may need to provide manpower for support; some may need to provide equipment. ●● Keep Lines of Communication Open. Communication is the key to a successful commissioning project. At the beginning of this paper I described weekly Cx meetings. Toward the middle of the project and especially near the end you may need to have those same meetings daily. The Issues and Resolutions log should be updated by the CxA and distributed to the construction team dailwwy. Any major design issues should be brought to the construction team’s attention immediately. ●● Close out Issues quickly. A good CxA will stay on top of the Issues and Resolutions log and work with the subcontractors to close items out quickly. This really helps towards the end to keep the process less confusing. ●● Allow adequate time to Commission. This is hugely important. Most often, the general contractor is in charge of the project schedule and tends to give very little time for commissioning. Make sure you CxA has a copy of the construction schedule early on in the project, so that they can begin to massage those times as needed.

54 Now let’s take a look at some tips to help you close out the contract with your CxA once the project is complete. ●● Arc-Flash Labels/SKM Waiver. I require my CxA’s to provide the Arc Flash and Coordination Study as part of their contract. This means that they are responsible for generating the Arc-Flash Labels and installing them one all of the electrical components. It also means they are responsible for developing the SKM model for the coordination study. I have found that it is very advantageous for an owner to obtain a copy of the SKM model on CD. That way, if you ever do an addition to the building, the next contractor doesn’t need to completely recreate the coordination study from scratch. However, the CxA will usually require a signed waiver releasing them from any liability in order to release the SKM model to you. It’s a good idea tohave that waiver signed in a timely fashion. ●● Issues and Resolutions Log Closed. There always seems to be a few remaining items on the issues and resolutions log after the completion of a project. It’s a good idea to stay on top of those and get them closed out as quickly as possible. ●● Hard and Soft Copies of all Documents. I generally require my CxA to provide (3) hard copies and (3) soft copies of all of the commissioning documents. No matter the quantity, it’s a good idea to have at least (1) hard copy for your records.

CONCLUSION As I stated at the beginning of this paper, I hope it has helped to shed some light on the commissioning process, to bring about a more clear understanding of how it can be accomplished, how it can be budgeted for and how much time is required to successfully complete it. Also, I truly hope you consider commissioning your next mission critical build. Corey Dozhier is a Data Center Chief Engineer for Oracle, based in Salt Lake City, Utah. Corey has over eight years of Data Center design, construction, and facilities experience and is a graduate of Salt Lake Community College, where he received an associate of applied science in electrical studies. As Chief Engineer of a 250,000-square-foot, state-of-the art data center, Corey is knowledgeable in all key areas of critical building systems design, operation, and maintenance. These include medium-voltage electrical distribution systems, standby generation systems, direct and indirect evaporative cooling systems, traditional and flywheel UPS systems, fire and life safety systems, BMS and controls systems, and hot/cold aisle containment systems.

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RELIABILITY OF ELECTRICAL SYSTEMS FROM TESTING TO MONITORING PowerTest 2016 Alan M. Ross, Vice President of Reliability SD Myers, Inc.

RELIABILITY OF ELECTRICAL SYSTEMS: FROM TESTING TO MONITORING Transformers are the heart of electrical systems; therefore, any discussion about reliability of an electrical system must start with how robust our reliability system is for transformers. Operations & Maintenance (O&M) leadership has developed robust reliability standards for production assets in many cases but that same standardization of a system is lacking when it comes to transformers. Transformer reliability has not been an area that most industrial facilities or companies focus on. Why? The risks associated with transformer failures and the resulting production downtime has been overlooked. After all, the Mean Time Between Failure (MTBF) for transformers is 30 to 50 years and we have become over-reliant on an aging infrastructure that is beginning to experience a greater occurrence of failure and a exponentially growing severity from those increasing failures. It is a perfect storm that is now threatening the productive capacity of plants and facilities to avoid unplanned outages. In this paper, we will lay out a model Reliability Program Scale (RPS) for transformers followed by two practical cases demonstrating how this model is being adjusted and implemented to fit the needs of a major multi-site steel producer, Gerdau, and a complex single-site campus, Argonne National Laboratories. The changing demands on both of these organizations required a systems approach to transformer reliability and the increased need for testing, maintenance and monitoring of transformers.

RISK AND RELIABILITY The formula below illustrates the Risk/Reliability equation for transformers: Risk of Failure = Occurrence x Severity Detectability While the probability of transformer failures has been very low for decades, that probability has been increasing from <2% historically to as much as 7% as reported by several major insurance providers. More alarming is the dramatic increase in the severity resulting from an unplanned failure, especially when that failure is catastrophic. To maintain the same level of risk, or to reduce that risk, there must be an increase in the ability to detect potential failures with an increase in the preventative actions to avoid the

failure until the asset can be replaced. With lead times for replacing many classes of power transformers as much as 24 months, the need to extend the life of the current installed base is greater than ever. Replacing aging transformers might seem like the simple solution; however, we are often unaware that newer units have an increased probability of failure too. For decades we have relied on the bathtub curb, which projected higher failures at start-up for one year and then a leveling out of risk for 20 years and beginning to increase depending on the way the transformer was maintained. In 2011, in a presentation by Omicron found that the initial risk of failure, the front end of the bathtub curve has moved to three years from one year. Our empirical experience has validated that change too. During my years at Georgia Tech we used slide rules to solve complex calculations. Today, computer modeling allows transformers to be built to exacting and precise standards. In short, we do not overbuild them any more. More entrants into the transformer OEM market also means greater price competition, which has led to greater cost controls.

THE OCCURRENCE (PROBABILITY) OF FAILURE Transformers suffer from a malady that seems to mirror a growing issue in society; they are aging. Failures have increased over the past decade from less than 2% to less than 3% per insurance industry feedback with one carrier experiencing a 7% rate for a certain class of power unit. This is not much of an increase is it? The chart below represents one of the ways to look at probability from a process perspective. It is difficult to develop a purely mathematical model given the variables we must consider.

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THE SEVERITY (CONSEQUENCES) OF FAILURE The chart below is a simple illustration of the consequences from transformer failure. While the best method for determining the consequence from failure is to monetize that consequence, it is often extremely hard to do. We have increasingly seen the consequences of failures from minor irritations to complete plant shutdowns costing multiple millions of dollars.

Occurrence X Severity = Potential Disaster When we combine the two we have an excellent process model for determining risk.

While a basic plan might suffice for a small pad-mount transformer that powers the little used back parking area, a more robust plan should be applied to a critical unit that might power a data center or a critical production component. Basic plans lead to the highest potential for unplanned outages. Assurance plans, while never guaranteeing that an outage will not occur, apply every possible measure to increase the detectability of a potential problem and are the most robust plans for critical units.

PAPER, OIL AND DETECTABILITY Craft paper is used to separate the copper windings in transformers, providing mechanical and dielectric strength and dielectric spacing. It is clear that the life of the transformer for the most part is based on the life of the paper. As paper degrades, the reliability of the unit degrades and the degradation of paper can never be reversed.

TRANSFORMER RELIABILITY PLANNING What this should lead to is a better way to determine our priorities for life-cycle planning; how to detect potential failures through testing and monitoring; how we can reduce or eliminate that potential with better maintenance practices. Clear standards exist for chemical testing transformer fluids; however, a great deal of discretion is applied to which transformers are tested and when. Coupled with advances in testing technologies and monitoring capabilities, there really is no excuse for not implementing the best reliability plan for transformer fleets. Determining the consequences from potential failures is a good first step in determining the criticality of transformers. The chart at top-right outlines the potential steps in any reliability plan for critical units.

Dielectric fluids, the vast majority being mineral oils, act as a coolant, provide additional dielectric strength, protect the paper and play a tremendous role in detecting problems in the transformer. In fact, the first basic in transformer testing is diagnostic testing of the fluid. The same is true for FR3 or silicone testing in transformers that use these fluids as insulating fluids. Chemical testing is the accepted industry standard for detecting the reliability of a transformer. Consider that oil plus a catalyst like paper, copper and iron; coupled with an accelerator like heat and moisture create oxidation. Oxidation byproducts are numerous: ●● Alcohols, Peroxides, Ketones, Aldehydes, Metallic Soaps and Epoxies However, one byproduct of oxidation that degrades paper significantly is Acids. The chart below shows the acceptable to questionable to unacceptable levels of acids: Below are four simple magnifications at 750X of acid in paper:

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Transformers Vol. 2 IR AND CHEMICAL TESTING – BETTER TOGETHER

At a .05 acid we have reached a level considered the beginning of a questionable acid level. Remember, paper degradation cannot be reversed so a questionable level should be the first sign that maintenance is required.

At a .10 acid level, a level considered the beginning of an unacceptable result, you can see the build up of acid along the fiber strand and the beginning of splitting within the strand.

While IR testing is pretty standard for electrical systems, the annual IR test is usually done of the entire building and the test of the transformer is seldom correlated to the time a sample is pulled for chemical analysis. We have found that conducting a thorough IR scan at the time the sample is pulled provides better information for the IR and better information for the oil analysis. The engineering team can better identify the cause of a hot spot picked up on the IR report if they have the chemical test available to review at the same time, so conducting both tests at the same time is highly beneficial. Another benefit of IR at the time of sampling is that the IR data can be housed with the chemical data. When there is an issue, it avoids the need to search for two sets of data that do not really correlate due to the timing each test was conducted. What are we looking for specifically with an IR on the transformer? ●● Temperature under 65°C/55°C ●● Heat dissipation from top of transformer tank/radiator to bottom of transformer tank/radiator ●● Low oil level ●● Temperature difference between two similar bushings

At a .15 acid level we begin to see even more paper degradation and acid build-up. Fiber strands are breaking and acids continue to build up.

At a .30 acid level the paper begins to look more like dried porridge than paper. Much of the dielectric strength is lost and the life of this paper does not bode well for this unit. Additional chemical testing for greater diagnostics are: ●● Liquid Screen, Inhibitor Content, Power Factor, Karl Fischer (Moisture), Gas in Oil (DGA), Metals in Oil, Furan and when appropriate PCB

FIELD INSPECTION The value of a simple Field Inspection is often overlooked when sampling transformer fluids. A good visual inspection should look for and document: ●● Area accessibility, Paint condition, Gaskets, Bushings Checking the readings and the working order of the gauges: ●● Level gauge, Temperature gauge, Pressure/Vacuum Gauge

●● Hot spots showing on tank, LTC compartment, throat connections, or bushings

PREVENTIVE AND PREDICTIVE MAINTENANCE One of the most disturbing trends relative to transformer reliability is the tendency to avoid any sort of maintenance on transformers other than reactive maintenance. Given the fact that as paper degrades the reliability of the unit degrades and can never be reversed, it would seem logical to use your diagnostic testing to determine the maintenance standards you will put place. In far too many cases, when we are doing Root Cause Analysis of a failed unit, the condition of the equipment prior to the failure was clearly demonstrated as QUestionable to UNacceptable , two ratings we use based on the specifics of the diagnostic tests. As in the case above for acids, a level between .05 and .10 is QUestionable and a level above .10 is UNacceptable. In any reliability program, when equipment reaches these levels, the CMMS kicks in and the right parts, the right tools and the right people arrive in time at the right place to avoid a failure. It is time we applied those same reliability standards to the electrical system. One of the difficulties in doing so is because most CMMS and EAM program do not have built in capability for transformers, therefore a robust data management program needs to be initiated for transformer testing.

58 What would a good PM or PdM program do? ●● Vacuum processing / degassing ●● Re-inhibiting ●● Moisture reduction ●● Hot oil clean ●● LTC inspection & repair ●● Re-gasketing ●● Refurbishing ●● Full Electrical Testing A recent study in our Innovation Center looked at the impact of service on transformer life. The chart below presents the results of that study of over 1,500 decommissioned units.

Transformers Vol. 2 DGA monitor manufacturers use many different technologies for the purpose of dissolved gas detection in active monitoring. The largest manufacturers predominantly use gas chromatography (GC), photo-acoustic spectroscopy (PAS), solid state (SS), thermal conductivity detector (TCD), or selective membrane (SM) based sensors. These technologies have been in active use for several years, though GC is currently the only gas detection method referenced in IEEE standards for gases generated in oil-immersed transformers 2. Other emerging DGA monitoring technologies include non-dispersive infrared (NDIR) and carbon nanotube (CNT). In our 18-month study, we included all major OEM monitor, which account for over 95% of monitors in service. Over that period of time, we simulated faults and tested the monitors’ reactions. A white paper with the full details of the study parameters and results is available; however, for purposes of the this paper we will summarize the results as follows: ●● The monitors worked. While there were some differences in lead and lag times for gas detection, overall, DGA monitoring works and works well. ●● There are false positives we experienced and feedback from customers who have installed monitors report the same issue. This requires diligence in understanding the data to avoid “little boy who cried wolf” syndrome, where false positives are ignored and we miss the time it becomes a real issue.

For those units in the study where no service (PM or PdM) was done, the units lasted just under 20 years, which is what the insurance industry and many OEM’s have predicted. However, with just one service, that life extend to a little more than 27 years. For two services the life extended to just under 35 years and finally at three services the life was just over 37 years. Basically we can double the life of a unit by maintaining the oil, removing moisture from the paper and doing basic connection or bushing repairs. Beyond extending the life of the unit, a weaker transformer is at a greater risk from a fault caused either up-line or down-line. A well maintained unit is more likely to survive these external faults than a poorly maintained one.

FAULT GAS MONITORING Transformer monitoring is a rapidly growing field. It is estimated that the market for DGA monitors will increase from $113 million in 2012 to more than $755 million in 2020 1. This includes expansion from predominantly utility and generation monitoring into wider and broader application throughout the power grid and into industrial application as well. It is increasingly common to purchase DGA monitors at time of purchase of new transformers, and adding monitors to critical in-service transformers is becoming a significant component of transformer maintenance and reliability programs.

●● Data management for monitor data can in many cases create data chaos, a word one monitoring customer used to describe his monitoring program. Add to the fact that most monitoring data is not correlated to the chemical, mechanical or electrical testing data and you can see why data chaos might happen. In one instance, the customers must maintain Windows 95® to house his monitor data from one monitor. Imagine having multiple brands with multiple systems. ●● Hydrogen was present in EVERY fault condition we simulated, making it a very good low cost, check engine light. Running a chemical DGA after an alarm can then determine what events took place so combining the DGA with the Hydrogen monitor is a very good and cost-effective step to transformer monitoring. There are certain transformer applications where multiple gas monitoring would be recommended, based on the required need for a broad range of gassing conditions and for transformers with a Very High consequence from failure.

SUMMARY OF THE MODEL RELIABILITY PROGRAM The tools are available to significantly impact the reliability of our electrical systems. Due to the aging nature of existing transformers and the unique design and manufacturing changes for new units, every company must determine what their standard of reliability will be. An analysis of the consequences from failures coupled with the best detectability standards will mean less unplanned

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Transformers Vol. 2 down-time, a more reliable and low-cost system and the assurance and peace of mind that comes with instituting and maintaining the best practices for transformer reliability.

GERDAU: A MODEL FOR THE COMPLEX MULTI-SITES Gerdau, a major global steel producer, had several major considerations when it came to asset planning: The global market for steel was under pressure from a pricing perspective making it imperative that they use capital carefully and make lean manufacturing their O&M priority. However, the aging of their North American infrastructure created a potential for unplanned outages based in particular to the age of their installed base of LMF and EAF transformers. (Both types of units are critical to the steel making process.) Gerdau developed a reliability approach for their North American fleet, identifying both in service and spare units at 13 location in Canada and the United States. By taking a similar risk approach as used in the Myers model, they developed Health Check as follows:

These were developed using IEEE C57.104 standards. As you can see, this provided a simple, clear framework for both maintenance and replacement planning.

FAULT GAS MONITORING PROGRAM Gerdau also made the decision to install (32) 8-Gas monitors on their critical units. To make reliability decisions seamless, they installed the Guardian Monitoring Service, which places all their critical lab, monitoring and maintenance data in their web based data management system. In the event of an alarm the data can be shared immediately with the fault gas monitoring system Engineer, corporate reliability manager, site engineers and with offsite experts, who may be familiar with this type of equipment and issue. To date several issues have been rapidly identified and assessed with better and faster management decisions. Gerdau Conclusions: ●● Requires a corporate commitment to a culture change ●● Includes standardization of: ○○ Testing – Chemical • Mechanical • Electrical ○○ Maintenance practices ●● Requires integrated operational and capital planning ●● Requires a knowledgeable work force ●● Requires a robust and shared data management system ●● Will eliminate or reduce unplanned down-time/outages

Using these four condition criteria, Gerdau developed the following rating for installed units:

The Gerdau implementation of their Transformer Reliability Program is only the beginning of their commitment to overall electrical system reliability.

ARGONNE NATIONAL LABORATORIES: A MODEL FOR COMPLEX SINGLE-SITE Where Gerdau was a complex multiple site case study, Argonne is a complex single site case study. Argonne traces its birth from Enrico Fermi’s secret charge — the Manhattan Project where the team constructed Chicago Pile-1, a nuclear reactor which achieved criticality on December 2, 1942, the first of its kind. ●● $760 Million operating budget And also for their spares:

●● 3,350 employees ●● 1,250 scientists and engineers ●● 750 Ph.D.s The Argonne need was to create a reliability approach for their entire grid, given the critical nature of their work and the fact that demand is going to double in the near future. They created a modified reliability approach for: ●● Transformers and motors. ●● Breakers may never have to perform their function through their lifecycle.

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●● Protective relays — the silent sentinels. ●● Electrical transmission and distribution-required redundancy. Argonne took the following steps to achieve greater reliability and prepare for growth: ●● Equipment list reassessment in the CMMS system ●● Granular criticality distribution of individual assets - well defined basis derived from: ○○ Safety ○○ Outage impact ○○ Quality impact ○○ Replacement cost ○○ Replacement availability ●● Development of PdM routes and advanced Maintenance & Monitoring equipment and processes: ○○ Infrared imaging ○○ Ultrasound detection of corona ○○ Data analysis using Web Based Data Management System. ○○ PM inspections modified (Based on FMEA) ○○ Frequency of PdM and PM inspections developed based on asset criticality. ○○ Combined approach to all PdM tools available. ○○ Purchase and utilization of Online Moisture Reduction equipment ○○ Future installation of Fault Gas Monitoring System on Critical units Argonne Conclusions: By all measurement standards costs were reduced, better PdM and PM methods were implemented and the overall reliability of the system is now better documented and planned for future growth.

CONCLUSIONS Electrical system reliability has been overlooked for too long, leading to over-reliance on an aging infrastructure. Creating a riskbased approach to the most critical component within an electrical system will lead to better outcomes for maintenance, capital planning for fleet replacement and the overall reliability of any system. Unplanned outages may never be eliminated however they can be better managed and planned for using this reliability centered approach which is already prevalent in most other areas of the plant. By creating the right set of standards for testing and monitoring, managing data centrally and making it easy for decision making we will take the first steps to creating a reliable system for both existing and new transformers.

Alan Ross is Vice President of Reliability at SD Myers, Inc. in Tallmadge, Ohio. He is responsible for developing and executing long-term reliability strategies and nextgeneration leadership for all operating units, both domestically and internationally. He is a Certified Reliability Leader and a member of the IEEE Reliability Society. He often presents at industry conferences and has authored several trade publication articles on transformer maintenance and reliability, including articles featured in Solutions and Uptime magazines. He has also written two books: Unconditional Excellence and Beyond World Class. Alan completed his undergraduate work in mechanical engineering at Georgia Institute of Technology and received his master of business administration in marketing from Georgia State University, graduating magna cum laude.

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ELECTRIC & DIELECTRIC CONDITION ASSESSMENT OF HV CURRENT TRANSFORMERS PowerTest 2016 Diego M. Robalino, PhD, PMP, MEGGER North America

OUTLINE The purpose of current transformers (CT) in the field is twofold: (1) to be used in accurate measurement systems and; (2) to be used in complex protection and control schemes. For both applications, reliability and precision are paramount; mal operation of CTs may result in the failure of critical components of the electrical infrastructure and interruption of electric energy supply to consumers. Extensive work is carried out by different manufacturers to improve the performance of high voltage equipment. As part of this work, the evaluation of alternative testing procedures capable of improving the efficiency of the manufacturing processes and minimizing the risk of failure in the field are of utmost importance. Non-intrusive and non-destructive testing procedures are primarily used in the field. A complete analysis of the electrical parameters and their compliance with nameplate information is the first step in qualifying the electrical condition of the CT. In addition to electrical testing, a series of dielectric tests can be carried out in the field to determine the condition of the insulation system of oil-impregnated HV current transformers. This paper will cover best field testing practices and interpretation of results. It will be a practical reference for testing technicians, asset managers and engineers dealing with condition assessment of HV instrument CTs. A variety of examples are incorporated throughout this paper to help the reader better understand the advantages and field challenges of electric and dielectric testing procedures, including but not limited to: turn ratio, polarity, saturation, static winding resistance, insulation resistance, power factor and dielectric response.

Equation 1 In practice, the accuracy of a CT or its ability to precisel represent the primary current is dependent on two factors: ●● The external load applied to the secondary of the CT (referred to as burden) ●● Magnetic losses that occur in the core of the CT Transformation errors will always exist in varying degrees because of losses that occur within the magnetic circuit of this specialized type of instrument transformer. Errors in the accuracy of current transformation can be related to both CT construction and their specific application. CTs are a magnetic device and require a portion of the primary current in order to simply excite the core of the transformer, or to cause magnetic flux to flow within the core of the transformer. Similarly, the magnetic coupling of the flux that is flowing in the core of the CT must be transferred to the secondary winding which also results in losses that can affect the accuracy of the transformer. Therefore, it can then be said that the resulting current in the secondary of a CT corresponds to the primary current (carried to the secondary winding) minus the excitation current and other magnetic losses. This leads to the expression (2), graphically represented in Fig 1.

Expression 2

CURRENT TRANSFORMERS - BASICS By definition, CTs are instrument transformers whose primary winding is connected in series with the conductor carrying the current to be measured or controlled [1-2].

Ideal vs. Real Current Transformers Under ideal conditions, a CT views the secondary current as being inversely proportional to the turns’ ratio relative to the primary winding current. Thus, any variation in the primary current will be reflected in changes to the secondary current as well. This is illustrated in equation (1).

Fig. 1: Real CT equivalent circuit

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Zμ - corresponds to the impedance of the magnetic circuit and core losses Zb - corresponds to the impedance of the load or "burden" Accordingly, the vector diagram shown in Figure 2 illustrates the vector components of the primary current as it is transferred to the secondary circuit.

TCF involves both components of error; the ratio correction factor (RCF) and the phase deviation error (β - in minutes). Generically speaking, the TCF for a CT that has a lagging power factor of 0.6 would be expressed as shown in the following equation (4). (4) However, the equation used in (4) is generic and only an approximation that assumes β is a very small value close to zero. The correct and therefore more precise formula, under the same conditions where the power factor is 0.6 lagging is shown in equation (5): (5)

Accuracy class for measurement Fig. 2: Vector diagram of the current components of a real CT The magnitude of the error is known as ratio error and the phase angle error is known as phase deviation. When a CT is used for current measurements only, then the ratio would be the only consideration. However, if the CT is used in power measurement applications where the phase relationship between voltage and current is involved, then the phase angle error of the CT should be considered as well.

At 100% of rated current

10% of rated current

Minimum

Maximum

Minimum

Maximum

0.3

0.997

1.003

0.994

1.006

0.6

0.994

1.006

0.988

1.012

1.2

0.988

1.012

0.976

1.024

Table 1: IEEE Accuracy classes measuring CTs The fact that TCF and RCF limits are the same is why in 3 the accuracy class parallelogram references both RCF and β as shown in Figure 3.

ACCURACY OF CURRENT TRANSFORMERS CTs are used mainly for two applications: measurement and protection. These applications are clearly defined in the international standards by their performance characteristics. In section 5.3 of 3 , the standard accuracy classes for metering CTs and the corresponding limits of the transformer correction factor (TCF). This classification is based on the requirement that the TCF of the CT be within the specified limits when the power factor (lagging) has a value from 0.6 to 1.0, and has a standard load of 10 and 100% of rated primary current. Notice that a CT that is burdened to 10% of the specified load, does not necessarily have the same TCF as when that same CT is burdened to 100% of the specified load. It is then necessary to define some terms used to express the errors in the magnitude of the ratio relationship in (3)

RCF =

Actual Transformer Ratio Nameplate Transformer Ratio

(3)

Phase angle error β (as shown in Figure 2) is the angle between the vector of the secondary current and primary current vector. This angle is considered positive when the secondary current vector leads the primary current.

Fig. 3: Limits of accuracy classes for metering CTs The accuracy characteristics of CTs in a dedicated system protection scheme must be maintained while simultaneously tolerating adverse over-current conditions. There are three kinds of protection CTs: C, T and X. For CT classifications of C and T, the

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Transformers Vol. 2 accuracy class is given by the secondary voltage at which the CT is able to output up to 20 times the rated secondary current (5A) without exceeding its specified ratio error. For this reason, it is important to know the correlation between this voltage value and the standard burden specified on the nameplate of the CT as presented in Table 2 for the IEEE reference 3 Limits of ratio error

@ rated current

@ 20 TIMES

C&T

3%

10%

X

User defined

Table 2: IEEE Accuracy classification for relaying application

RESIDUAL MAGNETISM IN CURRENT TRANSFORMERS The influence of DC current tends to saturate the magnetic core material of a CT. Any residual magnetism, referred to as magnetic bias, that remains after having applied DC to the transformer can directly affect the accuracy of the ratio. Regardless of the application, whether measuring or protection, the CT core can be magnetized either by: ●● the application of DC via one of the windings of the transformer, ●● the passage of AC when the opposite winding is opened, and; ●● under a transient condition or sudden interruption. To remove the magnetic remnants in the CT, the flux density should be raised up to the saturation level and then gradually reduced to zero. This process is known as demagnetization and can be done in both DC and AC. Take note that in the course of field testing, specifically when performing winding resistance test, DC is used to saturate the core of the transformer. The change in current with respect to time will vary until the core becomes saturated and will no longer accept any additional flux. (6)

CURRENT TRANSFORMER ELECTRIC FIELD TESTING In routine testing with advanced equipment, it is necessary to input the CT nameplate data, identifying and differentiating its application and accuracy class. It is especially important in high -voltage CTs, to have a historical assessment of the CTs’ insulation resistance. In the absence of an acceptable insulation resistance test result, there is a safety concern regarding electrical shock during testing or operation of the unit. Electrical acceptance testing of current transformers is described in Section 7.2.1 of 4. NETA recommends that the testing of insulation resistance between windings or between a winding and the ground connection be made at 1000VDC or at a tolerance recommended by the manufacturer. Once a CT’s dielectric properties have been verified to be acceptable, the next step is to verify the performance characteristics and nameplate compliance of the transformer. The first test performed is the winding resistance (WR) test. WR test is performed by injecting DC current into the secondary winding. Once the core of the CT begins to saturate, fluctuations in current will begin to stabilize, allowing the voltage drop across the winding to be measured. Ohm’s law can then be applied to accurately calculate and record the resistance of the winding. Traditionally, this test has to be repeated on each secondary winding section of a selectable-ratio CT, one at a time. This process is very inefficient and time consuming, especially on CTs with multiple taps, due to the time it takes to swap the test leads between each test. New testing technology now allows the entire winding to be energized and measurements for each section taken simultaneously, so values of all combinations of terminals can be obtained from performing the test only once. The circuit for performing concurrent testing of CT secondary windings is illustrated in Figure 4. After performing the winding resistance test, the core of the CT must be demagnetized. Demagnetizing the CT can be accomplished by applying an algorithm that can utilize either AC or DC current. It is essential that this step in the testing process be completed prior to subsequent testing to ensure that excitation and ratio test results are both accurate and reliable.

At the point of saturation, the variation of current flow with respect to the change in time will go ideally to zero based on equation (6).

FIELD TESTING OF CURRENT TRANSFORMERS Now that the performance of metering and relaying CTs has been discussed, the field electric and dielectric testing methods to assess the condition of CTs in the field are summarized hereinafter. HV CTs, especially those of oil-impregnated construction, are discussed in more detail as the condition of the dielectric system must also be assessed by tests performed when the equipment is out of service by non-intrusive and non-destructive techniques.

Fig. 4: Simultaneous measurement of the secondary winding resistance in a CT using multiple leads

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Following the proposed plan to test the CT, and having it fully demagnetized, the next step is to perform excitation and saturation testing. Both excitation current and the RMS voltage of the secondary winding should be clearly observed in the measurement process.

Fig. 5: Saturation test results of a multi-tap / selectableratio CT under simultaneous mode As defined in section 3.4.214 of [10], the excitation characteristic is a graphical presentation of the relationship between the r.m.s. value of the exciting current and a sinusoidal voltage applied to the secondary terminals of a CT. From here the knee point voltage is observed as the r.m.s value of the sinusoidal voltage at rated frequency applied to the secondary terminals of the transformer, all other terminals are floating, which when increased by 10%, causes the r.m.s. value of the exciting current to increase by 50%. The excitation characteristic made at rated frequency allows comparison against the curves supplied by the CT manufacturer. This comparison provides a means by which CT accuracy class and saturation point can be verified for the appropriate application of the CT. One additional test can prove the ratio and the polarity of the CT. Ratio measurements would need to be collected in the linear portion of the excitation curve, below the point that the CT would begin to saturate. IEEE C57.13.2008 3 indicates two methods of obtaining this information; one requires that primary current be injected into the CT and secondary current measured, and the other that allows for the application of voltage to the secondary of the CT and the primary voltage measured. Either method is acceptable. The polarity test, performed during the same step as the ratio test, confirms that the predicted direction of secondary current flow is correct for a given direction of primary current flow. CT performance is finally validated calculating the CT ratio and phase errors at different burden values as presented in Figure 6.

Fig. 6: Graphical representation of ratio error and phase deviation at different burden values Separately, the physical burden attached to the CT secondary can and should be measured to confirm that field conditions comply with CT specifications.

CURRENT TRANSFORMER FIELD DIELECTRIC TESTS Insulation Resistance (IR) test is part of the fundamental field test for low, medium and high voltage CTs. Medium (MV) and high voltage (HV) devices require additional dielectric tests considering the additional stress created by high voltage field and the unstoppable aging process the insulation system undergoes. Oil sampling is not always an option and testing of the insulation system is critical. Therefore, non-intrusive and non-destructive techniques such as dielectric response testing in the frequency domain are more and more being used in the field. Power Factor / Dissipation Factor test is a single frequency test typically performed at line frequency or close to it to evaluate the average condition of the insulation system. The test provides a general idea of contamination and or deterioration of the insulation system. For HV instrument transformers, it is important to verify if the CT has a test tap or not before performing the test. In the more complex case of a CT where the insulation system consists of paper wrapped in graded sections and immersed with a test tap, all capacitive sections as shown in Figure 7 can be tested 5.

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Transformers Vol. 2 HV → high voltage terminal LV → low voltage terminal D

→ tap test point

C1 → represents the main insulation between HV and D C2 → represents the insulation between the test tap and ground. Typically the test voltage for this capacitance does not exceed 500VAC unless there is a different recommendation provided by the manufacturer. C3 → represents the insulation between the test tap and the secondary winding C4 → represents the insulation between LV and ground

A

C5 → representing the insulation between the HV-terminal directly to ground including porcelain surface HV

C1 C3 C5

LV

D

C2

C4

Fig. 7: CT with tap - testing capacitances Dielectric response in the frequency domain (DFR) involves a procedure similar to the power factor test method, but in this case, a wide band frequency sweep generates the unique the dielectric response of the insulation (capacitance) where the greatest amount of solid insulation is located. For most cases, the capacitance C1 is tested for CTs with test tap and the overall insulation having the secondary shorted to ground.

B Fig. 8: DFR of HV CT before (a) dry-out 4.9% moisture and after dry-out 1.4% moisture. In the field, similar units are utilized and benchmarking gives a perspective of the condition of similar units on a common application. DFR provides a very good visual reference to quantify the accelerated degradation of a unit in the system.

DFR is carried out on HV CTs to determine: ●● Moisture estimation in solid insulation ●● Liquid insulation conductivity ●● Thermal behavior of dielectric parameters ●● Non-typical responses DFR can be easily applied in factory as a QA/QC tool before and after the dry-out process. This application allows manufacturers a better control of the dry-out process making it more efficient and effective. Moreover, it is clear that the condition of the insulation system changes when moisture is removed. This is clearly observed not only in the dielectric response but also on the thermal response of dielectric parameters such as power factor.

Fig. 9: Sister CTs installed on a 3-phase system Moreover, DFR allows prioritization and specification of maintenance/repair/replacement activities and the evaluation is carried out by the system directly which allows the operator to worry about the results and not much about the shape of the curve.

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CONCLUSIONS ●● Electric condition assessment allows verification of nameplate information, validation of performance characteristics and compliance with field requirements. This derives in reliable and safe operation coordination. ●● The concurrent method for electric testing minimizes the time spent in the field and optimizes the field resources making field testing more efficient. ●● Reporting is paramount. Results should comply with the reference standard and the field operation requirements ●● Dielectric condition assessment, using frequency response techniques (PF & DFR), allows assertive decisions to be taken, prioritization of activities, benchmarking, QA/QC and failure prevention ●● DFR under high EMI may require to be performed at voltages higher than 1kVrms.

REFERENCES 1

IEEE 100 "The Authoritative Dictionary of IEEE Standards Term." Seventh Ed 2000.

2

I EEE Standard Terminology for Power and Distribution Transformers, IEEE Standard C57.12.80-2002, Nov. 2002.

3

I EEE Standard Requirements for Instrument Transformers, IEEE Standard C57.13-2008, July 2008.

4

International Electrical Testing Association, Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems. ANSI-NETA ATS-2013

5

 VO Multiamp, CB-100 Capacitance and Power Factor Bridge A User's Guide.

6

J . Cheng; Werelius, P.; Robalino, D.; Ohlen, M., "Improvements of the transformer insulation XY model including effect of contamination," Electrical Insulation (ISEI) Conference, Vol., No., pp.169, 174, 10-13 June 2012

7

Werelius, P.; J. Cheng; Ohlen, M.; Robalino, DM, "Dielectric frequency response measurements dissipation factor and temperature dependence," The Electrical Insulation (ISEI) Conference, Vol., No., Pp.296, 300, 10-13 June 2012

8

 . M. Robalino, N. Colorado, Oropeza G., "Technological D Advances in the Assessment of the Status of Power Transformers", Proceedings of the 2013 IEEE Conference RVP, Mexico, 2013

9

IEEE Guide for Field testing of Relaying Current Transformers. IEEE std. C57.13.1 – 2006.

10

IEC 61869-2 – Instrument Transformers – Part 2: Additional requirements for current transformers

Diego Robalino works for Megger as a senior applications engineer, where he specializes in the diagnosis of complex electrical testing procedures. While doing research in power system optimization with a focus on aging equipment at Tennessee Technological University, Diego received his electrical engineering Ph.D. from that institution. With an international background spanning from South America to Eastern Europe, he’s garnered additional education experience in project management and electric drives/ automation. Diego has many years of management responsibility in the power systems, oil and gas, and research arenas managing the design, construction, and commissioning of electrical and electro-mechanical projects. He is an active member of IEEE, ASTM, and PMI with multidisciplinary engineering interests.

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BUSHING REPLACEMENT IT FITS – BUT WILL IT WORK? PowerTest 2016 Keith Hill, Doble Engineering Company

Bushing replacement can appear to be an easy and straight forward job. Remove the defective bushing and replace with a new bushing that will fit in the opening. One must also make sure that the replacement bushing will not only “fit in hole” but the replacement bushing must have the same current rating, voltage and BIL. The theory “that it fits in the hole” can often times work on low voltage bushings but when replacing higher voltage bushings several items must be taken into consideration. According to Keith Ellis, the author of Bushings for Power Transformers, the following items must be considered for IEEE Standard designed bushings. ●● The temperature of the ambient air does not exceed 40o C and the average temperature of the ambient air for any 24-hours period does not exceed 30o C. ●● The temperature of the ambient air is not lower than -30o C. ●● The altitude does not exceed 1,000 meters. ●● The temperature of the transformer insulating oil in which the inboard section of the bushing is immersed and the temperature of the mounting flange does not exceed 95o C averaged over a 24 hour period. ●● The external terminal and bush connections do not exceed a 30o K (243o C) rise over ambient. ●● The bushing is mounted at an angle of inclination to the vertical not exceeding 20o. Mr. Ellis also states that there are also numerous items that must be taken into account for unusual service conditions for IEEE Standard designed bushings. ●● Applications at altitudes greater than 1,000 meters (3,300 feet). The dielectric strength of bushings that depend in whole or in part upon air for insulation decreases as the altitude increases due to the effect of decreased air density. The bushing is either designed to operate at the required altitude or is de-rated in accordance with Table 1 in IEEE Standard C57.19.00. ●● Damaging fumes or vapors, excessive abrasive or conducting dust, explosive mixtures of dust or gases, steam, salt spray, wet conditions, etc. These adverse conditions may require using a SRI (Silicone Rubber Insulator) bushing in place of the standard porcelain type bushing. If porcelain is used the creep distance may have to be increased.

●● Tilting in excess of 20o from vertical. Most bushings can be applied at greater angles, but it is wise to confirm with the manufacturer of the bushing. Excessive tilting of a bushing on a mobile transformer may result in the breakage of the bushing during transport if the bushing is not high strength. ●● Abnormal vibration or shock. These conditions arise for mobile transformers and in high seismic areas. ●● Unusual temperature applications. This includes applications for enclosed or isolated phase bus duct and certain areas with very high temperatures such as Arizona. ●● Proximity of walls and buildings that could limit air circulation. ●● Application where fire deluge systems are used. An accidental operation may cause the bushings to fail as the volume and direction of the water is unlike a rainstorm for which the bushings were designed.

BUSHING FAILURES Some causes of bushing failures are top terminal heating, flashover caused by animals, vandalism, electrical system issues, failure of the bushing insulation system, and bushing sealing system failure, design issues, and abuse of the bushing such as overload or adverse operating conditions. Other factors that can affect the successful operation of a bushings are the incorrect long term storage mishandling and incorrect transportation of the bushing. There have been numerous times when the owner of the equipment thought that they had spare bushings in storage only to find out that improper storage or mishandling over the years have left the bushings to be useless for service. Bushings that have been in storage and fail to operate when placed into service identifies the need for periodic testing of bushings while in storage. When spare bushings are not available the owner of the equipment often times expects the service company to work miracles and obtain a bushings in a matter of hours when in reality it make take weeks or months to get the much needed bushing from the manufacturer. Every transformer designer provides industry acceptable safety margins for internal and external electrical clearances. When replacing existing bushings it is extremely important that the original design clearances are maintained. If you cannot replace the original bushing with one that is exactly the same as the original bushing you need to evaluate the impact the replacement bushing will have on the transformer design.

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It should be noted that bushings manufactured prior to 1980 may be PCB contaminated and should be handled as such until tests prove otherwise.

BUSHING REPLACEMENT FACTORS When a failure occurs and an exact match for the bushing is not available there are many factors that must be considered for the replacement and proper operation of the equipment. Factors that must be taken into consideration for proper replacement and operation include the dimensions above and below the flange, connections terminals to the transformer windings leads and to the electrical system, mounting flange configuration, electrical clearances inside the tank, phase to ground and phase to phase clearances, outside the tank and to adjacent accessories. Often times a flange adapter or draw lead adapter must be utilized for the proper fit and operation if the replacement bushing is not an exact match.

DIMENSIONS ABOVE THE FLANGE Dimensions above the flange can vary for reasons such as different creep levels, altitude of bushing in service, different design concepts, or because of a new and better design. The creepage distance has no effect on the arcing, or strike, distance of a bushing, the straight line distance from the live part to ground. Creepage and strike distance (figure 1) bushing dimensions above the flange. Arcing distance determines the altitude rating of the bushing, which may vary depending on the design of the bushing’s capacitance graded condenser. One design may require 100” of arcing to operate at 10,000 feet and another may only need 92”. The creepage of the insulator is achieved with a variety of shed profiles and configurations, which is left up to the individual bushing designer or based on the requirements of the purchaser. Today, many bushing manufacturers have standardized on a 10,000 foot altitude rating as well as the higher recommended creep specified in C57.19.01 – 2000 for most of their bushing line. Therefore, the height above the flange will be different among bushing brands and different within a specific brand of bushings from one generation to the next. This has become more common as efforts to standardize bushing lines have increased. These differences need to be considered and evaluated when the new bushing is not an exact match to the old bushing. The following possible issues need to be evaluated:

Fig. 1: Creepage and strike distance Some of the factors that must be taken into consideration for dimensions above the flange are; Are the bushings mounted at an angle? ●● Taller bushings will increase the phase to phase clearances ●● Shorter bushing will decrease the phase to phase clearances Elevation of the lightning arresters ●● Depending on how close the arresters are mounted to the bushing the top of the arrester must not be below the top of the bushing ●● If the arrester is below the top of the replacement bushing consult with the bushing manufacturer to determine if the arrester needs to be raised Bus Connections ●● Bushings that are taller or shorter may require modification of the rigid bus ○○ Rigid bus should not be used in moderate or high seismic areas ●● Replacing high current GSU Bushings require special consideration when being replaced because the connection is a combination of rigid bus with flex connections ○○ If the new GSU bushing is taller or shorter than the old bushing major changes will be required to the connection assembly Draw Lead Bushings ●● When replacing draw lead bushings and the new bushing is not the same dimension above the flange, a draw lead adapter may be required in order to maintain the original electrical geometry inside the transformer ●● If the difference in height above the flange is greater than +/½” the use of a draw lead adapter should be considered

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Transformers Vol. 2 ●● If you know how the draw lead cable is insulated inside the bushing the above tolerance could be increased to + ½"– 1"

FLANGE ADAPTERS

crimp on adapter also requires special skills. If the cable size is unknown the technician or engineer must estimate the cable size based on the MVA rating of the transformer. One must also cut off the old stud below the solder flow if the stud was brazed on.

When replacing old bushings, it is often necessary to use a bushing flange adapter (Figures 2&3) for the proper fit of the new bushings. This is often required when the lead time for an exact replacement is too long, when there is a gasket groove, when the bushing has a different mounting pattern or a different flange thickness. It should be noted that flange adapters should be fabricated with non-magnetic material.

Fig. 4: Crimp on and brazed

Standard Flange

9 ¼ Pattern

Modified Flange

11 ½ Pattern

Modified Flange

13 ½ Pattern

Fig. 2: Flange Adapters courtesy of Trench

The chart in Figure 6 is used to estimate the cable size for draw lead connections. With the Winding Current determined from the maximum through current by MVA and voltage table (figure 5), you can now use the Bushing Draw Lead Cable table (figure 6) to estimate the possible cross section of the draw lead cable Example: 30 MVA Transformer, 115 kV with 159 Amps; Based on this table we need about 60 mm² cross section of conductor. This would suggest a 2/0 cable Using the table in figure 5 amount of current on the draw leas can be estimated.

Fig. 3: Various flange adapters courtesy of Trench

DRAW LEAD ADAPTERS When the replacement bushing is a different length above the flange a draw lead adapter may have to be used for proper clearances. The two types of adapters are the threaded and the crimp on (figure 4). For taller bushings one may have to use the thread on. This type of adapter is the easiest to use as it connects to the existing stud. For a shorter bushing, the crimp may have to be used. This adapter is more difficult as it requires cutting of the existing stud. The person performing the replacement may not know the draw lead cable size which can lead to problems. The brazed on and crimp adapters each have their own issues when replacing. The braze on requires the work to be performed on the transformer which results in a fire risk, The technician must also be skilled in the use of the tools required for this work. The

Fig. 5: Estimated cable sizes as provided by Trench After determining the estimated current one is able to use the chart in Figure 6, to determine the size of the cable used for the draw lead. Once you have estimated the draw lead cable to be 2/0 it is recommended that you obtain 2 extra crimp type adapters, one size smaller and one size larger than the one you expect to use for the 2/0 cable. Having different sizes will provide a higher degree of assurance that you will have the correct size crimp adapter.

70

Transformers Vol. 2

Estimating cable size With the Winding Current determined from the table in figure 5 you can now use this Bushing draw lead cable table to estimate the possible cross section of the draw lead cable Example: 30 MVA Transformer 115 kV with 159 Amps; Based on this table we need about 60 mm² cross section of conductor. This would suggest a 2/0 cable.

Fig. 6: Bushing draw lead cables sizes provided by Trench

DIMENSIONS BELOW THE FLANGE As Mr. David Geibel, ABB, and Mr. Keith Ellis, Trench, pointed out, at the Bushing Tutorial presented at the 2007 International Conference of Doble Clients, there are several factors both inside and outside the tank that affect the safe and reliable operation of the replacement bushings. Not only are the dimensions above the tank critical but the dimensions below the flange (figure 7) must also be taken into account. We have reviewed some of the items above the flange, now we must take into consideration factors below the flange and inside the tank.

the most part, the new bushing must match the “L” dimension of the old bushing. The “L” dimension dictates the location inside the apparatus of the energized end of the bushing. In the case of circuit breakers, this is critical because it is an integral part of the mechanism. In the case of a transformer, it may be possible to deviate from the original bushing as long as you know the location of the tank wall, lead supports, core frame, coils, tap changing apparatus, etc. Some of these items are energized and some are grounded, and others, like cables, could be from another phase. For example, making a bushing bottom end shorter may bring the energized end closer to grounded supports for the lead structure. Very often, detailed information concerning vintage transformers is available from the OEM against the tank wall before the unit was re-energized. Variation of the “L” dimension can clearly affect the length of the draw lead if one is applied. With the high voltage bushings frequently dictating the height of the transformer cover, there is almost always enough electrical clearances inside the transformer to allow the new low voltage bushings to be a little longer. The new bushings cannot be much shorter than the old bushing because of the available length of the lead connected to the bottom of the bushings. Based on this, a tolerance of – ¼ inch to + 2.0 inch is reasonable for low voltage side bushings up though 69 kV class. For bushings applied to the high voltage of the transformer, the tolerance must be extremely small, +/- ¼ inches, unless transformer data is available. Low side bushings above 69 kV class should follow the tolerances for the high side bushings. The low side tolerance for bushing though 69 kV class often means that it is possible to replace 25 kV class bushings with the IEEE standard 34.5 kV class bushings.

THE “W” DIMENSION L = Length under cover T = Minimum oil coverage W = CT Pocket D = Maximum diameter under cover P = ID of gasket surface Q = OD of gasket surface

Fig. 7: Below the flange dimensions courtesy of ABB

THE “L” DIMENSION In the 2007 bushing tutorial, it is stated that the length of the bushing below the mounting flange is designated by IEEE C57.19.01 – 2000 as the “L” dimension (See Figure 7). The “L” dimension is required to be listed on the bushing’s nameplate. For

All IEEE Standard bushings are supplied with space in the “L” dimension to accommodate Bushing Current Transformers (BCT). This space is known as the “W” dimension or CT Pocket length (see Figure 7). The grounded length of the bushing below the flange is referred to as the CT Pocket Length (W) simply because this is the space under the cover where current transformers can safely be mounted. This space is protected from the voltage “contained” in the bushing by the condenser ground layer and usually by the metal flange extension. This dimension generally dictates the lowest level of the oil but not always. The specific oil level is provided by the “T” dimension (see Figure 9). If no apparatus data is available, it is generally safe to use a longer CT Pocket Length as this makes more room for grounded current transformers. However, it must be noted that as this dimension gets longer the grounded portion of the bushing is moving deeper into the apparatus where it may approach energized objects. In general, adding up to 2 inches is very low risk. It is important to know how much of the bushing must remain under the oil. Bushings are designed to have a portion of the under-

71

Transformers Vol. 2 cover-length not covered with oil. However, it is not always easy to determine how much. In general, if the metal grounded portion of the flange extension is covered when the oil is at its minimum temperature and lowest level, coverage is sufficient. But, in some cases there is no metal flange extension. In other cases, the internal ground sleeve (internal to the bushing) is below the end of the flange extension. In these cases the “T” dimension is the only indication of safe oil level. It is important to keep the oil level as high as the minimum oil level requirements set by the manufacturer. If the oil level is too low, the field around the active portion of the condenser (figure 8) could be out of the oil, and the stresses in this area, especially during over-voltage conditions, could be greater than the gas space can support, resulting in a lower end flashover. Even at normal voltage, when the oil is low the stress at the oil gas interface can easily be great enough to cause partial discharge which would be detected as suspicious gasses. Enough partial discharge could eventual bring about a flashover.

than bushings of just 20 years ago (figures 10 – 12). This has led to issues of interchangeability because not all transformer manufacturers abide by the bushing requirements in IEEE C57.12.00, clause 6.1. It is often the case today that when replacing a newer bushing with an older one, the older larger bushing will not fit through the bushing current transformers. The best way to prevent this situation is for the transformer purchaser to insist that the transformer manufacturer follow clause 6.1 in the C57.12.00 standard.

"D"

Fig. 10: Traditional 350 kV BIL oil filled Bushing

Fig. 11: Solid Insulation “Dry” 350 kV BIL BIL Bushing

Fig. 8: Low oil level

ABB

TRENCH Fig. 12

Fig. 9: Revised CT pocket length

THE “D” DIMENSION Another important dimension is the diameter of the bushing below the flange. Technologies and materials for bushings have improved and bushings have been getting smaller in diameter. Therefore, a bushing produced today could be 40% smaller in diameter

As one can see, the proper replacement of a bushing is more than if it will fit in the hole. Several important factors must be considered for the safe and reliable operation of the replacement. Excellent support is provided by the bushing application engineers from ABB, Trench and PCORE and will assist in selecting the proper replacement bushing that will provide reliable service. Several manufacturers have excellent cross reference programs on their web sites.

BUSHING STORAGE AND HANDLING It is recommended that spare bushing tests (follow procedures by the manufacturer of the test equipment being used) be per-

72 formed on bushings that are in storage. Just because the bushing is new does not mean that it is in a condition to be placed into service. It is important that bushing be stored per the manufacturer’s recommendation. Different types of bushings have specified handling and storage requirements. Some suggestions by various manufacturers are: To avoid damage, never place a lifting sling around the silicone rubber sheds when installing or removing a bushing with Silicone Rubber Insulators (SRI). Bushings that are Epoxy Resin Insulators (ERI) are susceptible to ultraviolet de-coloration and after 10 years of exposure to UV the ERI may need to be replaced. The lower end of the bushing must be protected from sunlight if stored outdoors. (Indoor storage is preferred for all types of bushings) Proper storage of Epoxy Resin Impregnated Paper bushings (ERIP) requires the inboard end of the bushing be under oil since this end is the actual epoxy resin condenser of the bushing. Several manufacturers offer this type of “tank” while often times the devices are fabricated in-house.

CASE STUDY A recent call concerned a problem with the C2 tests performed on bushings that had just been replaced. After performing some troubleshooting, by grounding the bushing flanges, it was determined that the bushing flange on the new bushings were not properly grounded. During this troubleshooting it was determined that the new bushing flanges were not as thick as the old bushing flanges. The old hardware had been used for the replacement and this resulted in the nuts bottoming on the “shoulder” of the bolt. Although the nut appeared to be properly tightened the “bottoming out” of the bolt resulted in the flange of the bushings and the flange of the transformer not making a good solid grounded connection. New hardware was used and proper C2 results were attained.

REFERENCES World Wide Web Bushings for Power Transformers by Keith Ellis THE IMPORTANCE OF PROPER BUSHING REPLACEMENT tutorial by Keith Ellis (Trench Electric) and Dave Geibel (ABB) at the 2007 International Conference of Doble Clients - Boston, Massachusetts

Transformers Vol. 2 Keith Hill has been employed at Doble Engineering since 2001, and currently works as a Principal Engineer in the Client Service Department. Keith has over 38 years of experience in substation maintenance, electrical testing, and project management. Mr. Hill is a member of IEEE, a former NETA certified technician, and is a level I and II certified thermographer. Prior to Doble, Mr. Hill was the Electrical Supervisor of Engineering Services for a major refinery. Mr. Hill has published several papers relating to equipment testing and maintenance for various conferences and publications. At the present time, Keith serves as the secretary of the Doble Arresters, Capacitors, Cables, and Accessories committee. Keith received his BS from the University of Houston with a major in Electric Power.

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

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alabama 1

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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27

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

46

47

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

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florida 50

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C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

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Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

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Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

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Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

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missouri 114

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117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

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143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

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145

new york 139

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141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

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HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

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148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

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168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

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189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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207

208

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210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: ●● The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. ●● NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. ●● A Registered Professional Engineer will review all engineering reports. ●● All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). ●● The firm is a well-established, full-service electrical testing business.

Setting the Standard

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TRAX

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MWA 3-Phase Ratio and Winding Resistance Analyzer

DELTA4000 12 kV Power Factor (tan delta) Tester

Get The Full Picture of Your Transformers’ Health Transformer health is paramount to ensuring the stable transmission and distribution of electrical energy. Maintaining these costly assets can be difficult if you don’t have the proper tools. The full line of Megger Transformer Testing Solutions delivers the broadest range of diagnostic testing in the industry to help extend the life of your transformer, so you can Power on.

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Fully integrated, complete transformer testing solution customized to meet your needs