Substation: Design Manual
This document was uploaded by user and they confirmed that they have the permission to share it. If you are author or own the copyright of this book, please report to us by using this DMCA report form. Report DMCA
Overview
Download & View Substation: Design Manual as PDF for free.
More details
- Words: 69,986
- Pages: 445
Loading documents preview...
SUBSTATION DESIGN MANUAL
December 2012 Asset Management Department, TNB Distribution Division
1
Chapter 1: Introduction Introduction Background
1 1
i
Objectives Scope of this Manual
3 3
Chapter 2: Substation Design & Configuration
2
Overview Design Philosophy Substation Categories Major Components
6 7 8 10
Electrical Clearance Site Considerations Operation and Maintenance Considerations Safety Considerations
12 13 17 17
Chapter 3: PMU, PPU and 33kV SSU Design
3 4
5
Introduction 18 Pencawang Masuk Utama (PMU) 18 Pencawang Pembahagian Utama (PPU) 26
Mini PPU 34 33kV Primary Switching Station (33kV SSU) 50 Testing and commissioning 54
Chapter 4: P/E, 11kV SSU and S/S Design Introduction 55 Indoor Distribution Substation (Indoor P/E) 60 11kV Primary Switching Station (11kV SSU) 82 Outdoor Distribution Substation (Outdoor P/E) 85
Switching Station (S/S) Compact Substation Unit (CSU) Pole Mounted Substation (PAT) Pole Mounted Substation (PAT) with RMU
93
95 105 125
Chapter 5: Design for Substations with Special Requirements Mobile SSU
6 7
8
130
Flood Prone Areas
153 211 239 252
Feeder Pillar 257 Current Transformer (CT) 264 Potential Transformer (PT) 270
Chapter 7: Secondary Equipment Overview Protection/Protective Relaying Control DC & AC Auxiliary Systems Heater
273 273 284 289 294
DESIGN MANUAL The TNB power distribution network includes medium and low voltage power lines, substations, switching stations and metering system. Proper design and construction of the substations is aimed to ensure a reliable and robust electricity distribution network. This is important in order to achieve optimum system performance, reduce system losses and improve customer satisfaction.
144
Chapter 6: Primary Equipment Transformers Switchgear Neutral Earthing System Medium Voltage Fuse
SUBSTATION
Secondary Wiring
296
Metering
297
Communications
302
Other Secondary Equipment
308
This manual covers the distribution substations and related equipment. The manual is a compilation of various documents, circulars and requirements pertaining to the design and construction of the distribution network.
Chapter 8: SCADA System
9
10
Overview Master System Communication System
320 322 324
Chapter 9: Earthing Overview
330
Earth Connections Above-Ground
334
Earth Connections Below-Ground
353
Chapter 10: Fire Fighting System Overview 363 Fire System Requirements for TNB Substations 364
11
Remote Terminal Unit (RTU) 325 SCADA-ready Substations 329
System Components
372
Chapter 11: New Technology Mobile Equipment 375 Energy Efficient Distribution Transformers 384
Cast Resin and Synthetic Ester RMU CB Containerised PPU
390 395 402
December 2012 Asset Management Department TNB Distribution Division
Substation Design Manual
December 2012
Asset Management Department Distribution Division Tenaga Nasional Berhad Wisma TNB Jalan Timur, Petaling Jaya Selangor
Disclaimer: This Substation Design Manual is a document providing technicians, engineers, and managers of the Distribution Division of Tenaga Nasional Berhad with an understanding of proper substation system design. The information in this document has been prepared in good faith and represents the Asset Management Department’s intentions and opinions at the date of issue. The Asset Management Department may change any information in this document at any time.
ii
Substation Design Manual
Acknowledgement We would like to express our deepest gratitude to the management of the Distribution Division, for giving us the opportunity to develop the TNB Distribution Division’s Substation Design Guide. Special thanks to Hj. Ismail Mohd Din (SGM), Hj. Esmet Sidqie bin A.Muttalib, Young Zaidey bin Yang Ghazali, Sharizal bin Shamuri, Hannah binti Ahmad Rosli and Mohd Khairul Ikram bin Ghazali from Substation Section, Engineering Service Unit, Asset Management Department for their valuable contribution and assistance in developing this manual. Our appreciation goes to Ideris Shamsudin from Pejabat Pengurus Kawasan Petaling Jaya; Tan Siew Hwa from Unit Perancangan dan Pembangunan Sistem; Hj. Muhamad Subian Sukaimy, Dr. Abd Rahman bin Khalid and Zaini Zainal from Protection; Mohd Jaffery Raffles and Sek Yean Ling from SCADA; Noor Adnan Abdul Aziz, Mohd Fatani bin A Rahman, Ahmad Ridhaudin Abdul Razak, Mohd Fauzi bin Mohd Ismail and Ahmad Suhaimi bin Mohamed from Jabatan Perancangan & Pembangunan Aset; Mohd Faris Ariffin from Overhead Section, Engineering Service Unit; Zahari Dollah and Mohammad Khuzairee bin Ibrahim from Unit Perkhidmatan Pengurusan Aset; Mohd Fahami Jaapar and Kamarul Azam Abu Kassim from Unit Perkhidmatan Perjangkaan; and finally Mohd Nazri bin Rahmat and Syamsul Fahrizal bin Samsu from Pengurus Kawasan Kulim. The project team would also like to express our gratitude to Pairolani bin Safari @ Hj Hashim and Govindan Gopal from ILSAS, Bangi. Not forgetting Nurul Azlina Abdul Rahman, Ir. Noradlina Abdullah and Mohd Aizam bin Talib from TNB Research Sdn. Bhd. and Muhamad Faiq Mohd Rozi from MTM Sdn. Bhd. Our appreciation also goes to the Uniten Team, comprising Mohd Zafri Baharuddin, Fareha binti Mohd Zainal, Dr. Noor Miza binti Muhamad Razali, Adzly Anuar, Nadhira binti Mat Nashim, Shahrul Iznan, Nurul Aishah binti Mohd Rosdi, Redia binti Mohd Redzuwan, Kamalambigai A/P Munusamy, Nurulaqilla binti Khamis and Norizzati Shafinaz binti Sabri for their untiring efforts and patience towards the successful completion of this manual. We welcome any feedback and improvement advice that will be useful for future revisions of this manual. Thank you. Ir. Wan Nazmy bin Wan Mahmood General Manager, Engineering Services, Asset Management Department, Distribution Division, TNB.
Substation Design Manual
Foreword VP Distribution Division, Datuk Ir. Baharin Din As Malaysia progresses to achieve Vision 2020, TNB plays a vital role in ensuring sufficient and strategic injection of electricity power is available by the building Transmission Main Intake Substations, Primary Distribution Substations and Distribution stations. With continuous expansion of the distribution network and its ever challenging environment, it is essential that the spirit of “do it right the first time” be instilled among TNB personnel and appointed contractors. Properly designed substations and correct installation of related equipment will ensure reliable and quality power supply, longer equipment lifespan and improved system security as well as safety. From time to time, various technical and engineering circulars and guidelines have been issued to ensure standard practices on substation design, construction and installation are practiced among the states and areas. However, there is a need to compile these guidelines in a form of a practical handbook to be made more available and accessible for easy reference throughout the Distribution Division. TNB Distribution Division through the Distribution Asset Management Department, in collaboration with ILSAS and Universiti Tenaga Nasional, have taken a step forward to develop this manual which incorporates the latest technological changes in substation equipment and design, existing relevant instructions and circulars, as well as approved technical specifications. Therefore, I would like to take this opportunity to congratulate the project team from the Asset Management Department, as well as ILSAS, TNB Research and Universiti Tenaga Nasional, for their impressive effort in developing this useful manual for substation design for the distribution system. Thank you.
iii
iv
Substation Design Manual
Table of Contents Chapter 1:
Introduction ..............................................................................1
1.1.
Background ...................................................................................1
1.2.
Objectives .....................................................................................3
1.3.
Scope of this Manual .....................................................................3
Chapter 2:
Substation Design & Configuration ...........................................6
2.1.
Overview .......................................................................................6
2.2.
Design Philosophy .........................................................................7
2.3.
Substation Categories ....................................................................8
2.4.
Major Components ...................................................................... 10
2.5.
Electrical Clearance ..................................................................... 12
2.6.
Site Considerations ...................................................................... 13
2.7.
Operation and Maintenance Considerations ................................ 17
2.8.
Safety Considerations .................................................................. 17
Chapter 3:
PMU, PPU and 33 kV SSU Design ............................................18
3.1.
Introduction ................................................................................ 18
3.2.
Pencawang Masuk Utama (PMU) ................................................. 18
3.3.
Pencawang Pembahagian Utama (PPU) ....................................... 26
3.4.
Mini PPU ..................................................................................... 34
3.5.
33kV Primary Switching Station (33 kV SSU) ................................. 50
3.6.
Testing and commissioning .......................................................... 54
Chapter 4:
P/E, 11 kV SSU and S/S Design ................................................55
4.1.
Introduction ................................................................................ 55
4.2.
Indoor Distribution Substation (Indoor P/E) ................................. 60
4.3.
11 kV Primary Switching Station (11 kV SSU) ................................ 82
4.4.
Outdoor Distribution Substation (Outdoor P/E) ............................ 85
Substation Design Manual
4.5.
Switching Station / Stesen Suis (S/S) ............................................ 93
4.6.
Compact Substation Unit (CSU) ................................................... 95
4.7.
Pole Mounted Substation (PAT) ................................................. 105
4.8.
Pole Mounted Substation (PAT) with RMU ................................ 125
Chapter 5:
Design for Substations with Special Requirements ............... 130
5.1.
Mobile SSU ............................................................................... 130
5.2.
Flood Prone Areas ..................................................................... 144
Chapter 6:
Primary Equipment .............................................................. 153
6.1.
Transformer .............................................................................. 153
6.2.
Switchgear ................................................................................ 211
6.3.
Neutral Earthing System ............................................................ 239
6.4.
Medium Voltage Fuse ............................................................... 252
6.5.
Feeder Pillar .............................................................................. 257
6.6.
Current Transformer (CT) .......................................................... 264
6.7.
Potential Transformer (PT) ........................................................ 270
Chapter 7:
Secondary Equipment .......................................................... 273
7.1.
Overview .................................................................................. 273
7.2.
Protection/Protective Relaying .................................................. 273
7.3.
Control...................................................................................... 284
7.4.
DC & AC Auxiliary Systems......................................................... 289
7.5.
Heater ...................................................................................... 294
7.6.
Secondary Wiring ...................................................................... 296
7.7.
Metering ................................................................................... 297
7.8.
Communications ....................................................................... 302
7.9.
Other Secondary Equipment ..................................................... 308
v
vi
Substation Design Manual
Chapter 8:
SCADA System ...................................................................... 320
8.1.
Overview ................................................................................... 320
8.2.
Master System .......................................................................... 322
8.3.
Communication System ............................................................. 324
8.4.
Remote Terminal Unit (RTU) ...................................................... 325
8.5.
SCADA-ready Substations .......................................................... 329
Chapter 9:
Earthing ................................................................................ 330
9.1.
Overview ................................................................................... 330
9.2.
Earth Connections Above-Ground .............................................. 334
9.3.
Earth Connections Below-Ground .............................................. 353
Chapter 10: Fire Fighting System .............................................................. 363 10.1.
Overview ................................................................................... 363
10.2.
Fire System Requirements for TNB Substations .......................... 364
10.3.
System Components .................................................................. 372
Chapter 11: New Technology ................................................................... 375 11.1.
Mobile Equipment ..................................................................... 375
11.2.
Energy Efficient Distribution Transformers ................................. 384
11.3.
Cast Resin & Bio-Degradable Oil Immersed Transformers ........... 390
11.4.
RMU CB ..................................................................................... 395
11.5.
Containerised PPU ..................................................................... 402
Appendix ................................................................................................... 406 Appendix A: Metering Calculations ......................................................... 406 Appendix B: CPPU Bukit Gambir Earthing Calculations ............................ 407 Appendix C: IP – Ingress Protection Ratings............................................. 428 List of Abbreviations ................................................................................... 431 Glossary ..................................................................................................... 435
Introduction
Chapter 1: 1.1.
Introduction
Background
Electricity distribution is the delivery of electricity from the transmission network to end users or customers through the distribution network as shown in Figure 1-1. The TNB power distribution network includes medium and low voltage power lines and cables, substations, switching stations and metering system. Typical medium voltage in the network is 11 kV and 33 kV. Some parts of Perak and Johor distribution network consist of 6.6 kV and 22 kV systems; however these are being phased out in stages. Distribution substations consist of equipment such as transformers and circuit breakers, and are interconnected by a network of underground cables and overhead power lines. There are several types of distribution substations which can either be of outdoor or indoor design, and either stand-alone or attached to a building. The functions of a distribution substation may include a combination of the following: (a) To manage the distribution network by switching elements in and out of the system to transmit power from main intake stations or other networks to load centres and in some cases direct to consumers. (b) To change or transform voltage levels within the distribution network, such as 33kV/11kV and/or 11kV/0.4kV (c) To provide data concerning system parameters (voltage, current flow, power flow) for use in operating the utility system. (d) To isolate faulted section from the healthy sections of the distribution network. (e) To allow an element to be isolated from the rest of the distribution network for maintenance or repair.
1
1
GENERATION
Substation Design Manual
132kV
TRANSMISSION
132kV
275kV
132kV/275kV
275kV/132kV
275kV/132kV
PMU 132kV/11kV
PMU 132kV/33kV
PPU
DISTRIBUTION
2
PPU 33kV/11kV 33kV SSU
11kV SSU
S/S
P/E 11kV/0.4kV
CUSTOMER
1
Residential
Commercial
Figure 1-1: Electricity supply network
Industrial
Introduction
1.2.
Objectives
Proper design and construction of the substations is aimed to ensure a reliable and robust electricity distribution network. This is important in order to achieve optimum system performance, reduce system losses and improve customer satisfaction.
1.3.
Scope of this Manual
This manual covers the distribution substations and related equipment. The manual is a compilation of various documents, circulars and requirements pertaining to the design and construction of the distribution network. Topics in this manual are arranged according to the following chapters: Chapter 2: Substation Design & Configuration This chapter provides an overview of the different types of substations, along with their design philosophy and type selection criteria. Chapter 3: PMU, PPU and 33 kV SSU Design This chapter covers main design criteria for Main Intake Substation/Pencawang Masuk Utama (PMU), Primary Distribution Substation/Pencawang Pembahagian Utama (PPU), and 33 kV Primary Switching Station/Stesen Suis Utama (33 kV SSU). Chapter 4: P/E, 11 kV SSU and S/S Design This chapter details out the main design criteria for all distribution substations and switching stations of 11 kV and below. These are the indoor and outdoor substations/pencawang elektrik (P/E), compact substation units (CSU), pole mounted substations (H-pole), 11 kV primary switching station/stesen suis utama (11 kV SSU) and switching stations/stesen suis (S/S). Chapter 5: Design for Substations with Special Requirements This chapter covers substations under special requirements such as Mobile SSU for rapid deployment situations and mitigation construction methods for substations located in flood prone areas.
3
1
1
4
Substation Design Manual
Chapter 6: Primary Equipment This chapter describes the substation primary equipment such as transformers, switchgears, Neutral Earthing Resistors (NER) and feeder pillars. Chapter 7: Secondary Equipment This chapter explains secondary equipment that covers the functions of protection, metering and communication. These include instruments, relays, control panels, DC and LV supply and optical fibres. Chapter 8: SCADA System This chapter briefly explains the structure of the SCADA system for remote monitoring and control of geographically dispersed assets to Regional Control Centres. This chapter also explains the main functions and equipment related to this system. Chapter 9: Earthing The chapter primarily covers the objectives of good earthing design, the earth connections above and below ground levels and the earthing components used. Chapter 10: Fire Fighting System Fire fighting system requirements for TNB substations are discussed in this chapter. The fire fighting system components are also introduced. Chapter 11: New Technology The chapter covers several new technologies which are introduced to the distribution system in order to increase system reliability, security and efficiency. The chapter covers mobile equipment, RMU circuit breaker and containerised PPU.
Introduction
This manual is a mandatory guide for distribution substation design requirements in any Region and Area (kawasan). Additional supporting documents to accompany this manual include: 1.
Electricity Supply Application Handbook (ESAH), where dimensions of the various types of built up P/E design is detailed out.
2.
Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian, for schematic drawings of standard PPU design.
3.
Distribution Planning Guidelines, where basic principles and general policies of distribution system planning are outlined.
4.
Underground Cable System Design Manual, for interconnecting cable specifications.
5.
Penyambungan Pengalir Kabel Bawah Tanah, as a guideline for conductor connection techniques.
6.
Capacitor Bank Guideline, for information on capacitor banks inside substations.
7.
For testing and maintenance methods, please refer to the latest editions of the following documents: o o o
Transformer Maintenance Manual Switchgear Maintenance Manual Cable Maintenance Manual
5
1
6
2
Substation Design Manual
Chapter 2: Substation Design & Configuration 2.1.
Overview
Substation design depends on many factors, either from geographical, technical, regulatory, or demographic requirements which determine the type of substation to be constructed. The main issues in determining the design of a particular substation are reliability and cost. A good design attempts to strike a balance between these two, to achieve sufficient reliability at the optimum cost. Sufficient land area is required for installation of equipment with necessary clearances for electrical safety and sufficient access to perform operation and maintenance of components such as transformers and circuit breakers. In dense urban areas where land is costly, gas insulated switchgear may save money overall. The design should also allow easy expansion of the station, if required. Environmental effects of the substation must be considered, such as drainage, noise, water supply and road traffic. Earthing must be calculated to protect equipment in case of a short circuit in the distribution system. Ideally, the substation site must be reasonably central to the distribution area to be served.
Introduction
2.2.
Design Philosophy
TNB Distribution Division substations are designed with objectives to ensure: (a) Correct engineering practice (b) Compliance with acts and regulations (c) Availability, reliability and security of supply (d) Optimisation of cost – Using TNB Engineering economics model (Financial Evaluation Template from MV Planning Guideline) (e) Ease of construction, operation and maintenance of substations (f) Safety of public, personnel and equipment (g) Customer requirements are fulfilled (h) Flexibility to meet changing demand (i)
Adoption of green initiatives
(j) Consideration of climate and environmental change (k) Positive corporate image (l)
7
Prolonged equipment life through life cycle and risk assessment
2
8
Substation Design Manual
2.3. 2
Substation Categories
Substations are categorised according to the voltages they handle and whether the substation performs voltage transformations or only switching functions.
2.3.1.
Transmission Main Intake / Pencawang Masuk Utama (PMU)
Transmission Main Intake Substation / Pencawang Masuk Utama (PMU) is the interconnection point of 132 kV or 275 kV to the distribution network. The typical transmission capacity and voltage transformation provided at the PMU are as follows:
132/33kV, 2 x 90 MVA 132/11kV, 2 x 30 MVA
Other voltage transformations are also catered for based on special site requirements.
2.3.2.
Primary Distribution Substation / Pencawang Pembahagian Utama (PPU)
Primary Distribution Substation is normally applicable to 33 kV and 22 kV interconnecting networks with 11 kV networks. It provides capacity injection into 11 kV network through a standardized transformation of 33/11 kV or 22/11 kV. Typical transformer capacities used in PPU are 7.5 MVA, 15 MVA and 30 MVA.
2.3.3.
Primary Switching Stations / Stesen Suis Utama (SSU)
Primary Switching Stations / Stesen Suis Utama (SSU) are stations with circuit breakers, established to serve the following function:-.
To supply a dedicated bulk consumer at 33 kV, 22 kV or 11 kV. To provide bulk capacity injection or transfer from a PMU/PPU to a load centre for further localized distribution.
This manual will detail out the 33 kV SSU and 11 kV SSU.
Introduction
2.3.4.
Distribution Substation / Pencawang Elektrik (P/E)
A distribution substation / Pencawang Elektrik (P/E) is a combination of switching, controlling, and voltage step-down equipment arranged to reduce medium voltage (MV) of 33 kV, 22 kV and 11 kV to low voltage (LV) for residential, commercial, and industrial loads. Typical capacity ratings are 1000 kVA, 750 kVA, 500 kVA, 300 kVA and 100 kVA. The design of these substations varies widely according to network requirement. Some distribution substations would include a dedicated customer substation with a metering room. This substation would be similar to the typical distribution substation except that all of its capacity would be reserved for the service of one customer. Coordination with the customer is of primary importance in determining the technical requirements. Standardized M & E designs of 11/0.4 kV substations are available in the latest version of the Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian, TNB.
2.3.5.
9
Switching Stations / Stesen Suis (S/S)
Switching Stations / Stesen Suis (S/S) are stations with RMU or VCB which normally do not contain transformers and operates only at a single voltage level to distribute to feeders.
2
10
Substation Design Manual
2.4. 2
Major Components
The specifications for major components are determined by the parameters of the power system and their expected functionality when in operation. The following are some functional descriptions of major components in a substation. Selection of equipment requires the utmost consideration. Cost, schedule, and performance penalties may be incurred as a result of improper selection. Other associated subsystems in the electrical installation of substations include protection, metering, control and communication systems, earthing system, fire fighting system, lighting system and security system.
2.4.1.
Transformers step up or step down voltages and transfer power to different voltage levels. Power transformers work at the MV level and above. Distribution transformers function to step down to low voltage distribution voltages. Local transformers are distribution transformers that provide supply locally to the substation only.
2.4.2.
Transformer
Switchgear
Switchgear is a switching device used to control, protect and isolate electrical network. It may comprise of disconnectors, switches, fuses or circuit breakers. Typically, for MV switchgears, they are compartmentalised and metalenclosed. Configuration may be of single or double busbar system. o A busbar is a strip or bar of copper, brass or aluminium that conducts electricity within a substation. o Busbars connect incoming and outgoing circuits.
Introduction
2.4.3.
Potential Transformers
Potential Transformers (PT) function to step down voltage for measurements, protection and control. They are located on the feeder side of the circuit breaker. There are also known as Voltage Transformers (VT).
2.4.7.
Lightning Arrestors
In overhead installations, lightning arrestors function to discharge overvoltage surges to earth and protect the equipment insulation from lightning surges. They are connected between phase conductor and earth. Located at the end of an incoming line and also near transformer terminals, they form the first line of defence against surges into the substation.
2.4.6.
Disconnector/Isolator
Disconnector/isolators function to provide isolation from live parts for the purpose of maintenance. They can only be operated in off-load condition. They are located inside the switchgear. Separate isolators are used for pole-mounted installations.
2.4.5.
Circuit Breaker
The circuit breaker is a component inside the switchgear. A circuit breaker is an automatically operated electrical switch designed to protect an electrical circuit from damage caused by overload or short circuit. Its basic function is to detect a fault condition and, by interrupting continuity, to immediately discontinue electrical flow. They are located at designated switching points or both ends of protected zones.
2.4.4.
11
Current Transformers
Current Transformers (CT) steps down current for load measurement, protection and control.
2
12
2
Substation Design Manual
2.5.
Electrical Clearance
2.5.1.
Safety Clearance
Safety clearance is the minimum distance to place partitions of safety barriers from normally exposed live parts while working in a substation. The minimum safety clearance is shown in Table 2-1.
2.5.2.
Working Clearance
Working clearance is the minimum safe distance to be observed between normally exposed live parts and any person or tools while working in a substation. The minimum working clearance is shown in Table 2-1.
2.5.3.
Phase Clearance
Phase-to-earth and phase-to-phase clearances should be coordinated to ensure that possible flashovers occur from phase to earth rather than from phase to phase. The minimum phase clearance is shown in Table 2-1. Table 2-1: Minimum phase clearance in millimetres Description
275 kV
132 kV
33 kV
22 kV
11 kV
Safety clearance between earth and the nearest point not at earth potential of an insulator
2440
2440
2440
2440
2440
Safety clearance between earth and the nearest live unscreened conductor
4570
3500
2740
2740
2590
Working clearance between any person or person with tools to earth
3050
2440
1220
1220
914
Phase/Live metal to earth
2082
1270
381
279
203
Phase/Live metal to different phase
2388
1473
432
330
254
Introduction
2.6.
Site Considerations
2.6.1.
General
It is becoming increasingly important to perform initial site investigations prior to the procurement of substation site. The following factors should be evaluated when selecting a substation site: (a) Location of present and future load centre (b) Location of existing and future sources of power (c) Availability of suitable right-of-way and access to site by overhead or underground transmission and distribution circuits (d) Location of existing distribution lines (e) Access roads into the site for heavy equipment under all weather conditions (f) Possible objections regarding appearance or noise (g) Soil resistivity (h) Drainage and soil conditions (i) Cost of earth removal, earth addition, and earthmoving (j) Atmospheric conditions: salt and industrial contamination (k) Cost of cleanup for contaminated soils or buried materials (l) Space for future as well as present use (m) General topographical features of site and immediate neighbouring areas; avoidance of floodplains or wetlands (n) Public safety and public concern; avoidance of schools and playgrounds (o) Security from theft, vandalism, damage and sabotage (p) Total cost including transmission and distribution lines with due consideration of environmental factors (q) Possible adverse effects on neighbouring communications facilities
2.6.2.
Appearance
Appearance is becoming increasingly important to the public. In some areas, zoning regulations and suggestions by local authorities often mean screening, painting, or other measures to improve appearance. The general trend is to locate substations in a way that they are not strikingly visible to the public.
13
2
14
Substation Design Manual
A substation set back from a heavily travelled road may be acceptable with little or no architectural treatment.
2
Substations strategically located facing main roads can be used to place 1 company contact information . Generally, it is better to use complementary rather than contrasting colours. 2 Colouring can be used to blend substation equipment into the background . Lighting in the compound is typically a means to deter vandalism and theft. It also provides safety for crews who may be performing maintenance at night.
2.6.3.
Public Safety
Substations should be safe for people who may have occasion to be near them. The primary means of ensuring public safety at substations is by the erection of a suitable barrier such as a fence. Appropriate warning signs should be posted on the substation’s barrier fence or walls. For each substation site, assess whether standard signs are sufficient. Special bilingual signs or additional signs, such as “No Trespassing” / “Dilarang Masuk”, may be advisable for some areas.
2.6.4.
Effluent
Effluent is water pollution, such as liquid waste or sewage from industrial facilities discharged into surface waters. Upon the failure of a container filled with a pollutant, such as oil in a transformer or oil circuit breaker, no harmful quantity of such pollutant (oil) may be allowed to enter a navigable waterway. For PPU, it is necessary to have a Spill Prevention Control and Countermeasures (SPCC) plan of action for disposing of effluent, should spills or leaks occur. 1
Arahan Naib Presiden (Pembahagian) TNB (Dasar Perkhidmatan dan Amalan Kejuruteraan), Bil. A08/2012, Penceriaan Pencawang Pembahagian Utama dan Pencawang Elektrik Jenis Bangunan TNB. 2 Arahan Naib Presiden (Dasar Perkhidmatan dan Amalan Kejuruteraan), Bil. A02/2010, Penggunaan Warna Cat yang Dibenarkan untuk Dinding Luar Semua Bangunan Pencawang Baru TNB.
Introduction
2.6.5.
Weather
As dependence on the use of electricity grows, it is increasingly important that substations operate more reliably in extremes of weather than in the past. 2.6.5.1.
Rain
Malaysia’s climate experiences an average of 250 centimetres of rain per year. As such, a substation should be designed to be operable under predictable conditions of rainfall. Flood prone areas are to be avoided. Mitigation methods for substations in flood prone areas are explained in Chapter 5.2. Rain can also lead to soil erosion. Areas prone to soil erosion such as steep slopes are to be avoided. 2.6.5.2.
Lightning
Malaysia has among the highest number of lightning strikes per year in the world. Typically, for a tropical country, the keraunic level ranges between 100 to 180 Thunderstorm days per year (based upon the Malaysian Meteorological Office). Lightning can cause transient conditions which can trip circuit breakers and/or damage equipment. Lightning surge arresters are the measure normally employed for pole-mounted substation lightning protection. For substation buildings, shielding is provided by lightning rods. 2.6.5.3.
Humidity
Being in a tropical climate, the equipment must also operate under high humidity conditions. Consideration should be given to install differential thermostat-controlled heating in cabinets such as circuit breaker enclosures where condensation could be a problem. 2.6.5.4.
15
Altitude
Equipment that depends on air for its insulating and cooling medium will have a higher temperature rise and a lower dielectric strength when operated at higher altitudes. Dielectric strength of air, current ratings of conductors
2
16
2
Substation Design Manual
operated in air, and ambient temperatures should be corrected for altitude variation. Applications above normal specified elevation limits are considered special, and the manufacturer should be consulted for a recommendation.
2.6.6.
Other Considerations
2.6.6.1.
Wildlife and Livestock
A substation should be protected from wildlife and livestock. The primary means of protection is the perimeter barrier. This is generally a chain link fence that keeps out larger animals. It may also be necessary to have rodent and/or reptile barriers. Insect screening should be applied where local experience indicates it is beneficial. Avoiding attractive nesting and perching sites usually minimizes damage by birds. Adequate clearances and insulation should be provided to prevent electrocution of wildlife. 2.6.6.2.
Airborne Foreign Material
Airborne seeds, leaves, debris, dust, and salts that are local phenomena could be a problem. Build-up could occur that would compromise electrical insulation or interfere with cooling. Appropriate prevention measures should be included in the design of a substation expected to be exposed to such contamination. 2.6.6.3.
Reactive Gasses
If a substation is to be situated next to a sewage treatment plant, landfill or waste disposal facility, the developer must take preventive measures to avoid reactive gasses from entering the substation area. These measures must be proven before approval can be considered. If reactive gasses from nearby sources cannot be contained, it is a priority to relocate the substation to another location. If relocation is infeasible due to prior planning approval or etc., the developer must provide all undertaking related to the substation.
Introduction
2.7.
Operation and Maintenance Considerations
The substation site must have infrastructure facilities such as roads, drains, water pipes, and sewage system, whichever is required. Substation sites should also consider land setback requirements, road widening reserves, rivers, routes in and out of street corners and reserve buildings or space for future expansion. For simplicity and ease of maintenance, substation equipment arrangements, electrical connections, signs, and nameplates should be as clear and concise as possible. A substation may occasionally experience emergency operating conditions. The provision of additional load of some equipment or connections should always be considered and appropriately accounted for in the design. Substation design needs to allow maintenance to be accomplished with a minimum impact on a substation’s operation. Allocation of adequate working space is necessary. In selecting equipment, consider the service intervals recommended by the manufacturers and past experience in using a particular manufacturer’s equipment.
2.8.
17
Safety Considerations
It is paramount that substations are safe for the general public and for operation and maintenance personnel. Practical approaches include the employment and training of qualified personnel, appropriate working rules and procedures, proper design such as on earthing systems, and correct construction. The safeguarding of equipment also needs to be considered in substation design.
2
18
Substation Design Manual
Chapter 3: Design 3
3.1.
PMU, PPU and 33 kV SSU
Introduction
This chapter presents general information concerning the design of the physical arrangement of PMU, PPU and 33 kV SSU. It describes various types of substations, illustrates typical layouts, and presents technical criteria of these substations.
3.2.
Pencawang Masuk Utama (PMU)
3.2.1.
Overview
Main Intake Substation / Pencawang Masuk Utama (PMU) is the interconnection point between Transmission’s HV network to the Distribution’s 33 kV, 22 kV and 11 kV MV network. Distribution Division is responsible for the MV primary and related secondary equipment within the PMU. Main Intake Substations / Pencawang Masuk Utama (PMU) are managed by Transmission Division. However, Distribution Division is responsible for the operation and maintenance of MV circuit breakers, panels and MV cable panel inside the PMU. Figure 3-1 is a PMU line diagram showing the responsibility boundary over the assets, operations and maintenance work between Transmission and Distribution.
PMU, PPU and 33kV SSU Design
19
M HV Busbar R
TNBT
TNBD
M R OG NER
Bus Coupler
HV Incomer (CB) Y
Y
Δ
Δ Y
NER
Main Reserve Outgoing Neutral earth resistor Asset Boundary Operation & Maintenance Boundary
Y
MV Incomer (CB) M
MV Busbar
R
O/G Feeder
Bus Coupler
O/G Feeder
Figure 3-1: Line diagram and boundary of responsibility of a TNB PMU
Figure 3-2: PMU with outdoor Air Insulated Switchgear (AIS) switchyard
3
20
Substation Design Manual
3
Figure 3-3: PMU with indoor Gas Insulated Switchgear (GIS)
Figure 3-4: 132 kV Gas Insulated Switchgear (GIS)
PMU, PPU and 33kV SSU Design
3.2.2.
21
PMU Layout
Total land area required for a PMU depends mainly on the type of the primary equipment selected to be used. The equipment is usually classified by the switchgear; being either Air Insulated Switchgears (AIS) or Gas Insulated Switchgears (GIS). AIS equipment has to be installed in a switchyard and thus require much more space than GIS equipment. Additionally if a capacitor bank is required in the PMU, the land requirement will further increase. Minimum land requirements for PMU are summarised in Table 3-1 below. Table 3-1: PMU minimum land requirements Minimum Land Size
Equipment Insulation
(NOT inclusive of Land Setback)
Air Insulated Switchgear (AIS)
(a) 130 m x 130 m (b) 160 m x 150 m (with capacitor bank)
Gas Insulated Switchgear (GIS)
(a) 60 m x 80 m (b) 140 m x 75 m (with capacitor bank)
AIS PMU consists of a large switchyard with equipments that are controlled from a nearby substation building. Typical arrangement of the AIS PMU substation building is shown in Figure 3-5 and switchyard arrangement in Figure 3-6. An example GIS PMU layout is shown in Figure 3-7.
AC Room
Toilet
Control Room
Telecontrol
Battery Room
Relay Room
LV Switchgear
Figure 3-5: Major equipment in the AIS substation building
3
22
Substation Design Manual
(2)
(1)
(3)
(4)
3
(5)
1. 2. 3.
4. 5. 6.
7.
8.
9.
(6)
(7)
(8) (9)
Fly bus Lightning shield conductor Busbar Aluminium Tubular Supported on post insulators Circuit breaker Open and close operations Power transformer Isolators/disconnects Isolation duty Located on both sides of circuit breaker No current make or break rating Current transformer Step down current measurement Protection and control Potential transformer Step down voltage measurement Protection and control Surge arrestor Discharge over-voltage surges to earth
Figure 3-6: Major equipment in the AIS PMU switchyard
PMU, PPU and 33kV SSU Design
23
3
Figure 3-7: Layout of a GIS PMU and typical locations of major components
24
Substation Design Manual
3.2.3.
Electrical Criteria
The electrical design guideline is prepared based on the following system configuration: Table 3-2: Typical ratings in a PMU Components
3 Transformers
132 kV AIS Switchgear
132 kV GIS Switchgear
System Configuration
275/132/33 kV at 240, 180 MVA 132/33 kV at 90, 45, 30, 15 MVA 132/22 kV at 60, 30 MVA 132/11 kV at 30, 15, 7.5 MVA Local/earthing transformers
2 incomer feeders 1 bus-section 1 bus-coupler 2 transformer feeders 1 spare bay 2 incomer feeders 4 cable feeders 1 bus-section 1 bus-coupler 2 x 90 MVA transformer feeders
33 kV Switchgear
2 incomer feeders 4 cable feeders 1 bus-section and 1 bus-coupler for double bus in existing systems; or 2 bus-tie panels for GIS (single bus) for new installations
11 kV Switchgear
2 incomer feeders 14 outgoing cable feeders 1 bus-section; or 1 bus-coupler for double busbar TX Capacity
Neutral earth resistor (NER) in ohms
90 MVA 60 MVA 45 MVA 30 MVA 15 MVA 7.5 MVA
Rated Secondary Voltage 33 kV 22 kV 11 kV 12 8 24 36 16 4 73 8 Solid Grounding
PMU, PPU and 33kV SSU Design
3.2.4.
25
Civil Criteria
Transmission Division is responsible for the design, construction and installation of the PMU. Distribution Division would witness the commissioning of the MV side and is responsible for constructing and installing outgoing feeders in the PMU compound. For civil requirement details, please refer to the “Design Guideline for Built-In GIS Substation” and “Transmission Design Philosophy & Guidelines for Substations” by the TNB Transmission Division.
3
26
3
Substation Design Manual
3.3.
Pencawang Pembahagian Utama (PPU)
3.3.1.
Overview
Primary Distribution Substation / Pencawang Pembahagian Utama (PPU) in the TNB Distribution network manages primary voltages of 33/11 kV. The PPU is normally to step-down the voltage from 33 kV to 11 kV for distribution to pencawang elektrik (P/E) and customers. Figure 3-8 is a sample single-line diagram for a basic PPU.
To other PPUs
3L5
NOP 2L5
1L5
4L5
R
1W0
Double bus 33kV
M
1H0
1S0
T1 30MVA 33/11kV
2H0
T2 30MVA 33/11kV
32
31 30 13K5
11K5
9K5
7K5
5K5
3K5
1K5
Single bus 11kV 2K5
4K5
6K5
8K5
10K5
12K5
Local
Figure 3-8: Typical single line diagram of a PPU
14K5
PMU, PPU and 33kV SSU Design
27
In Figure 3-8, the breakers are numbered systematically with codes as listed in Table 3-3. Table 3-3: Typical numbering/coding for circuit breaker in a PPU Installation
33 kV code
11 kV code
Outgoing Feeder (left side)
5L5, 3L5, 1L5 or 5P5, 3P5, 1P5 or 5S5, 3S5, 1S5
5, 3, 1 or 5K5, 3K5, 1K5
Incomer 1
1HO (from 33 kV) or 1TO (from 132 kV)
31
Bus Coupler
1WO
34*
Bus Section
1SO
30
Incomer 2
2HO (from 33 kV) or 2TO (from 132 kV)
32
6L5, 4L5, 2L5 or 6P5, 4P5, 2P5 or 6S5, 4S5, 2S5 *Notes: only applies for 11 kV double busbars Outgoing Feeder (right side)
6, 4, 2 or 6K5, 4K5, 2K5
The PPU would typically contain 33/11 kV transformers, AIS or GIS switchgears and their control panels, a local transformer for the building supply, auxiliary battery supply, capacitor banks for power factor correction, and Neutral Earth Resistance (NER). The NER is connected to the star point of the transformer to limit the earth fault current. At present there are two types of PPUs which are the conventional PPU (7.5 MVA, 15 MVA and 30 MVA) and Mini PPU (5 MVA). Mini PPU are installed for low load areas such as outskirt/rural areas. The following highlight some typical PPUs found in the distribution network.
3
28
Substation Design Manual
3.3.1.1.
3
One and a Half Storey PPU
The PPU should be ideally constructed as One and a Half Storey buildings. The bottom half of the building houses the cable cellar where the underground cable entry point is. These cables are channelled up to the first floor to connect to the switching and control rooms. Transformer and NER/NEI bays are located outside the building.
Figure 3-9: One and a Half Storey Primary Distribution Substation (PPU) – Front view
Figure 3-10: One and a Half Storey Primary Distribution Substation (PPU) – Rear view
PMU, PPU and 33kV SSU Design
3.3.1.2.
29
Single Storey PPU
Underground cables in single storey PPUs are placed in trenches instead of in cable cellars. This results in less flexibility for cable installation or reconfiguration.
3
Figure 3-11: Single Storey PPU 3.3.1.3.
Special Type (Three/Four Storey) PPU
In certain locations where space is limited, the PPU may be constructed vertically. This option is not recommended as the design needs to be specifically customised to the requirements of each location. This in turn will result in slower project implementation and commissioning.
Figure 3-12: Three-storey PPU
30
Substation Design Manual
3
Figure 3-13: Four-storey PPU
3.3.1.4.
Outdoor PPU
Outdoor PPUs were the early form of the PPU. Plans are in place to refurbish/upgrade existing outdoor PPU to become indoor PPU.
Figure 3-14: Outdoor PPU
PMU, PPU and 33kV SSU Design
3.3.2.
31
PPU Layout
The site for PPU should be at least 46 m x 46 m in size, not including land setback requirements. Major components of a typical PPU are listed in Table 3-4. Figure 3-15 and Figure 3-16 shows the location of these components in a PPU. Generally the lowest floor is the cable cellar and the top floor holds all other primary and secondary equipment located in the switch room, control room and battery room. Transformer and NER bays are located outside the building structure. Table 3-4: Major components in a PPU Primary Equipment
Transformer (Power & Local Transformer) Switchgear NER/NEI (Neutral Earthing System) Power Cables
Secondary Equipment
Battery / Battery Charger Control and Relay Panel (Protection Relays, Unit Protection, OCEF) Marshalling cubicle Remote Terminal Unit (RTU) Control Cables (Pilot or Fibre)
3
32
Substation Design Manual
Cable cellar
3 Spare bay
Underground cable trench
Distribution transformer bays NER bay Local transformer bay Capacitor bank bay
Figure 3-15: Typical ground floor layout of a PPU
Control room 11 kV switch room with cable entry slots
Battery room
33 kV switch room with cable entry slots Roller shutter door
Loading bay
Figure 3-16: Typical first floor layout of a PPU
PMU, PPU and 33kV SSU Design
3.3.3.
33
Electrical Criteria
Table 3-5 summarises the standard electrical ratings for equipment in a PPU. Table 3-5: Electrical ratings for the PPU Parameters Voltage rating
Transformer installed capacity
2 x 30 MVA 2 x 15 MVA 2 x 7.5 MVA
Local transformer
300 kVA
Switchgear
33 kV GIS-Single Bus bar 11 kV AIS-Single Bus bar
Battery charger
Charger – 110 VDC 35 A Battery – 150Ah
Neutral Earthing Resistor (NER)
3.3.4.
System Configuration 33/11 kV 22/11 kV 11/33 kV(step-up) 33/(22 or 11 kV) – dual ratio transformer
33/11 kV NER Transformer 30 MVA – 4 ohm Transformer 15 MVA – 8 ohm 22/11 kV NER Transformer 30 MVA – 4 ohm Transformer 12.5 MVA – 8 ohm
Solid earthing
Transformers 7.5 MVA and below
Earthing
Less than or equal to 1 ohm
Civil Criteria
For detailed civil criteria, refer to the PPU Handbook (Panduan Asas Rekabentuk dan Pembinaan Bangunan Pencawang Pembahagian Utama (PPU) 33/11 kV Bahagian Pembahagian, TNB).
3
34
3
Substation Design Manual
3.4.
Mini PPU
3.4.1.
Overview
Mini Primary Distribution Substation or Mini PPU is a 33/11 kV 5 MVA PPU introduced as an initiative to improve the system performance at suburban and rural areas normally located far from any existing PMU/PPU with load 3 density less than 5 MVA fed through long distance 11 kV distribution lines . The Mini PPU can also contribute in losses reduction in the suburban and rural area by means of:
Shortening the 11 kV feeder length Reducing the 11 kV load per feeder
Figure 3-17: 33/11 kV, 5 MVA Mini PPU
3
Surat Pekeliling Pengurus Besar Kanan (Pengurusan Aset) (Perkhidmatan dan Amalan Kejuruteraan) Bil. A25/2012 Panduan Perancangan Dan Pemasangan Mini PPU 33/11kV 5MVA untuk Pertingkatkan Prestasi Sistem Pembahagian
PMU, PPU and 33kV SSU Design
35
Limitations on the use of the Mini PPU should also be considered: (a) Mini PPU are not suitable for cities or densely populated areas which are typically connected by underground cables. These underground cables are typically rated at 30 MVA; however the jumper (288A/16.4 MVA) and 33 kV isolator (400A/22.8 MVA) are rated below 30 MVA, which will introduce bottleneck to the network. (b) The pole-top circuit breaker short circuit rating is 12.5 kA; therefore it can only be used with systems having short circuit levels not exceeding 90% of the rating, which is 11.25 kA.
3.4.2.
Basic Design Configuration
3.4.2.1.
Major Components
The basic configuration of a Mini PPU consists of the main components listed in Table 3-6. Table 3-6: Primary components and secondary equipment in a Mini PPU Primary Components
Secondary Equipment
5 MVA Transformer, with maximum dimensions of 3.3 m(L) x 3.5 m(W) x 3.4 m(H) 33 kV Switchgear – Pole Top Circuit Breaker 11 kV Switchgear – VCB Type A1 / RMU Outdoor Lightning Arrester o 36 kV, 10 kA o 12 kV, 10 kA 30 VDC Remote Control Box o Battery/Charger 30 VDC
The single line diagram of the Mini PPU is shown in Figure 3-18. Figure 3-19 and Figure 3-20 provides further illustration of the basic Mini PPU 4 configuration .
4
A16/2010 - Panduan Perancangan dan Pemasangan Mini PPU 5MVA 33/11kV
3
36
Substation Design Manual
33 kV bare overhead line/ABC 2
150 mm Silmalec
3 3-pole switch 36 kV, 400 A
3 x 36 kV, 10 kA MOV Lighting Arrestor (LA)
3 x 12 kV, 10 kA MOV LA
Pole top circuit breaker 36 kV, 630 A
3 x 12 kV, 10 kA MOV LA 3 x 12 kV, 10 kA MOV LA 5 MVA 33/11 kV Transformer
3 x 12 kV, 10 kA MOV LA 2
240 mm 3C XLPE Al B2
11 kV VCB Indoor
Figure 3-18: Basic configuration of a Mini PPU 5 MVA
PMU, PPU and 33kV SSU Design
21
37
1
2
20
3
3
4
3
3
19 2
3
7 5 8 16
6
5 MVA 33/11 kV Transformer
6000
18
17
9 11
10 3420 18 1740
1600
R
1000
13 2000
No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21
7
12 1615
15
14
15
R
13
1850
Description Tubular steel pole 15 m or Spun pole 10 m, 5 kN Lightning arrester 36 kV, 10 kA Bare aluminium conductor 150 mm sq. (Silmalec) with insulating cover 3-pole switch 36 kV, 400 Amps Pole top circuit breaker 36 kV, 630 Amps (Auto-recloser) 3-pole switch operating rod ABC, 33 kV, 3 x 150 mm sq. + 50 mm sq. aluminium Wooden peg 6” x 6” PVC pipe 150 mm class B with UV protection Pole top circuit breaker control box Pole top circuit breaker control wire 3-core XLPE insulated aluminium cable with MDPE outer sheath 11 kV, 240 mm sq. Single wall HDPE corrugated pipe 150 mm Transformer plinth 2700 x 1850 mm (length x width) Angle iron bracket 50 x 50 x 5 mm HV cable box, air type, 33 kV LV cable box, air type 11 kV Angle iron bracket 50 x 50 x 5 mm Bimetal lugs 150 mm sq. (See Detail A) Copper strip 25 x 3 mm with black coating Parallel grooved clamp 150 mm sq.
Figure 3-19: Mini PPU 5 MVA 33/11kV design configuration
38
Substation Design Manual
28
22
3
25 22
26
8 23
22
24 18
22
27 29
No 8 18 22 23 24 25 26 27 28 29
22
Description Wooden peg 6” x 6” Angle iron bracket 50 x 50 x 5 mm C-channel iron cross arm min. dimensions 50 x 50 x 100 mm with 5 mm thickness Flexible steel strap Half stay clip Stay insulator (big) Stay wire 7/8 swg Stay bow and thimble Universal band Aluminium cleats
Figure 3-20: Mini PPU 5 MVA 33/11 kV design configuration (isometric view)
PMU, PPU and 33kV SSU Design
3.4.2.2.
39
Electrical Criteria
The Mini PPU is suitable for 33 kV overhead lines with spur or T-off feeder configuration. Table 3-7 summarises the standard electrical ratings and configuration for equipment in a Mini PPU. Table 3-7: Typical electrical ratings and configuration of Mini PPU Item Incoming 33 kV system Pole-top circuit breaker
Typical Electrical Ratings and Configuration
The incoming 33 kV system must be from an overhead system, either bare conductors or Aerial Bundle Cable (ABC).
A 3-pole switch and auto-recloser is installed to function as a 33 kV pole-top circuit breaker (with auto-recloser function turned OFF). Pole-top circuit breaker must be installed correctly to prevent it from falling off the H-pole structure.
Cable
VCB
Lightning Arrester
2
33 kV ABC (3x150 mm ) is used to connect from the pole-top circuit breaker to the primary side of the 5 MVA 33/11 kV transformer. 2 11 kV XLPE Al 3-core (240 mm ) cable is used to connect from the secondary site of the 5 MVA 33/11 kV transformers to the VCB (B2 type) in the switchgear room. Both sides of the messenger wire for the 33 kV incoming cables must be tied to the H-Pole structures and to the transformer body. The 33 kV incoming cable must be bonded to the H-Pole structure, by single point earth bonding using copper braids. The cable bending radius (R in Figure 3-19), shall be minimally: o Single core – 20 x cable diameter o Three core – 15 x cable diameter o ABC – 7 x cable diameter (overall diameter of the ABC) Suitable bimetal lugs sizes must be used for the transformer tail connections. All cable terminations must use types/brands approved by TNB. Three VCB (A1 type) panels are used for 11 kV system reticulation. One VCB (A1 type) panel is used for the local transformer supply. Surge arresters are installed on both MV and LV terminals of the transformer.
3
40
Substation Design Manual
3.4.2.3.
Civil Criteria
In general the construction of building structures should follow the civil requirements of indoor substations as stated in Subchapter 4.2.4 and requirements of pole-mounted structures as stated in Subchapter 4.7.4.
3
Additionally, requirements specific to this substation are listed here. Table 3-8: Mini PPU civil design requirements Item
Dimension of Mini PPU
Switchgear Room
Minimum Requirements The dimension for the 5 MVA 33/11 kV Mini PPU depends on the poles, transformer and 11 kV switchgear building layout. 11100 x 21000 mm (Layout A – Figure 3-21), or 19000 x 13000 mm (Layout B – Figure 3-22), or 14620 x 14620 mm (Modified P/E – Figure 3-23)
Room size: 5000 x 5100 mm The room design (which includes the civil and structure design, earthing system and drain outlet) is according to Pekeliling Pengurus Besar Kanan (Kejuruteraan) Bil A49/2009 (Design standard of SSU 11 kV substation).
Plinth
The plinth for Mini PPU components must be able to withstand the weight of 1.4 times the dead load. The weight for the 5 MVA transformer is 15 tonnes (15,000 kg).
Fence
The fence for the Mini PPU must be installed for the safety purpose and also to indicate the area of the substation. The fence must be 3.05 metres tall.
3.4.3.
Mini PPU Layout
3.4.3.1.
New Installations
Land size for a Mini PPU depends on the arrangement of electrical poles, transformer and 11 kV switching room. Figure 3-21 and Figure 3-22 show two possible layouts for the Mini PPU.
PMU, PPU and 33kV SSU Design
41
Ultimately, arrangement of these components must comply with the minimum clearance between each component and substation building:
Cable chute for outgoing cables
760 5000
760
1000
B2 A1 A1 A1 A1 900
VCB
Local Tx 300 kVA
900
5 MVA 33/11 kV Transformer
1000
11000
4000
2000
2000
17000
5100
5. 6.
760
800
Battery Charger
2 000
4.
2 000
2 000
3.
Distance between the H-pole and the 5 MVA transformer is 2 metres. Distance between the 5 MVA transformer and the 11 kV switchgear building is 2 metres. Distance between the 11 kV switchgear building and the 300 kVA local transformer is 2 metres. Distance between the substation fence and any Mini PPU component or building is 2 metres. Distance between the gate and the switching room building is 3 metres. The 33 kV incoming cables must be installed at least 600 mm away from the H-Pole structure.
4000
1. 2.
1000
2000
Feeder Pillar 800 A
1500
1200
Cable chute for outgoing cables
Pole Top CB
1000 4000
Note
900 mm trench depth sand filled with cement rendered
1. A1 configuration VCB shall be used with approved type relays. 2. Battery charger shall be 30 Vdc 10A/40Ah
Figure 3-21: Layout of the Mini PPU – Layout A
3
42
Substation Design Manual
10100
1200
2000
800
Feeder Pillar 800 A
900
1000
3
2000
1000
Cable chute for outgoing cables
Local Tx 300 kVA
1500
VCB
A1
17000
760
2000
760
900
19000
B2
5100
20004000
760
Battery Charger
3 000 Cable chute for outgoing cables
5000
760
1000
5100
B2 A1 A1 A1 A1 900
VCB
900
5 MVA 33/11 kV 5 MVA 33/11 kV Transformer
4000
4000
Local Tx 300 kVA
1000
Transformer
760
11000
A1
2000
5000
A1
4000 4000
Cable chute for outgoing cables
760
2000
A1
800
1000
1000
2000
Feeder1000 Pillar 800 A
1500
2 000
4000
Pole Top CB
Cable chute for outgoing cables
1200 Note
1. A1 configuration VCB approved type relays 2. Battery charger shall
2 000
2 000
2 000
Pole Top CB
4000
1000
2 000
Battery Charger
900 mm trench d with cement ren
Note
900 mm trench depth sand filled with cement rendered
1. A1 configuration VCB shall be used with approved type relays. 2. Battery charger shall be 30 Vdc 10A/40Ah
Figure 3-22: Layout of the Mini PPU – Layout B
PMU, PPU and 33kV SSU Design
3.4.3.2.
43
Modification of Existing P/E
Depending on site requirements, existing indoor standalone single chamber P/E buildings (14.6 m x 14.6 m) can be modified and transformed into Mini PPU. Transformation from existing P/E into Mini PPU is encouraged so that new Mini PPU can be established in a shorter timeframe and procurement for new land can be avoided. The following criteria should be considered for new Mini PPU located at the sites of existing P/E distribution substation: 1.
The 33/11 kV 5MVA transformer to be placed in front of the P/E building.
2.
The existing 11/0.4 kV transformer to be relocated outdoor.
3.
The existing P/E building is modified to become an 11 kV VCB switching room.
4.
Replace chain link with brick wall of 2.13 meters in height, with extra height of 3.05 meter high for walls adjacent to the transformer to provide for safety measures and pleasant view to the neighbouring households.
5.
The minimum safety and working clearances must be complied.
The suggested modified P/E layout for a Mini PPU is shown in Figure 3-23.
3
44
Substation Design Manual
14620 – (48’-0’)
3480
4620
3050
3480
3165
7670
Local Tx
New 2130 high brick wall to replace existing chain link fence
600 900
4600
3
2500
14620 – (48’-0’)
Existing P/E
New 3050 high brick wall to replace existing chain link fence
3.3m
1865
Plinth 5 MVA Tx
3.5m
6865
1.5m
3995
H-pole with pole-top CB
4Nos, 160mm CHDPE Pipe
4 meter wide gate
Figure 3-23: Mini PPU layout for modification of existing standalone single chamber substation
3.4.4.
Connection Guidelines
Connection schemes for the Mini PPU are as follows: (a) Spur with 33 kV ABC or bare overhead line directly from 132/33 kV PMU source or 33/ 11kV PPU; (b) Ring with 33kV ABC between two or more Mini PPU fed by feeders from the same or different 132/33 kV PMU or 33/11 kV PPU. Table 3-9 shows a summary of Mini PPU connection scenarios and guides on planning schemes with accompanying diagrams.
PMU, PPU and 33kV SSU Design
45
Table 3-9: 33kV Network Connection Scheme to Mini PPU Scenario Erection of new Mini PPU 33/11 kV 5 MVA
Erection of 2nd/3rd Mini PPU to existing Mini PPU network
33kV Network Connection Scheme (a) Connection of 2 33 kV ABC, 3 x 150 mm , Al., from 33 kV bare overhead lines (Figure 3-24) (b) Spur connection of 2 33 kV, ABC 3 x 150 mm , Al., from an existing PPU. (Figure 3-25) (c) Connection of 33 kV 2 ABC, 3x150 mm , Al., from 132/33 kV PMU. (Figure 3-26) Connection of 33 kV ABC, 2 3x150 mm , Al., from existing Mini PPU (Figure 3-27)
33kV Connection Criteria / Requirement Auto-recloser must be installed at the T-off point between the ABC and bare overhead lines to control operation and isolation. Total load of the 33 kV main feeder to the PPU must comply with the n–1 contingency.
i.
Spur connection if feedback is 100% through 11 kV ii. Ring connection if 11 kV network could not support 100% feedback Add H-pole and Auto-recloser at Mini PPU for operational control and feedback 33 kV network. (Number of Mini PPU depends on protection coordination ability)
In principle, a spur connection is suitable to be set up at the early stage of Mini PPU establishment at rural areas with the condition that the connected 11 kV network is free from any non-transferable load (NTL) problem if the 33 kV network experiences supply disruptions. If NTL is possible or when the same 33 kV network needs to be connected to additional Mini PPU, a ring connection should be established as the next stage of the 33 kV network expansion. It should be noted that any loop in – loop out (LILO) connection from Mini PPU to the existing main feeders between PMU to PPU, between PPUs or between SSUs with fully switched equipment is prohibited. This is to ensure the stability of the unit protection scheme and the operation of the main feeders.
3
46
Substation Design Manual
33 kV bare overhead lines
3
33 kV ABC 3 x 150 mm2
Mini PPU
Figure 3-24: T-off connection from 33 kV bare overhead lines to Mini PPU
PMU, PPU and 33kV SSU Design
47
33 kV Incoming Feeder 1 33 kV Incoming Feeder 2 PPU
3 33 kV Interconnector to another PMU/PPU 33 kV ABC 2 3 x 150 mm Mini PPU
Figure 3-25: Spur connection from an existing PPU to a Mini PPU
48
Substation Design Manual
PMU 132/33 kV
3
ABC 3 x 150 mm 33 kV
2
Mini PPU
Figure 3-26: Spur connection from an existing PMU to a Mini PPU
PMU, PPU and 33kV SSU Design
49
A typical connection from a PMU to two Mini PPUs is shown in the single line diagram of Figure 3-27 below. Legend: Lightning arrestor
PMU 132/33 kV
Pole-top circuit breaker 3-Pole Switch
Connection from another PMU or same PMU (different bus) ABC 3 x 150 mm 33 kV
2
ABC 3 x 150 mm 33 kV
ABC 3 x 150 mm 33 kV
Mini PPU No.1
2
2
Mini PPU No.2
Figure 3-27: Connection between PMU and multiple Mini PPUs
3
50
3
Substation Design Manual
3.5.
33kV Primary Switching Station (33 kV SSU)
3.5.1.
Overview
33kV Primary Switching Station / Stesen Suis Utama (33 kV SSU) refers to a station that supplies power via circuit breakers to ‘bulk supply customers’ and other distribution circuits at the 33 kV voltage level. The 33 kV SSU bus-tie is designed using single-bus switchgears with bus-tie system to avoid total shutdown to customers for maintenance works. This configuration is illustrated in Figure 3-28. 33 kV incomer
7S5
33 kV incomer
3S5
5S5
4S5
1S5
2S5
8S5
6S5
Bus-tie
33 kV Consumer Service Feeder
2nd 33 kV Consumer Service Feeder
Figure 3-28: The design of bus-tie for 33kV SSU
PMU, PPU and 33kV SSU Design
51
The main advantages of SSU 33 kV using Bus-Tie are: Electrical supply for 33 kV bulk consumers will not be interrupted whenever the switching station is under maintenance. Therefore, the system reliability is not affected. In the event of component failure such as switchgear flashover, only half the bus will be affected and supply to customer can be restored immediately through the other bus. This configuration provides a safe and convenient way to perform maintenance work.
33 kV incomer
7S5
33 kV incomer
3S5
4S5
8S5
Section A
Section B 5S5
1S5
2S5
6S5
Bus-tie 100% Load 33 kV Consumer Service Feeder
nd
2 33 kV Consumer Service Feeder
Section under Shutdown
Figure 3-29: Supply feedback to SSU A From the above diagram, the maintenance unit can perform half bus shutdown for Section A without causing supply disruption to consumers because the consumers’ load can be transferred to the second service cable.
3
52
Substation Design Manual
3.5.2.
33 kV SSU Layout
The site for 33 kV SSU should be at least 30 m x 30 m in size, not including land setback requirements.
3
Figure 3-30 shows the typical layout of 33 kV SSU and locations of major components. Generally the SSU contains a switchgear room, control room, battery room and metering room. Incoming and outgoing cable connections would be installed in underground cable trenches or a half-storey cable cellar. However, the actual design may vary according to the availability of land and suitability to the site. Table 3-10: Major components in an SSU Primary Equipment
Switchgear Power cables
Secondary Equipment
Battery / Battery Charger Control Relay Panel (Protection Relays, Unit Protection, OCEF) Marshalling cubicle Remote Terminal Unit (RTU)
Cable entry via cable cellar
Switchgear room
Control room Store Metering room
Battery room
Figure 3-30: Typical layout of 33kV SSU and locations of major components
PMU, PPU and 33kV SSU Design
3.5.3.
53
Electrical Criteria
Table 3-11 below summarises the typical electrical ratings in a 33 kV SSU. Table 3-11: Typical ratings in a 33 kV SSU Item Voltage rating
Typical ratings
33 kV
Switchgear
33 kV GIS – Single busbar with bus-tie (for new areas) 33 kV GIS or AIS – Double busbar (existing areas) Incomers as required 2 Outgoing feeders to consumer 2 Breakers for Bus-tie (where applicable)
Interconnecting Cables between Bus-Ties (where applicable)
3 x 33 kV XLPE 630 mm Al Single Core (single bonding practice shall be strictly followed for single core cable as stipulated in Arahan Naib Presiden Bil A06/2010 Amalan Single Point Bonding pada Transformer Tail di dalam PMU/PPU)
Protection for bus-tie (where applicable)
Battery charger and battery Earthing
3.5.4.
2
OCEF and Current Differential protection scheme on both bus-ties At least one of the switchgears on the bus-tie must be normally off (on soak) OCEF setting for both switchgears must follow the settings supplied by the manufacturer Switch configuration and position during normal operation, shut-down, contingency, as well as during operation and equipment ownership must follow the Interconnection Operation Manual (IOM) that exists between the RCC and consumer. Charger – 110 VDC 35 A Battery – 150 Ah Less than or equal to 1 ohm
Civil Criteria
In general the construction of building structures should follow the civil requirements of indoor substations as stated in Subchapter 4.2.4.
3
54
Substation Design Manual
3.6.
Testing and Commissioning
Before commissioning the PMU, PPU or 33 kV SSU, specific tests are to be carried out on substation equipment to ensure safe and reliable operation. The following are some tests that are to be performed, wherever applicable:
3
Pre-commissioning tests: (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n)
Current transformer test Instrumentation transformer test Power transformer test Secondary equipment test Instrumentation verification tools test Validation test major component Testing the stability of the protection scheme Switchgears operation test Power transformers operation test Substation battery system test Test indication to the SCADA system Transducer test Grounding system test Heating test
Commissioning tests: (a) Live phasing test (b) Phasing voltage test instrumentation
P/E, 11 kV SSU and S/S Design
Chapter 4: Design 4.1.
P/E, 11 kV SSU and S/S
Introduction
This chapter covers general design, illustrates typical layouts, and presents technical criteria of various types of stations for the MV/LV distribution network. The types of substations that will be covered in this chapter are: 4.2 4.3 4.4 4.5 4.6 4.7 4.8
Indoor Distribution Substation / Pencawang Elektrik (P/E) 11 kV Primary Switching Station / Stesen Suis Utama 11 kV (11 kV SSU) Outdoor Distribution Substation / Pencawang Elektrik (P/E) Switching Station / Stesen Suis (S/S) Compact Substation Unit (CSU) / Pencawang Elektrik Padat Pole Mounted (H-Pole) Substation / Pencawang Atas Tiang (PAT) Pole Mounted (H-Pole) Substation (PAT) with RMU
Subchapter 4.2 introduces construction guides applicable for all substation building structures. Standardised distribution substation buildings and their schematic drawings are made available in the latest versions of the following documents:
55
Electricity Supply Application Handbook (ESAH) Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian
Subchapter 4.4 provides guides on outdoor substation structures. Construction guides and schematic details of pole-mounted substations are introduced in Subchapter 4.7.
4
56
Substation Design Manual
4.1.1.
Characteristics of Distribution Substations
Typical distribution substations will have several MV feeder circuit connections: one or more incoming feeders; and one or more outgoing feeders. Spur substations will only have one MV incoming feeder connection.
4
MV circuits connect to the substation through switchgears which are used principally to isolate the substation from the MV network for maintenance, fault sectionalizing, or when replacement of substation equipment is required. The switchgear used can be either vacuum circuit breakers (VCB) or ring main units (RMU). The MV circuit can then be stepped down to LV via a transformer to supply LV customers. MV customers can also receive directly from the substation. Figure 4-1 and Figure 4-2 show sample single-line diagrams for distribution substations. MV Incoming feeder
MV Outgoing feeder
VCB Transformer
LV customer
MV customer
Figure 4-1: Basic VCB Distribution Substation (P/E) with 1 incoming feeder, 1 outgoing feeder, 1 LV transformer feeder, 1 MV customer
P/E, 11 kV SSU and S/S Design
MV Incoming feeder
MV Outgoing feeder
Transformer 1
Transformer 2
LV customer 1
LV customer 2
Figure 4-2: Basic RMU Distribution Substation (P/E) with 1 incoming feeder, 1 outgoing feeder, and 2 LV transformer feeders
4.1.2.
57
Characteristics of Switching Stations
A switching station is a combination of switching and controlling equipment arranged to provide circuit protection and system switching flexibility. Incoming connections are typically from PPU and outgoing connections are usually to P/E or MV customers.
Incoming
VCB
Incoming
VCB Busbar
Outgoing
Figure 4-3: Typical switching station single line diagram
4
58
Substation Design Manual
4.1.3.
Comparison of Substations
It is useful to note the differences between substations and switching stations for operational purposes.
4
P/E will have switchgears that are either VCB or RMU. For Indoor P/E these switchgears will be installed in a switching room.
P/E will also have a distribution transformer installed inside a transformer room/chamber. Additional transformers require separate chambers.
11 kV SSU are characterised by a bus section. SSU connect to multiple feeders at 11 kV that can go to other substations, distribution transformers or direct to bulk consumers.
S/S are stations without transformers and function only as switching or T-off points using an RMU with three switches (3S) or VCBs.
PAT are distribution substations with components and equipment that are mounted on poles.
Figure 4-4: Indoor – standalone, single chamber without metering room
P/E, 11 kV SSU and S/S Design
59
Table 4-1 highlights the characteristics and main differences between indoor distribution substations and 11 kV switching stations. Table 4-1: Comparison of distribution substations and 11 kV switching stations Pencawang Elektrik (P/E) RMU Single chamber
VCB Double chamber
Single chamber
Double chamber
4
no transformer
11 kV SSU (VCB) 1 Transformer
Substation (No transformer) VCB RMU
2 Transformers
PAT (Pole-mounted)
60
Substation Design Manual
4.2.
Indoor Distribution Substation (Indoor P/E)
4.2.1.
Overview
The indoor distribution substation or pencawang elektrik (indoor P/E) is a substation with all primary equipment installed within a building structure. Indoor P/E can be built either standalone or attached to a building. Both can be of single or double chamber type, with or without a metering room.
4
4.2.1.1.
Indoor – Standalone
Possible configurations are single chamber or double chamber, with or without metering room. This is the ideal choice with the principal advantages as follows: (a) It facilitates installation of fully switched facilities, or power factor improvement capacitors, if and when required. (b) It facilitates the installation of automation equipment, such as SCADA, remote switching facilities, etc. (c) It provides easy access, and space separating it from adjacent buildings, thus minimize the risk to the adjacent building (due to safety reasons). (d) For substation with extra land area, it can accommodate additional extension of switchgear or compact substation to meet the increasing customer demand. (e) Removes the need for any special fire fighting facilities. The use of portable dry type powder fire extinguishers is sufficient. 4.2.1.2.
Indoor – Attached to a Building
Possible configurations are single chamber or double chamber, with or without metering room and with or without SCADA facilities. This alternative has similar advantages to that of a separate building, except: (a) Little or no land space, as developers usually provide the minimum space. (b) The need to install fully automatic fire fighting equipment to meet fire safety requirements. (c) Design of the building must be in line with developers’ layout plan with emphasis on aesthetics and landscaping. (d) Building owners may need to incorporate fire fighting facilities for their premises.
P/E, 11 kV SSU and S/S Design
61
In practice, the real estate developer will construct and provide the substation building based on the requirements specified by TNB during project planning. Substation architectural designs and colour schemes need to be in harmony with the surrounding, as required by Arahan Naib Presiden Bil. A2/2010. The following figures show sample indoor substations.
4 Attached P/E
Figure 4-5: Indoor – attached, double chamber P/E designed to blend with surrounding structures
Figure 4-6: Indoor – standalone, double chamber P/E designed to blend with surrounding structures
62
Substation Design Manual
4.2.2.
Indoor P/E Layout
Typical indoor substation building sizes are shown in Table 4-2 and Table 4-3 taken from ESAH version 3.
The sizes below can also cater for SCADA equipment installation. Total land area required will need to take into account of land setback requirements. Please refer to the latest version of ESAH for updates or changes in layout design.
4
Table 4-2: Standard sizes of 11/0.4 kV indoor substations (without Metering Room) Building Type
S/Gear
Overall (mm)
S/Gear Room (mm)
Tx Room (mm)
Length (mm)
1
Single chamber
Standalone
VCB
7600 x 5100
4600
3000
5100
2
Double chamber Standalone
VCB
10600 x 5100
4600
3000
5100
3
Single chamber
VCB
8600 x 5700
5600
3000
5700
4
Double chamber Attached
VCB
13000 x 5700
7000
3000
5700
5
Single chamber
Standalone
RMU
7000 x 4000
4000
3000
4000
6
Double chamber Standalone
RMU
10000 x 4000
4000
3000
4000
7
Single chamber
Attached
RMU
8000 x 5700
5000
3000
5700
8
Double chamber Attached
RMU
13000 x 5700
7000
3000
5700
Attached
Table 4-3: Standard sizes of 11/0.4 kV indoor substations (with Metering Room) Building Type
S/Gear
Overall (mm)
S/Gear Room (mm)
Tx Room (mm)
Length (mm)
1
Single chamber
Standalone
VCB
7600 x 5700
4600
3000
5700
2
Double chamber Standalone
VCB
10600 x 5700
4600
3000
5700
3
Single chamber
Attached
VCB
7600 x 5700
4600
3000
5700
4
Double chamber Attached
VCB
12000 x 5700
6000
3000
5700
5
Single chamber
Standalone
RMU
7000 x 5700
4000
3000
5700
6
Double chamber Standalone
RMU
10000 x 5700
4000
3000
5700
7
Single chamber
Attached
RMU
7000 x 5700
4000
3000
5700
8
Double chamber Attached
RMU
11000 x 5700
5000
3000
5700
P/E, 11 kV SSU and S/S Design
63
Major components of a typical indoor P/E are listed in Table 4-4. Figure 4-8 and Figure 4-9 shows the location of these components in indoor P/Es.
Switchgears are installed in switching rooms. Distribution transformers are placed inside transformer rooms/chambers. Each transformer requires a separate chamber. Feeders for P/E are all connected by underground cables which enter and exit the substation via PVC ducts. Feeder pillars are located outside the building structure. Attached substation rooms are larger in size to accommodate the feeder pillars, and the additional ventilation fans and fire fighting equipment. Table 4-4: Major components in an indoor distribution substation Primary Equipment
Switchgear (VCB / RMU) Transformer Feeder pillar
Secondary Equipment (For VCB only)
Battery Charger with Battery Control Relay Panel (Protection Relays, Unit Protection, OCEF) Remote Control Box (RCB) Remote Terminal Unit (RTU)
Customer LV room
Fire-fighting control panel
Transformer rooms
RCB panels
Switching room
Figure 4-7: Indoor – attached, double chamber with RCB and RTU panels (SCADA ready)
4
64
Substation Design Manual Transformer with guards in a chamber
VCB in the switching room
Underground cable trench
Ventilation blocks
Feeder pillar
4 LV feeder underground ducts
RCB Manhole
11 kV feeder underground ducts
Figure 4-8: Layout of Standalone Indoor Substation – Double Chamber Metering room
Transformer in a chamber
VCB in the switching room
Ventilation blocks (where possible)
Insulating mat Ventilation fans
11 kV feeder cables RCB Feeder pillar LV feeder underground cables
Figure 4-9: Layout of Attached Indoor Substation – Double Chamber with Metering Room
P/E, 11 kV SSU and S/S Design
4.2.2.1.
65
Switching Rooms
Indoor substations will always have switchgears which are either vacuum circuit breakers (VCB) or ring main units (RMU) which are installed in a switching room. Rooms installed with VCB will be slightly larger due to the VCB’s larger size compared to the RMU. 4.2.2.2.
Transformer Room/Chamber
Indoor P/E will also have a distribution transformer installed inside a transformer room/chamber. Additional transformers require separate chambers to ensure containment during any emergency. 4.2.2.3.
Metering Room
Certain indoor substations that are supplying to LV and 11 kV bulk customers will have a metering room, connected either to the transformer tail or feeder pillar for LV bulk customer or to the switchgear for MV/HV customer. Suggested locations for the metering room with respect to the customer are shown in the following Subchapters (4.2.2.4 and 4.2.2.5). For 33 kV bulk customers, the metering room shall be located at the customers’ premise. General design requirements of the metering room are as follows:
The metering room is an enclosed looked room for the purpose of installing metering cubicles, and must have its own dedicated entrance, separated from the transformer/switchgear rooms by walls. The metering room is separated so that the meter may be accessed without having to enter the high voltage zone. The minimum size for the room is 2.0 m(W) x 2.0 m(L) x 2.5 m(H) and located inside the substation/switching station for LV and 11 kV bulk customers. Location of the metering cubicle inside the metering room shall be as represented in Figure 4-10.
4
66
Substation Design Manual
2000
550
Metering Cubicle
2000
1100
4 Entrance
Figure 4-10: Layout for installing metering cubicle in the metering room
4.2.2.4.
P/E Location for LV Bulk Customer
For LV bulk customer, the preferred type of building is the standalone indoor substation. Suggested location of the substation with respect to the customers’ facility and main switch board (MSB) is shown in Figure 4-11 and Figure 4-12. Substations for LV bulk customers must be located at the front area of the gated factory with a separate access from the main factory access. This is required because of the following objectives:
TNB personnel can enter the substation easily without getting permission from the customer. TNB personnel can perform cable and substation upgrading work without disturbing roads/facilities inside the customers’ compound.
P/E, 11 kV SSU and S/S Design
67
Criteria of new substation location for LV bulk customer: (a) Size of the substation must comply with setback and frontage requirement of the local authority (b) Customers’ MSB room are recommended to be place next to the substation (Figure 4-11) (c) If customers’ MSB room cannot be located next to the substation due to unavoidable technical issues, customers’ MSB room can be located at the factory’s building (Figure 4-12) with these conditions: i. The LV service cable cannot have any straight through joints and the length of the cable must be less than 250 meters; ii. Voltage drop from the substation to the customers’ MSB is less than 5% as suggested in the LV Planning Guideline; iii. If LV service cable is of single core type, it must be laid in a concrete trench with earthing copper tape (extended from transformer starpoint connection) at the bottom for the physical protection of the cable and for ease of maintenance. The concrete trench needs to be filled with sand and cement rendered.
Factory Fence
TNB metering room
Customers’ MSB P/E
Road
Figure 4-11: Location of P/E with attached MSB room for LV bulk customers
4
68
Substation Design Manual
Customers’ MSB Factory Fence LV service cable inside concrete trench
4
TNB metering room P/E
Road
Figure 4-12: Location of P/E with detached MSB room for LV bulk customers
4.2.2.5.
P/E Location for MV Bulk Customer
The substation location for MV bulk customers is dependent on the land area of the factory:
If the land area is big, an indoor standalone P/E located at the front area of the gated factory is preferred. If the land area is small, an attached substation is allowable provided 24 hour accessibility to the substation is possible.
P/E, 11 kV SSU and S/S Design
4.2.3.
69
Electrical Criteria
Table 4-5 summarises the standard electrical ratings for equipment in the indoor substation. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-5: Typical ratings in a conventional P/E Equipment/component
Rating and size
Voltage rating
11/0.433 kV
Transformer installed capacity
500 kVA, 750 kVA, 1000 kVA
Switchgear Feeder pillar
4.2.4.
12 kV Ring Main Unit (RMU); or 12 kV Vacuum Circuit Breaker (VCB) 800 A, 1600 A
Civil Criteria
The following are guidelines for typical substation civil requirements to provide proper working environment for the equipment and personnel working within the indoor substation. Guidelines provided here are also applicable to all other distribution substations with building structures. 4.2.4.1.
Compound area
A flat surface ideally desired for the layout and operational function of a substation. It permits uniformity in foundation elevations and structure heights. Unless there are property restrictions, severe topographical features, subterranean rock, or other considerations dictate otherwise, the substation surface should be graded nominally flat.
4
70
Substation Design Manual
4.2.4.1.1.
Land Requirement
The required land size must consider the size of the substation as shown in Table 4-2 and Table 4-3 previously. Additional setback and frontage requirement of local authorities must also be considered. Under normal circumstances the following land size is sufficient for Standalone Indoor P/E: (a) Single chamber – 13.6 m x 14.8 m (b) Double chamber – 16.6 m x 14.8 m
4
4.2.4.1.2.
Foundation
Piling requirements need to be decided based on evaluation of the soil condition which should have been evaluated during initial site investigations. 4.2.4.1.3.
Surfacing Material
For standalone substations, the compound area outside the building structure should be paved with tarmac or cement of 50 mm (2 inches) thickness with 150 mm (6 inches) of crusher run underneath. 4.2.4.1.4.
Substation gate and fence should ideally be 2.1 metres or 7 feet tall. Decorative gate and fence designs are encouraged to harmonize with the surrounding. Fence for standalone substations can be substituted with concrete kerbs (minimum 150 mm in height) or bollards to mark the substation area. For attached substations, whenever possible, removable barriers have to be installed 3 metres in front of the switchgear room and transformer room doors such that the entrance to the substation is not blocked.
4.2.4.1.5.
Gate and Fence
Drainage
Drainage should be built surrounding the substation around 750 mm from the outside wall to the centre of the drain. The drainage must be connected to the nearest existing draining system in the vicinity.
P/E, 11 kV SSU and S/S Design
4.2.4.2. 4.2.4.2.1.
Structures Floor
The substation floor should be made of Reinforced Concrete (RC). Surface finishing of the outdoor area should be at one level. Floors are to be painted with epoxy green paint. Minimum safety clearance should be marked with yellow paint. The substation RC floors need to cater for the weights of equipment to be installed on it. The minimum floor loadings are shown below: Table 4-6: Minimum floor loadings for indoor P/E
4.2.4.2.2.
71
Equipment
Floor load
Transformer
Nominally 7000 kg 1.4 x transformer weight
Indoor Switchgear (VCB/RMU)
Nominally 8000 kg 1000 kg x VCB panel number (8 panels in switching room)
Feeder Pillar
1000 kg
Walls
All walls for building structures should be constructed using red clay bricks laid with 1:3 cement sand mortar. All walls should be 230 mm thick. All walls should be reinforced with expanded metal (exmet) at every fourth course in order to strengthen the wall structure. Partition walls between switching room and transformer room should be 230 mm thick and 2100 mm tall.
4
72
Substation Design Manual
Expanded metal layer
4
Figure 4-13: Expanded metal (exmet) layer at every fourth course
4.2.4.2.3.
Damp-Proof Course (DPC)
Damp-proof course (DPC) is necessary to prevent moisture ingress into the ground beam as well as termite infestation prevention. The DPC consists of 25.4 mm or 1 inch thick 1:1 cement sand-screed bedding laid on the ground beam. Upon drying, a bituminous felt is laid with liquefied bitumen.
Wall drying out above DPC
New plaster
Skirting
New chemical DPC
DPC membrane in solid floor
Ground level Rising damp
Figure 4-14: Damp-proof course (DPC)
P/E, 11 kV SSU and S/S Design
4.2.4.2.4.
Ventilation
Ventilation blocks (batu angin) can be used to provide sufficient aeration for the substation equipment. To prevent entry of pests into the substation building, anti-vermin plastic or stainless steel mesh netting mounted on aluminium frames must be installed on the outside of the ventilation blocks. The ventilation blocks for the switch room shall be covered with awnings to prevent rain water from entering the switch room which would affect the switchgears.
Figure 4-15: Ventilation blocks with anti-vermin plastic mesh
73
Attached indoor substations require additional ventilation in the form of an exhaust fan. The exhaust fan must be at least 12 inches in size and installed with thermostat control. The fan should be pulling air out of the substation.
4
74
Substation Design Manual
4.2.4.2.5.
4
Doors
All louvered doors shall be made of Composite-Fibre Reinforce Plastic. All louvered doors shall be installed with plastic anti vermin netting or stainless steel mesh netting mounted on Aluminium frame fixed on the inside of the door. Doors should be sized to fit the equipment to be installed inside the room. Transformer rooms require large double leaf doors to accommodate the size of the transformer. Suggested door dimensions are as follows: (a) Transformer room: 2400 mm(W) x 3000 mm(H) double leaves (b) Switchgear room: 1500 mm(W) x 3000 mm(H) double leaves
4.2.4.2.6.
Roofing
For all standalone substation buildings, the roofing style should match the styles of the surrounding building and area. If no specific roofing style is required, the roof should be of reinforced concrete (RC) flat type constructed with proper water proofing treatment.
RC flat roof designs shall cater for a waterproof slab, cast with waterproof concrete, cement screed with waterproofing agent, and provide for minimal shrinkage with anti cracking reinforcement. A layer of bituminous material must be applied to waterproof the concrete slab roof. For the attached P/E substation-type, if there are pipes across the top of the substation, two layers of water proof concrete roof slabs should be built. The first layer (closer to the substation) must contain a bituminous layer.
P/E, 11 kV SSU and S/S Design
4.2.4.2.7.
4.2.4.3.1.
Cable Trenches
All trenches in the substation are to be filled with washed river sand. Washed river sand has the following advantages: (a) Avoid moisture from entering into the switchgear via the cable entry. (b) Better heat dissipation and minimisation of impact due to fire hazards. (c) Has arc quenching property which can protect neighbouring cables from a cable that is at fault. (d) From a safety aspect – closed trenches can eliminate the risk of staff falling into the trench. A 50 mm (2 inch) thick cement render (1:2, cement:sand) is required to cover the trench. This is to minimize condensation of water from inside the trench and to prevent entry of vermin through the trench. The spacing from the trench floor to any beam or structure that may protrude into the trench should be 600 mm minimum. This is to ensure sufficient space to install the cable in the trench.
4.2.4.3.
75
Installations Pipes/Ducts for Feeder Cables
All incoming and outgoing MV and LV feeder cables to the substation need to be installed via pipes/ducts for added mechanical protection. The type of pipe to be used is PVC Class B with different diameters depending on its use as follows: a) 150 mm diameter – for 11 kV MV multi-core cables b) 200 mm diameter – for 11 kV MV single core cables laid in trefoil formation. A suitable number of pipes/ducts need to be prepared for current and future use. A draw wire shall be provided for each duct to facilitate cable laying. All cable pipes/ducts should be sealed to prevent water from entering the substation.
4
76
Substation Design Manual
4
For 11/0.433 kV substations, two layers of three PVC Class B 150 mm diameter pipes need to be laid from the trenches until they reach beyond the drain and/or road kerb. For 11 kV SSU, 1 layer of three PVC 200 mm diameter pipes and 1 layer of four PVC 150 mm diameter pipes are needed. For drainage crossings, G.I. pipes need to be used as a protective sleeve. However, only multi-core cables and single-core cables laid in trefoil are allowed in G.I. pipes. It cannot be used with single core cables laid singularly (alone) due to induced and circulating eddy currents in the G.I. pipes.
4.2.4.3.2.
Transformer Guard and Bushing Cover
All transformer bushings should be shrouded with transformer bushing covers. Additionally, transformer guard needs to be installed at all transformers in substations because: No live parts should be exposed without a barricade There is still voltage potential on the bushing covers To protect the metering CT which is connected at the LV cable support bracket
Transformer guard
Figure 4-16: Transformer guard
P/E, 11 kV SSU and S/S Design
4.2.4.3.3.
77
Feeder Pillar
The feeder pillar must be installed outside the substation building to facilitate access by fault finders and the LV maintenance team during breakdown or shutdown. 4.2.4.3.4.
Metering CT for LV Bulk Customer
For LV bulk customer, the metering current transformer (CT) is installed on the LV service cable connected to the secondary side of the transformer. Metering CT provides current readings to an energy meter through 2 2.5 mm 12-core copper multi-core cables. LV cable support brackets are used to support the LV Cable and the metering CT as shown in Figure 4-17. 2 Connections between meter and CT will use 2.5 mm , PVC/SWA/PVC, 12-core, copper multi-core armoured cables. Table 4-7: The maximum allowable distance between metering CTs and metering cubicle for LV consumer CT Burden (VA)
Secondary Rated Current (A)
7.5 7.5
5 5
Cross Connection of Conductor 2 (mm ) 2.5 4.0
Figure 4-17: CT on the cable support bracket
Maximum Distance Allowable (m) 12.0 20.0
4
78
Substation Design Manual
4.2.4.3.5.
4
For metering installations up to 33 kV, current (CT) and potential transformers (PT) shall be provided and installed by TNB at TNB's outgoing switchgear feeder. 2 2 Connections between meter and CT will use 2.5 mm or 4.0 mm , PVC/SWA/PVC, 12-core, copper multi-core armoured cables, depending on maximum allowable distance as in Table 4-8. The armoured cable shall not be buried or enclosed, and preferably laid on cable trays.
4.2.4.3.6.
Metering CT for MV Consumer
Metering CT for HV Consumer
A ‘marshalling box’ with independent sealing facility shall be provided by the consumer for the purpose of terminating the secondary circuit cabling of the CT and PT. 2 Connections between meter and CT will use 2.5 or 4.0 mm , PVC/SWA/PVC, 12-core, copper multi-core armoured cables, depending on maximum allowable distance between CT and meter as in Table 4-8. For metering installations of 132 kV and above, CTs and PTs shall be provided and installed by the consumer at consumer’s incoming switchgear in accordance with TNB’s specifications. TNB shall witness the commissioning tests of both CTs and PTs. Table 4-8: The maximum allowable distance between metering CTs and metering cubicle for MV and HV consumer CT burden (VA) 15 15 30 30 30 30
Secondary rated current (Amps) 5 5 5 5 1 1
Cross-sectional area 2 of conductor (mm ) 2.5 4.0 2.5 4.0 2.5 4.0
Maximum allowable distance (m) 30 47 65 100 1,647 2,545
Where meter burden for current circuit = 0.5 VA/ph
Calculations of the maximum allowable distance between metering CT and metering cubicle can be found in Appendix A.
P/E, 11 kV SSU and S/S Design
4.2.4.3.7.
79
Earthing System
Copper tape/strip of 25 mm wide x 3 mm thick (1” x 1/8”) is used as the earthing conductor. The copper strip should be installed on the side wall of the concrete trench wall, 60 mm from the top of the trench to prevent theft. Earthing layouts for different substations are shown in Subchapter 9.2.3.
60mm
4 Copper strip
Figure 4-18: Copper strip for earthing in a concrete trench 4.2.4.3.8.
Operating Equipment
The substation should be provided with its own respective operating equipment such as the operating gear and earthing gear. The equipment should either be stored on racks or placed in a cabinet. 4.2.4.3.9.
Fire Fighting System
Fire extinguishing equipment should be located near the entrance of the building. If automatic equipment is used, there should be means of switching off the equipment when work is being carried out in the substation. This is typically done through a fire-fighting control panel. For attached substations, fire-fighting equipment is installed inside the substation building structure. Detailed guidelines are presented in Chapter 10: Fire Fighting System and Pekeliling A08/2011.
80
Substation Design Manual
4.2.4.3.10.
4
Single phase wiring is required to be done with G.I. conduit complete with main-switch, ELCB, MCB Distribution Board and separate earthing. The source of supply is from the feeder pillar. Wiring in conduits for the Earth Fault Indicator (EFI) should be provided inside the switchgear room. Adequate lighting points should be provided and power socket outlets should be installed at convenient locations for the use of hand lamps, hand tools, etc. Emergency lighting is also required inside the substation with its own battery capable of supplying three hour of backup power to the emergency light. External lighting should utilise weather proof light fittings and operated via a photoelectric control unit (PECU).
4.2.4.4. 4.2.4.4.1.
Finishes Colour
Selection of colours should be harmonized with the surrounding environment such that they blend/match the neighbouring structures.
4.2.4.4.2.
Lighting, Fittings and Wiring
Signboard/Signage
A signboard containing the name of the substation must be installed at the front of the substation, facing the nearest road. The signboard should be installed at eye level for easy identification (around 1800 mm from floor level). Appropriate warning signs should be posted on the substation’s barrier fence. Substations, no matter how small, should have one sign per side, as a minimum. For each substation site, assess whether standard signs are sufficient. Special bilingual signs may be advisable for some areas.
P/E, 11 kV SSU and S/S Design
Head protection
No smoking
Body protection
Hand protection
Foot protection
Eye protection
Figure 4-19: Standardised signboard containing substation details 1245 20
20
505
20
330
330
20 20 155 20 155 20 210
1005
20 210 20 155 20 155 155 155 155 20 155 20 155 20 155 20 20 20 20 20
Figure 4-20: Standardised signboard dimensions
240
81
200
200
150
150
240
Figure 4-21: Standardised warning and electrical hazard signs
4
82
Substation Design Manual
4.3.
11 kV Primary Switching Station (11 kV SSU)
4.3.1.
Overview
Essentially, the 11 kV Primary Switching Station or Stesen Suis Utama (11 kV SSU) is a switching station which is installed with 12 kV, 630 A, 30 VDC VCB panels, with or without distribution transformers. Additionally, it must also be installed with a bus-section panel.
4
11 kV SSU is built for the following functions: As a switching station To give bulk supply to 11 kV customers To give LV supply via 11/0.433 kV distribution transformer Incoming VCB
Incoming
VCB
Outgoing
Figure 4-22: Example single line diagram for primary switching station (11 kV SSU) without transformer
Incoming
VCB
Incoming
VCB
Outgoing
Figure 4-23: Example single line diagram for primary switching station (11 kV SSU) with transformer
P/E, 11 kV SSU and S/S Design
83
4
Figure 4-24: Primary switching station (11 kV SSU)
4.3.2.
11 kV SSU Layout
The building features and civil criteria are similar as those for the indoor distribution substation in Subchapter 4.2.4. The difference is in the dimension of the building and rooms. Please refer to ESAH for details on the dimension and layout arrangement. The 11 kV SSU consists of: Switchgear room with bus-section Transformer room (as required) Battery room Metering room (as required) The number of VCB panels that can be erected in an SSU is subjected to the maximum load duty of the DC charger and battery. Typically one unit of a 30 VDC, 10 A charger with 40 Ah battery can cater for a maximum number of 5 VCB panels. However, the actual allowable number of panels can be determined by calculating the DC load profile duty cycle using IEEE 1118.
84
Substation Design Manual
Switchgears with bus-section
Underground cable trench
Ventilation blocks
Insulating mat
4
RCB LV feeder underground cables
Figure 4-25: Layout of 11 kV SSU
4.3.3.
Electrical Criteria
Table 4-9 summarises the standard electrical ratings for equipment in the indoor substation. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-9: Major components in an 11 kV SSU Primary Equipment
-
Secondary Equipment
- Battery / Battery Charger - Remote Terminal Unit (RTU)
Switchgear (VCB only) Transformer (if required) Feeder pillar (for SSU with transformer only) Power cables
P/E, 11 kV SSU and S/S Design
4.4.
Outdoor Distribution Substation (Outdoor P/E)
4.4.1.
Overview
85
Outdoor substations (Outdoor P/E) are similar in function to their indoor counterparts. Outdoor P/E are favoured for their cost advantages, and used mainly for rural electrification and system improvement. They are also used for industries that have very large land areas such as farms. The advantages of outdoor and semi-outdoor type substation are: Low cost Require smaller land area Easy and fast to install
incoming
outgoing
RMU 11 kV, 630 A Transformer 11/0.433 kV
Feeder Pillar 1600A/800A
Figure 4-26: Single line diagram for outdoor distribution substation
4
86
Substation Design Manual
4.4.2.
Outdoor P/E Layout
Outdoor substation layout is similar to the indoor substation layout except that the equipment is in the open air.
Barbed wire
Roof
Ventilation blocks for walls
Switchgear Transformer guard
4
Transformer
Feeder pillar
Stone chips
Doors
Figure 4-27: Layout of outdoor substation and locations of major components The typical existing fencing is the chain link fence. However, for new and future installations, ventilation blocks are preferred for fencing because they partially conceal the outdoor substation from public view as well as contain splashes of oil and/or arcing resulting from any possible flashover. Additionally the solid structure helps to deter unauthorized entry more effectively A roof is erected for the switchgear to cover the RMU as a protection from direct sunlight and heavy rain as well as providing a comfortable area for working personnel.
P/E, 11 kV SSU and S/S Design
87
4
Figure 4-28: Typical outdoor substation with ventilation block fencing
Transformer
Switchgear
Feeder Pillar
Figure 4-29: Typical outdoor substation with chain link fencing
88
Substation Design Manual
4.4.3.
Electrical Criteria
Table 4-10 summarises the standard electrical ratings for equipment in the outdoor substation. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-10: Typical ratings in an Outdoor P/E
4
Equipment/component
Rating and size
Voltage rating
11/0.433 kV
Transformer installed capacity
300 kVA, 500 kVA, 750 kVA, 1000 kVA
Switchgear
12 kV Ring Main Unit (RMU)
4.4.4.
Civil Criteria
In general the construction of outdoor substations should follow the civil requirements stated here. 4.4.4.1. 4.4.4.1.1.
Land Requirement
Under normal circumstances the minimum land size required for an Outdoor P/E is 7620 mm x 7620 mm (25 ft x 25 ft). Total land size including drainage is 8400 mm x 8400 mm (27.5ft x 27.5ft). The land area of the substation shall be raised by 100mm above the road level to prevent water flow into the substation and for ease of transportation.
4.4.4.1.2.
Compound Area
Plinth
Plinths shall be designed to cater for the loads as described below: Equipment
Plinth load
Transformer
1.4 x transformer weight Nominally 7000 kg
Outdoor Switchgear (RMU)
5000 kg
Feeder Pillar
1000 kg
P/E, 11 kV SSU and S/S Design
89
All plinths should have at least 150 mm above ground level. Plinth may need to be taller depending on special site requirements such as flooding.
4
Figure 4-30: Suggested switchgear plinth dimensions
Figure 4-31: Suggested feeder pillar plinth dimensions
90
Substation Design Manual
4.4.4.1.3.
4
The substation floor surrounding the plinths must be covered with 150 mm of stone chips in order to limit the step and touch voltage levels to a safe value as the crushed stone layer provides an insulation in series with the body. Optionally, a layer of tarmac is allowable as long as it matches the required insulation level of the stone chips. Both stone chips and tarmac have similar function to the insulating mat in the indoor P/E. The additional benefit of using stone chips or tarmac is to reduce grass/vegetation growth.
4.4.4.2. 4.4.4.2.1.
Structures Roof
RMU used in outdoor substations are designed with IP54 ingress protection which means they are suitable for outdoor applications. However a roof should still be provided to cover the RMU for additional protection from direct sunlight and heavy rain as well as providing a comfortable working area for personnel. Ardex corrugated sheets can be used as the roof material because they are cheap, easy to install and durable.
4.4.4.2.2.
Floor
Fence/Wall
Ventilation blocks are to be used as walls for new installations and upgrading of the Outdoor P/E. The height of the walls needs to be at least 1800 mm to keep the substation equipment hidden from outside view. Installation of barbed wire on top of the wall can help to prevent unauthorised entry. Chain link fences can be used if the outdoor substation is located in an extremely low traffic area.
P/E, 11 kV SSU and S/S Design
4.4.4.2.3.
o
4.4.4.3.1.
Signboard/Signage
Suitable and sufficient signage as mentioned in Subchapter 4.2.4.4.2 must be installed.
4.4.4.3.
Doors
The door shall be erected preferably at 90 angle from the RMU location to enable quick exit in emergency situation during switching. Double leaf composite doors are to be used with the dimensions 1300 mm(W) x 1800 mm(H) each door.
4.4.4.2.5.
Drainage
Water drainage shall be provided at the corners of the walls at floor level to enable water to flow from within substation to the outside drainage.
4.4.4.2.4.
Installations Transformer Guard and Bushing Cover
Outdoor substations are more prone to entry by animals compared to indoor substations. As such, all transformer bushings are to be shrouded with transformer bushing covers to prevent interruption/tripping due to shorting by animals. Additionally, transformer guards also need to be installed as justified in Subchapter 4.2.4.3.2.
4.4.4.3.2.
Feeder Pillar
The feeder pillar is installed in a recessed part of the outdoor substation wall as in Figure 4-27. 4.4.4.3.3.
91
Earthing System
Copper tape/strip of 25 mm(W) x 3 mm thick (1”x1/8”) is used as the earthing conductor. The copper strip shall be direct buried in the ground. The earthing layout is shown in 9.2.3.3.
4
92
Substation Design Manual
4.4.5.
Safety Clearances
Outdoor P/E design should comply with the minimum working clearances presented in Subchapter 2.5. The proposed designs here have the following working clearances:
4
Clearance between transformer and wall/fence is 1500 mm. Clearance between switchgear and wall/fence is 495 mm.
P/E, 11 kV SSU and S/S Design
4.5.
93
Switching Station / Stesen Suis (S/S)
Switching stations or stesen suis (S/S) are built as part of system improvement to introduce switching or T-off points. They consist of RMU with three-switch (3S) configuration. The typical features of switching station are as follow:
Dimension : 3000 (L) x 3000 (W) mm Plinth able to support up to 5000 kg. Roof type: Ardex corrugated sheets. Civil criteria for outdoor substation for floor, plinth and roof can be applied to the switching station construction. Chain link fencing shall be built around the RMU to provide sufficient safety clearance.
Figure 4-32: Switching station / stesen suis (S/S)
4
94
Substation Design Manual
Figure 4-33 shows the location of a switching station in a single line diagram. When required, switches A and C can be turned on to provide feedback supply in the event of network failure.
4
S/S
NOP
NOP
A
B
C
Figure 4-33: Single line diagram of switching station
P/E, 11 kV SSU and S/S Design
4.6.
Compact Substation Unit (CSU)
4.6.1.
Overview
95
The Compact Substation Unit (CSU or Compact Sub) is a substation with type tested equipment comprising of a distribution transformer, medium voltage switchgear, low voltage feeder pillar, connections and associated equipment, all in a compact enclosed unit. A CSU is shown in Figure 4-34 and a basic line diagram is shown in Figure 4-35. Advantages of the CSU include: Require only a small site (7000 mm x 4000 mm); Physically small and therefore unobtrusive, and can be erected quickly; Available in 500 kVA and 1000 kVA capacities; Can be installed in a shorter time compared to a conventional substation. However, a disadvantage of the CSU is that if faults affect any individual component inside the unit, the whole unit may need to be replaced completely. Its capacity is also fixed and cannot be expanded. The CSU is also considerably more expensive than conventional substations. As such, the compact substation can only be considered as a last resort after all options have been exhausted on a case by case basis. It is considered as a special feature design in which special features cost is charged to the customer as per Clause 8.0 of Statement of Connection Charges 1994/1995. Circulars related to the compact substation unit are: 1. 2.
3.
A7-2004 Pekeliling Kejuruteraan & Logistik – Use Of Package or Compact Type 11 or 415 kV Substation In TNB Distribution Network A30-2009 Arahan Naib Presiden (Pembahagian) – Garis Panduan Penggunaan PE Padat Bersaiz 500 kVA Untuk Bekalan Elektrik Skim Pembangunan Perumahan A02-2011 Arahan Naib Presiden (Pembahagian) – Garis Panduan Penggunaan Pencawang Elektrik Padat Untuk Bekalan Elektrik Ke Kawasan Komersial
4
96
Substation Design Manual
4 Figure 4-34: A typical CSU
MV incoming
MV outgoing
RMU 11 kV, 630 A Transformer 11/0.433 kV
Feeder Pillar 800 A or 1600 A
Figure 4-35: Single line diagram of a CSU
P/E, 11 kV SSU and S/S Design
97
The technical and economic considerations in selecting CSU against standalone indoor type substations (P/E) can be summarised as follows: i. Demand estimates and demand growth to determine transformer size to be used ii. Space requirements, if any, notably by the developer iii. Aesthetic requirements, if any, notably by the developer and or local authority iv. Maintainability of components v. Life cycle costs comprising of capital cost, O&M cost, replacement and upgrading costs Other considerations may be satisfied during the design and planning stage. 4.6.1.1.
Application of CSU
Upon request from developer, CSU are allowed to be utilised for new housing and commercial developments, taking into consideration of appropriate distribution network design to ensure security and restoration time to consumers will not be affected. Additionally for all other situations, prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah) to deploy the CSU. Detailed explanations on the use of the CSU are as below. 4.6.1.2.
Development with Limited Land
In development areas that have limited land/space and cannot meet the minimum requirements of conventional standalone indoor substations, a compact substation can be considered. Examples would include instances of a temporary supply scheme, supply to street lighting along major roads, supply to major billboards or even supply to existing factories/outlets with limited available space. In these cases, the compact substation can normally be considered. Prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah)
4
98
Substation Design Manual
4.6.1.3.
Low Voltage Reinforcement of Existing Developed Area
Low voltage reinforcement of existing developed areas typically involves substation sites to be acquired by TNB. In case of this situation, the use of CSU is preferred subject to satisfying the following:
4
Insufficient space to construct a conventional indoor substation Cost of constructing a conventional indoor substation is more expensive compared to a CSU. A shorter duration of time is required to complete the low voltage reinforcement works.
Prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah) 4.6.1.4.
Temporary Use of the CSU
There are cases whereby CSU are used on a temporary basis for supply projects. These would include cases due to unavailability of certain materials or even due to demand/request from the customer/authorities to meet certain deadlines which may be ceremonial in nature etc. Prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah). 4.6.1.5.
CSU for New Domestic Developments
CSU 500 kVA is encouraged to be installed for new domestic development with the following guideline:
CSU 500 kVA to be placed close to the load centre. CSU 500 kVA not to be placed at the corners of one development. CSU 500 kVA cannot be placed close to each other to ensure efficient load distribution to the consumers. CSU 500 kVA is considered as ‘special feature design schemes’ in which special features cost is charged to the consumer.
CSU with sizes bigger than 500 kVA for domestic development requires prior approval from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah).
P/E, 11 kV SSU and S/S Design
4.6.1.6.
99
CSU for New Commercial Developments
Both 500 kVA and 1000 kVA CSU are allowed (upon request by developer) to be used in commercial areas depending on the load requirements. However, application of CSU in commercial development is considered as special feature design schemes in which a special features cost is charged to the consumer.
4.6.2.
CSU Layout
The dimension and weight of CSU are dependent on the transformer size and manufacturer. Table 4-11 shows typical dimensions and weight of a compact substation. Figure 4-36 is a layout view of the CSU. Table 4-11: CSU dimensions and weight Height Overall length Overall width
Weight
LV Feeder Pillar
2000 mm 2500 mm 2000 mm Without transformer: 1300 kg With 500 kVA transformer: 3310 kg With 1000 kVA transformer: 4500 kg Nominally: 5000 kg
Transformer
RMU
2000
Doors
2500
Figure 4-36: Top view of a CSU
4
100
Substation Design Manual
RMU
MV transformer tail
4
Figure 4-37: RMU compartment in a CSU
Incoming disconnector unit
Outgoing fuse-switch disconnectors
Figure 4-38: LV feeder pillar compartment in a CSU
P/E, 11 kV SSU and S/S Design
101
RMU Compartment 630A 11 kV 3-phase 50 Hz
HRC fuse
11 kV in
4
11 kV out
Transformer Compartment 11 kV/433 V Transformer 1000 kVA
LV Feeder Pillar Compartment
1 x 1600 A Incoming Disconnector A
3 x CT 1600/5 A
PF
kWh
x3
(0-1600 A)
F 10 x 400 A Outgoing Fuse-switch Disconnector
Figure 4-39: Detailed single line diagram of 1000 kVA CSU
102
Substation Design Manual
4.6.3.
Electrical Criteria
The voltage rating for the CSU is 11kV/433V and is currently only available in 500 kVA and 1000 kVA capacities. A summary of compact substation specifications and dimensions are given in the table below. Table 4-12: CSU technical specifications, measurement and dimension Power Rating Input Unit Output Unit
4
LV Feeder Pillar Metering
Transformer
Switchgear
Type Voltage Type Insulation Rated Voltage Rated Current
Kiosk/Enclosure Dimensions
4.6.4.
Cover Base
500 kVA 1000 kVA 1 x 800 A 1 x 1600 A 6 x 400 A 10 x 400 A CT, class 1.0, 7.5 VA Ammeter Power factor meter kWh meter Hermetically Sealed/Oil 11kV/433V Ring Main Unit (RMU) SF6 gas 12 kV Ring feeder – 630 A Transformer feeder – 200 A Mild steel Channel Steel
The overall maximum dimension for the enclosure should not 2 exceed 2.0 m height and 2.5 m x 2.0 m or 5.0 m sitting area
Civil Criteria
The following are guidelines to provide proper working environment for the equipment and personnel working around the CSU. The criteria mentioned here is applicable to both the 500 kVA and 1000 kVA CSU. 4.6.4.1.
Land Requirement
The required land area for a compact substation is 7000 x 4000 mm. This consists of the plinth and working clearance around the CSU.
P/E, 11 kV SSU and S/S Design
4.6.4.2.
103
Plinth
Minimum size of the CSU plinth is 4600 x 2200 mm. The CSU sits in the middle of the plinth and it must be able to support the weight of the CSU which is approximately calculated as 1.4 x 5000 kg = 7000 kg. The specification of the plinth shall be as in Figure 4-40 and Figure 4-41 below. Proper plinth design is important to ease cable laying and termination to the CSU. earth strip embedded in concrete plinth with earthing rod in earthing chamber 200x200mm
100
1000
100 150 100
150
460
150
400
A
Removable Concrete Removable Slab Concrete Slab
400
1600 1600
400
700
460
Trench Opening LVTrench cable Opening Termination
400
400
100
1000 900
100
150 150
300
A
150
770
1230
400
Trench Opening Trench 11kV cable Opening Termination 11kV cable
LV cable Termination
Termination
Removable Concrete
Removable Slab Concrete Slab
300
A 400
400
980
2200 2200
400
400
400
A
700
980
400
400
460
460
700
700
150150
300
150150
Foundation/RC structure to structural engineer’s details
Figure 4-40: Compact substation plinth (top view) Compact Sub
Compact Sub
900
900
100
Angle Iron Angle 50mm x 50mm
800 300
800
300
150
Iron 50mm x 50mm
2 layers 4 nos 150mmp 2 layerscable chute
600
600
900
900
100
4 nos 150mmp cable chute
150
100 50
100 50
800
800
Trench diisi dengan pasir
50 100
400
400
1230
1230
100mm thick concrete slab
800
800
Trench diisi dengan pasir
100 50
770
770
100mm thick concrete slab 1000
Trench diisi dengan pasir
Foundation/RC structure to structural engineer’s details
Trench diisi dengan pasir
50 100
Cement Ready-Mix Grade 25
100 50
4
Opening
100
1000 900
100
4600
1000 900
770
1230
400
900 100
300
Opening
Earth strip embedded in concrete plinth with earth strip embedded4600 in concrete plinth earthing rod earthing chamber 200 x 200 mm with in earthing rod in earthing chamber 200x200mm
2 layer 2 nos 150mmp cable chute
2 layer 2 nos 150mmp cable chute
150mm 1000 thick trench base on 50mm thick 150mm screed thick trench
base on 50mm thick screed
50 100
800
800
50 100
Figure 4-41: Compact substation plinth (side view – Section A-A)
104
Substation Design Manual
The area around substation plinth can be filled with crusher run and a thin layer of premix to ease maintenance work in a future and prevent unwanted vegetation growth.
4.6.4.3.
4
Compound Area
CSU do not require fencing because it complies with the Internal Arc Classification Class B requirement which is safe for the public in the event of fault occurring in the RMU. Developers/consumers are allowed to plant trees outside of the CSU site to help it blend into the surrounding area. However it should be provided that the 2 meters wide access road to the substation site is not blocked. Suitable and sufficient signage as mentioned in Subchapter 4.2.4.4.2 must be installed.
Figure 4-42: CSU with decorative plants
P/E, 11 kV SSU and S/S Design
4.7.
Pole Mounted Substation (PAT)
4.7.1.
Overview
105
Pole-mounted substations or Pencawang Atas Tiang (PAT), also known as H-pole substations, contain substation components and equipment that are safely and securely mounted on pre-stressed spun concrete poles. Polemounted substation designs can be used for both 33 kV and 11 kV systems to be stepped down to LV. It is the most economical substation because it does not require any high voltage switchgear and utilises only a small piece of land. These substations can also be erected in a very short amount of time due to its simple design and construction requirements. PATs are suitable for rural areas where the load density is low. At the same time, a larger number of these small capacity substations may be required to satisfy customer demand. Pole-mounted substations can be considered for the following conditions:
Flood prone areas Rural area with low load consumption (below 300 kVA) Limited land area
The disadvantages of PAT are that they are not encouraged as a permanent solution and not more than 3 such substations may be erected in series.
4
106
Substation Design Manual
As can be seen in the single line diagram in Figure 4-43, the PAT is connected to 11 kV or 33 kV MV feeders, preferably isolated by 3-pole switches, protected by external drop-out fuses, feeding to a transformer which steps down voltage to be distributed via an LV feeder pillar. Optionally, LV may be distributed through a fuse-switch disconnector (black-box) as shown in Figure 4-44.
4
MV incoming
Isolator link
MV outgoing
Isolator link
Lightning arrester
EDO Fuse
Distribution transformer Feeder Pillar Link switch
Fuse-switch disconnector
Figure 4-43: Single line diagram for pole-mounted substation connected to feeder pillar with MV isolator link
P/E, 11 kV SSU and S/S Design
MV incoming
Isolator link
107
MV outgoing
Isolator link
4
EDO fuse
Lightning arrester
Distribution transformer
Fuse-switch disconnector
Figure 4-44: Single line diagram for pole-mounted substation connected to fuse-switch disconnector (Black box) with MV isolator link
108
Substation Design Manual
4.7.2.
PAT Layout
4.7.2.1.
Major Components
Major components on the pole-mounted substation and their functions are listed in Table 4-13 and each component is shown on the poles in Figure 4-45 through Figure 4-49. Table 4-13: Pole-mounted substation major components and their functions No
4
Component/Equipment
Function
1
MV underground and MV ABC cables
As the incoming and outgoing of the substations
2
Covered jumper conductors
As a T-off Interconnector between equipment /component
3a
Isolator link
To provide isolation Must only be operated during off-load condition
3b
SF6 Load Break Switch (LBS)
Alternative to isolator link to provide isolation Can be operated in on-load conditions Some have the facility to earth the circuit
4
Lightning arrester
To discharge lightning strikes and protect transformer
5
Expulsion Drop-Out (EDO) fuse
Provides fused protection of the transformer The fuse will operate and provide isolation when there is a fault on the HV and LV side of the transformer
6
Insulating covers
Covers exposed parts of live components to prevent interruption of supply due to shorting caused by animals.
7
Distribution transformer
Transforms the MV voltage 33/0.433 kV or 11/0.433 kV
8
Fuse-switch disconnector 400 A (black box)
To provide isolation Provides fused protection of the downstream circuit by disconnecting immediately upon fault
9
Feeder pillar (FP)
To provide isolation Provides fused protection of outgoing circuits Electricity distribution point for LV system
P/E, 11 kV SSU and S/S Design
(3a) Isolator link
(2) Covered jumper conductors
(4) Lightning arrester (1) Underground MV cable
109
(5) EDO fuse
(6) Insulating covers
(7) Distribution transformer
Figure 4-45: Major components on the pole-mounted substation
4
110
Substation Design Manual
4
Figure 4-46: Fuse-switch disconnector on the pole-mounted substation
Feeder pillar LV feeders
Figure 4-47: Feeder pillar used with the pole-mounted substation
P/E, 11 kV SSU and S/S Design
111
Pin Isolator
Lightning arrestor Jumper Conductor EDO Fuse Isolator Link with animal guard Anti climbing device EFI
Figure 4-48: Typical 11 kV pole-mounted substation layout
4
112
Substation Design Manual
4
Figure 4-49: Typical 33 kV pole-mounted substation layout
P/E, 11 kV SSU and S/S Design
4.7.2.2.
113
Types of PAT
Generally, PAT can be classified into two types, 2-pole and 4-pole structures. The number of poles used in an H-pole structure is determined by the weight of the distribution transformer to be installed on it.
The type of pole used is 10 meter spun concrete pole (5 kN cantilever strength). Typically, 2-pole structures are sufficient to support 100 kVA transformers for both 33/0.433 kV and 11/0.433 kV. For 300 kVA and larger transformers for both 33/0.433 kV and 11/0.433 kV, the 4-pole structure is needed to cater for the additional weight. An example is shown in Figure 4-50. 33 kV link unit / isolator links are heavy and thus require a 4-pole structure.
Figure 4-50: 4-pole structure 11 kV PAT
4
114
Substation Design Manual
U-shaped channel irons are used to support the transformer, lightning arrester, EDO fuse and pin insulators on the pole. Channel iron dimensions and distance between the poles depend on the system voltage level as per Table 4-14. Equipment for 33 kV are larger and thus longer channel irons are required. Table 4-14: Sizes of channel Iron Pole-mounted System voltage level
Dimension of channel iron Length x Width x Height (mm)
Distance between the poles (centre-to-centre)
11 kV system
2500 x 100 x 50
1800mm
33 kV system
2800 x 100 x 50
2200mm
4
The number of channel irons required to support the transformer on the pole differs for each type of pole-mounted substation as follows:
2-pole structure requires minimum 2 pieces of channel irons. 4-pole structure requires minimum 7 pieces of channel irons.
Wooden cross arms, as shown in Figure 4-51, are forbidden to be used to substitute channel irons as an effort to reduce tripping of the system due to animals. This is because wooden cross arm is susceptible to decay especially when inferior wood is used.
P/E, 11 kV SSU and S/S Design
115
Wooden cross arms
4
Figure 4-51: Wooden cross arms shall not be used to replace channel irons
4.7.2.3.
Insulating Covers
All pole-mounted substations must be installed with insulating covers. These covers are used to cover the exposed parts of live components to prevent interruption of supply due to shorting between live parts or between live parts to earth by animals. The insulating covers are designed to be UV resistant and anti tracking since they will be used outdoors. There are 5 types of insulating covers to be used on PATs listed here and shown in Figure 4-52: 1. 2. 3. 4. 5.
Animal guard Conductor cover Lightning arrester cover Drop out fuse cover Transformer bushing cover
116
Substation Design Manual
(1) Animal guard
4 (2) Conductor cover
(3) Lightning arrester cover
6
(4) Drop out fuse cover
(5) Transformer bushing cover 7
Figure 4-52: Insulating covers for equipment on the PAT
P/E, 11 kV SSU and S/S Design
4.7.3.
117
Electrical Criteria
Table 4-15 summarises the standard electrical ratings for equipment on the 33 kV and 11 kV PAT. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-15: Pole-mounted substation ratings Equipment/component Transformer rating Tx installed capacity Isolator link
Rating 33/0.433 kV
11/0.433 kV
Expulsion Drop-Out (EDO) fuse
100 or 300 kVA Rated voltage: 36 kV Rated voltage: 12 kV Rated continuous current: 400 A Rated voltage: 36 kV Rated voltage: 12 kV Fault making capability: Fault making capability: 25 kA, 3s 20 kA, 3s Rated continuous current: 400 A Rated voltage: 36 kV Rated voltage: 12 kV Maximum Continuous Maximum Continuous Operating Voltage, Operating Voltage, MCOV = 29 kV MCOV = 9.6 kV Standard Nominal Discharge Current = 10 kA Line Discharge Class = Class 1 Rated voltage: 36 kV Rated voltage: 12 kV Rated continuous current = 100 A
Fuse-switch disconnector
Rated continuous current = 400 A
Feeder pillar (FP) MV underground cable
Rated continuous current = 400 A, 800 A, 1600 A Incoming and outgoing: Incoming and outgoing: 2 150 mm Silmalec bare 11kV XLPE 3C Al cable conductor or 33 kV ABC encased in 150 mm G.I. pipe or PVC Class B pipe 2 2 ABC, 33 kV 3 x 150 mm Al ABC, 11 kV 3 x 150 mm Al Connection to feeder pillar: LV XLPE, 4-core, 185 mm2, Al (for 100 kVA transformer) PVC/PVC, 1-core, 300 mm2, Al encased in 150 mm G.I. Pipe or PVC Class B pipe (for 300 kVA transformer) Connection to fuse switch disconnector: ABC LV 3x95 mm2 + 1x70 mm2 (for 100 kVA transformer) ABC LV 3x185mm2 + 1x120mm2 (for 300 kVA transformer) The outgoing cable from the fuse switch disconnector that connects to the first pole is typically LV XLPE, 4-core, 2 185 mm , Al underground cable
SF6 Load Break Switch (LBS)
Lightning arrester
Jumper conductor LV underground cable
4
118
Substation Design Manual
4.7.4.
Civil Criteria
The following are guidelines of typical civil requirements to provide proper working environment for the equipment and personnel working around the pole-mounted substation. Guidelines provided here are also applicable to all other substations with pole structures. 4.7.4.1.
4
4.7.4.1.1.
Structures Concrete Footing
The pole should be planted 1800 mm deep in the ground. Underground concrete footing is required as a support base for each pole. The dimension of the concrete footing is 760 (L) x 760 (W) x 760 (H) mm. 4.7.4.1.2.
Stay Wires
Usually, 4 numbers of stay wires are used to support the 2-pole structure. For 2 33 kV PAT where the primary incoming cable uses bare conductor 150 mm , Silmalec, the pole structure is to be supported by 4 numbers of stay wires (45 tonne, SWG 7/8).
Legend: Pole Transformer Stay wire
Main Road Figure 4-53: Stay wire (top view)
P/E, 11 kV SSU and S/S Design
4.7.4.1.3.
119
Concrete Base
For area that has limited space for stay wires, a concrete base (concrete grade 25) is used to support the structure. The dimension of the base depends on the system voltage level as shown in the following table. Table 4-16: PAT concrete base dimensions PAT system voltage
Dimension of concrete base
11 kV system
300 (H) x 760 (W) x 2600 (L) mm
33 kV system
300 (H) x 760 (W) x 3400 (L) mm
Concrete base
Concrete footing
Figure 4-54: Concrete base and footing for 11 kV PAT
4
120
Substation Design Manual
4.7.4.2. 4.7.4.2.1.
Installations Isolator for Incoming and Outgoing
Typically, direct connection from incoming cable to the jumper is widely practiced. However the use of isolator link or SF6 Load Break Switch (LBS) is preferred at both incoming and outgoing cables for ease of isolation as it can be operated in on-load condition.
4
SF6 load break switch
Figure 4-55: H-pole using SF6 Load Break Switch (LBS)
P/E, 11 kV SSU and S/S Design
4.7.4.2.2.
121
Lightning Arrester
Lightning arresters must be installed at HV jumper and at the first pole of LV overhead system. 4.7.4.2.3.
MV Feeder Cables
Buried underground cables are preferably used for feeder cables instead of overhead cables to connect to the first pole. This practice is to prevent animals like squirrels and monkeys from reaching the pole-mounted substation via any overhead line. All underground cables entering and leaving the PAT should be encased in 150 mm G.I. pipe or PVC class B pipe (3 m long, with 2.7 m above ground and 0.3 m underground) and attached to the pole for cable protection. All cable terminations must be of a type/brand pre-approved by TNB for use in the distribution system. For 11 kV connections the incoming and outgoing feeders use XLPE, 3-core, 2 150 mm , aluminium underground cables. Sometimes, the incoming cables consist of 11 kV ABC. For 33 kV connections, the incoming and outgoing feeders typically use 2 150 mm Silmalec or 33 kV ABC overhead cables, as the 33 kV PAT’s usually tap off from existing 33 kV overhead system to give LV supply to nearby areas. 4.7.4.2.4.
LV Feeder Cables
For LV system, typical connection from the secondary side of the transformer to the fuse switch disconnector or feeder pillar is shown below: Table 4-17: LV feeder cables specifications LV distribution equipment used
Typical cable connection from secondary side of transformer 100 kVA transformer
300 kVA transformer
Fuse switch disconnector 400 A
LV ABC, 2 2 3x95 mm + 1x70 mm
LV ABC, 2 2 3x185 mm + 1x120 mm
Feeder pillar
LV XLPE, 2 4-core, 185 mm , Al underground cable
LV PVC/PVC, 2 1-core, 300 mm , Al underground cable
4
122
Substation Design Manual
To achieve buried connection to the first pole of the low voltage overhead system for prevention of animal encroachment, the outgoing cable from the fuse switch disconnector that connects to the first pole is typically LV XLPE, 42 core, 185 mm , Aluminium underground cable. Underground cables should be mechanically protected from external factors by encasing them in:
4
Type of pipe: 150 mm G.I. pipe or 150 mm PVC class B pipe Recommended length: 3 m with 2.7 m above ground and 0.3 m underground
The single core cables must be laid in trefoil and must not be laid singularly (alone) in a G.I. pipe. This is to avoid induced and circulation currents in the G.I. pipe. Due to the height of the transformer on the PAT, the stressing effect of the weight of the connected cables to the LV transformer bushings, especially when LV underground cables are used, can be damaging to the bushings. Hence, proper and sufficient cable clamping must be provided to support the weight of the LV transformer tail. All cable terminations must be of a type/brand pre-approved by TNB for use in the distribution system.
P/E, 11 kV SSU and S/S Design
4.7.4.2.5.
123
Jumper Conductors
Jumper conductors connect the incoming cable to the lightning arrester, down to the EDO fuse and then to the HV bushing of the transformer. The conductors used are typically:
2
For 33 kV PAT – ABC, 33 kV 3x150 mm , Aluminium 2 For 11 kV PAT – ABC, 11 kV 3x150 mm , Aluminium
Jumper conductors are essentially covered conductors as they are unscreened and therefore have potential on them. As such, sufficient clearance must be ensured from the jumper conductors to any earthed metallic/conductive bodies on the pole.
4.7.4.2.6.
Feeder Pillars and Fuse-Switch Disconnectors
Fuse-switch disconnectors (black box) are widely used for connection to LV feeders. However, the use of a feeder pillar is also allowable to provide more outgoing LV feeders for better load distribution. Using several fuse-switch disconnectors to achieve this has the disadvantage of being prone to lose contact issue as several LV cables will be connected to a transformer bushing.
4.7.4.3.
Safety and Signage
Anti-climbing devices should be fitted at the pole section below the transformer channel iron base. This is to prevent excess to the high voltage zone. Substation signage with danger notices must be prominently displayed below the transformer channel iron base.
4
124
4
Substation Design Manual
Anti-climbing device
Substation signage
Figure 4-56: Substation signage
4.7.5.
Safety Clearances
(a) Ensure that under all possible conditions, the clearance from the ground level or any adjacent object which a member of the public can stand upon to the lowest live terminal is at least 3 meters. (b) Any un-insulated wires running down the pole for earthing purposes must be insulated or guarded in some way for at least 3 meters above the ground level. (c) Stay wires fitted to the pole should have insulators installed at least 3 meters above the ground level.
P/E, 11 kV SSU and S/S Design
4.8.
Pole Mounted Substation (PAT) with RMU
4.8.1.
Overview
125
Pole mounted substations (PAT) with insulating cover and ring main units (RMU) is a combination of insulated pole-mounted with outdoor substation for the 11 kV system. The advantages of the PAT and RMU are ease of operation, suitable to limited land area and cheaper construction costs compared to outdoor P/E. However, it is important to ensure that permission to use the appropriate land area is obtained from the local authorities. RMU 11 kV, 630 A 11 kV incoming
11 kV outgoing
Distribution transformer Fuse-switch disconnector
Figure 4-57: Single line diagram for PAT with RMU connected to fuse-switch disconnector
4
126
Substation Design Manual
RMU 11 kV, 630 A 11 kV incoming
11 kV outgoing
4
Transformer 11/0.433 kV
Feeder Pillar 1600A/800A
Figure 4-58: Single line diagram for PAT with RMU connected to feeder pillar
P/E, 11 kV SSU and S/S Design
4.8.2.
127
Layout of PAT with RMU
Main components on the PAT with RMU are similar to the standard polemounted substation. However a Ring Main Unit (RMU) functions as the isolating component.
Transformer bushing covers Transformer
RMU
Feeder pillar
Figure 4-59: Layout of PAT with RMU and fuse-switch disconnector
4
128
Substation Design Manual
4.8.3.
Electrical Criteria
Table 4-18 summarises the standard electrical ratings for equipment on the PAT with RMU. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-18: Major components in a PAT with RMU Equipment/component
4
Typical rating and size
Transformer
11kV/433V, 100, 300, kVA
RMU
12 kV, 630 A Configuration 2L + 1T
MV underground cable
Incoming and outgoing: 11 kV 3C cable encased in 2
150 mm G.I. Pipe (1.8m long)
Transformer T-off: 11 kV, XLPE, 3C, 70 mm2, Al, 2
encased in 150 mm G.I. Pipe (1.8 m long) as riser going up the pole LV underground cable
Connection to feeder pillar
LV XLPE, 4-core, 185 mm2, Al (for 100 kVA transformer)
PVC/PVC, 1-core, 300 mm2, Al encased in 150 2
mm GI pipe or PVC Class B pipe (for 300 kVA transformer) Connection to fuse switch disconnector
LV ABC 3 x 95 mm2 + 1 x 70 mm2 (for 100 kVA transformer)
LV ABC 3 x 185 mm2 + 1 x 120 mm2 (for 300 kVA transformer)
The outgoing cable from the fuse switch disconnector that connects to the first pole is 2 typically LV XLPE, 4-core, 185 mm , Al underground cable Fuse-switch disconnector
400 A
Feeder pillar (FP)
400 A 800 A 1600 A
P/E, 11 kV SSU and S/S Design
4.8.4.
129
Civil Criteria
The following are guidelines of typical civil requirements to provide proper working environment for the equipment and personnel working around the pole-mounted substation with RMU. In general, the construction of this substation should follow the guides presented in Subchapter 4.4 on outdoor substation structures and Subchapter 4.7 on pole-mounted substations. Table 4-19: Civil requirements of PAT with RMU Item
Minimum requirement
Size/dimension
Land size : 4000 (L) x 3000 (W) mm
Support structure
Switchgear area
Dimension : 3000 (L) x 3000 (W) mm Plinth able to support up to 5000 kg Roof type: Ardex corrugated sheets will be used Chain link fencing shall be built around the RMU and H-pole structure
LV system connection
Buried LV underground cables are used as the outgoing cables instead of LV overhead cable from the fuse-switch disconnector to the first pole. This practice is to prevent animals like squirrels and monkeys from reaching the pole-mounted substation via the LV overhead cable.
2-pole structure: To support up to 100 kVA transformer 2 spun pole 10 m (5 kN cantilever strength) The transformer is mounted on 2 channel irons/Uchannel** 4-pole structure: To support 300 kVA transformer 4 spun poles 10 m (5 kN cantilever strength) The transformer is mounted on 7 channel irons/ Uchannel** Pole to pole distance is 1800 mm **size for channel iron: - 11 kV : 2500 mm(L) x 100 mm (W) x 50 mm(H)
Compound area
Safety signage
Suitable and sufficient signage as mentioned in Subchapter
Civil criteria for outdoor substation for floor, plinth and roof can be applied to the PAT with RMU construction as in Subchapter 4.4.4.1. 4.2.4.4.2 must be mounted on the PAT (below the transformer channel iron base) or on the fencing of the switchgear area.
4
130
Substation Design Manual
Chapter 5: Design for Substations with Special Requirements This chapter presents general information concerning the design of the Mobile Switching Station / Stesen Suis Utama Bergerak (Mobile SSU) and mitigation methods for substations located in flood prone areas. It describes configurations, illustrates typical layouts, and presents technical criteria of these stations.
5
5.1.
Mobile SSU
5.1.1.
Overview
A mobile unit substation or mobile transformer is one in which all the components are mounted on a highway trailer. These units may be readily moved from one location to another by a prime mover. The Mobile SSU provides a preconfigured, plug‐and‐play package that minimizes installation time, effort and risk. It consists of a metal enclosure, containing all the substation‐related elements, including the Medium Voltage cubicles, low voltage distribution board, battery charger and other auxiliary devices. The Mobile SSU was introduced to perform the main functions as below: (a) To provide temporary supply for new projects while a permanent substation is being constructed. (b) To assist in improving SAIDI as it is an alternative for quick supply restoration by: i. Diverting the network through the Mobile SSU to ensure continuity of supply while a PPU undergoes rehabilitation/renovation works. ii. Providing temporary supply by replacing whole or part of a PPU which may be affected by any breakdown of the PPU equipment.
Design for Substations with Special Requirements
131
The Mobile SSU enables TNB to fulfil its commitment for high network reliability which in turn would enhance TNB’s service level. The advantages of the Mobile SSU are:
High mobility and fast connectivity to the distribution network. Minimises civil engineering work; fully assembled and tested in the factory, ensuring an optimum level of quality and reliability. Requires a small area of 13 m x 3 m to station the container.
5
Figure 5-1: Two Mobile SSU units
33kV S/G
3
2
11kV S/G
1
1
2
3
4
5
6
7
8
Mobile SSU
On-Site Transformer
Figure 5-2: Mobile SSU connected to an on-site transformer
132
Substation Design Manual
5.1.2.
Layout
All equipment for the Mobile SSU is contained inside a standard intermodal ISO container sized compartment, which is pulled on a trailer. Figure 5-3 below shows the dimension of the container. 12500 (41ft) Trailer Length
Landing Gear
Prime mover
5
2590 (8.5ft)
3940 (12.9ft) General height
1350 (4.4ft)
1820 (6ft) Track 2500 (8.2ft) Max width
Figure 5-3: Dimension of the container
Design for Substations with Special Requirements
133
Figure 5-4 below shows the locations of major components inside the Mobile SSU. A Mobile SSU typically consists of: 1.
2. 3.
4. 5. 6. 7. 8.
(1)
3 units of 33 kV GIS switching panels: (a) 1 incoming feeder (b) 1 outgoing feeder (c) 1 feeder to transformer 2 units of air-conditioning 7 units of 11 kV GIS switching panels: (a) 1 incoming feeder (from 33/11 kV transformer); and (b) 6 outgoing feeders 1 unit of marshalling cubicle for 33/11 kV transformer LVAC panel 10 Control and Relay Panels (CRP) for 33 kV and 11 kV switching panels Battery and battery charger compartment – the battery is either of sealed lead acid or compact dry and maintenance-free type. Fire fighting equipment
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Figure 5-4: Plan layout of the Mobile SSU All of the above components are installed in a standard 40 foot container sized 12.192 L x 2.438 W x 2.591 H meters (40’ 0” L x 8’ 0” W x 8’ 6” H feet). The container is also equipped with two air-conditioning units to ensure that the equipment is at optimal operating temperature. Each air-conditioning unit is operated alternately via auto-changeover switch to prolong their lifespan.
5
134
Substation Design Manual
The following figures show some of the equipment inside the Mobile SSU.
5
Figure 5-5: 11 kV GIS switching panels
Figure 5-6: 33 kV and 11 kV Control Relay Panels (CRP)
Design for Substations with Special Requirements
135
5
Figure 5-7: Low Voltage AC (LVAC) panel
Figure 5-8: Dry type battery cells in the battery compartment
136
Substation Design Manual
5
(a)
(b)
(c) Figure 5-9: Cable entry point into the GIS switchgears underneath the 2 2 2 Mobile SSU, (a) 3C x 240 mm , (b) 3 x 1C x 500 mm , (c) 3 x 1C x 630 mm
Design for Substations with Special Requirements
137
The Mobile SSU requires an external LV power source to provide supply to all LV instruments including battery charger and air conditioning. LV supply to the container is drawn from an external source and connected to the plug point located at the bottom of the container as shown in Figure 5-10.
5
Figure 5-10: LV supply plug point
Four earthing points are available on a Mobile SSU.
1 for 33 kV switchgears 1 for 11 kV switchgears 1 for CRP 1 for other equipment such as battery charger and LVAC
138
Substation Design Manual
These points shall be interconnected and then connected to a substation earth rod using proper earthing cables. Earthing connection methods are presented in Chapter 9.
5
Figure 5-11: Earthing Point
5.1.3.
Electrical Criteria
Table 5-1 summarises the standard electrical ratings for equipment in a Mobile SSU. PPUs typically have 10 to 14 feeders. The Mobile SSU is designed to supply for half-bus loads which is 7 feeders. Table 5-1: Ratings of Mobile SSU Item Voltage Busbar rating
Rating 33 kV & 11 kV single busbar 2000 A
33 kV Circuit Breaker rating
1250 A (for the transformer and feeders)
11 kV Circuit Breaker rating
2000 A for the transformer and 1250 A for the feeders
Short Time Withstand Rating
25 kA, 3 seconds
Internal Arc Rating
25 kA, 1 second
Design for Substations with Special Requirements
5.1.4.
139
Operating Specifications
The Mobile SSU conforms to the following standards and operating conditions: IEC 62271‐100, IEC 62271‐200 and IEC 62271‐102. 5.1.4.1.
Normal Service Condition
Operating temperature range The ambient temperature shall be in the range of –5°C to +40°C and the average value measured over a period of 24 hours must not exceed 35°C.
Installation altitude High‐voltage switchgear can be installed up to an altitude of 1000 meters. At higher installation altitudes, the reduced voltage endurance must be taken into account.
Air pollution The ambient air must be free of dust, smoke, corrosive or combustible gases, steam and salts.
5.1.4.2.
Prime Mover Type/Connection
Use of prime movers can be arranged through: Pengurus Besar Jabatan Perkhidmatan Logistik Bahagian Perkhidmatan Korporat Tenaga Nasional Berhad 129 Jalan Bangsar 50732 Kuala Lumpur The container is suitable for prime mover class 4 x 2 for loads less than 35 tonnes. The prime mover should also have fifth wheel coupler. The prime mover should have a 50.8 mm (2 inch) kingpin connection.
5
140
Substation Design Manual
5.1.4.3.
Equipment
The special tools/ test plug supplied with the Mobile SSU are:
5
MMLB07 Multi Finger Test Plug 2 Pfisterer Socket Size 3, 36 kV Termination Kit, 630 mm XLPE Aluminium Conductor 2 Pfisterer Socket Size 3, 36 kV Termination Kit, 500 mm XLPE Aluminium Conductor Conductor Current Test Plug Size 2 with Dummy Plug Manual Charging Handle for Circuit Breaker Operating Mechanism Manual Operating Handle for Isolator Tif‐Xp‐1a SF6 Leak Detector Dummy Plug Size 3
Special tools for plugging in power cable termination and SF6 filling are not supplied in the container. This service would be rendered by the site testing and commissioning contractor. 5.1.4.4. 5.1.4.4.1.
Logistics and Operation Ingress Protection
The IP class for the mobile SSU is IP55. 5.1.4.4.2.
Level of Parking Area o
The inclination of parking area should not exceed 10 while the mobile substation is in operation. 5.1.4.4.3.
Landing Gear
Two sets of landing gear supports are provided at the front and back side of the container. The container will stand on these landing gears while in operation. 5.1.4.4.4.
Wedge for Tyres
During parking, the mobile SSU will be supported by the landing gears and tyres. If wedges are to be used, the wedges suitable for 41 ft trailer are recommended.
Design for Substations with Special Requirements
141
5 Figure 5-12: Landing gears placed on solid and flat surface
5.1.4.4.5.
Vehicle Insurance
The mobile container requires its own comprehensive first party vehicle insurance, separate from the prime mover insurance. 5.1.4.4.6.
Road Tax
The container requires a separate road tax from the prime mover. For road tax renewal, the container should undergo road worthiness inspection annually at PUSPAKOM. 5.1.4.4.7.
Inspection Prior to Moving Vehicles
Prior to towing the container the followings inspection and actions should be taken:
Air brake is released Landing gear is raised Air conditioner cover for the condenser unit is securely installed. Tyre pressure is within 120 psi. All indicating and signal lights function properly.
142
Substation Design Manual
5.1.4.4.8.
Mobile SSU Transportation
The mobile container is subjected to road transport regulations with a maximum speed of 90 km/hour. 5.1.4.4.9.
Security
For the purpose of prevention of theft and unauthorized entry, pad locking options are provided at each door.
5
Figure 5-13: Provision for padlocks at each door
5.1.5.
Maintenance Specifications
5.1.5.1.
Vehicle
Landing Gear – The landing gear is suitable for weight of up to 30 tonnes. Axles – The container uses 2 axles with 60 tonnes combined capacity. Tyre – The container is equipped with 8 tyres installed on the axle with one spare tyre. The typical tyre size is 11 R x 22.5 x 16. The recommended tyre pressure is 120 psi.
Design for Substations with Special Requirements
5.1.5.2.
143
Equipment
The electrical installation shall be tested at each re‐location prior to start‐up, or at intervals not exceeding 6 months, whichever comes first. The result of all tests shall be recorded and retained. The general tests required are listed as follows: 5.1.5.2.1.
Visual Inspection
The Mobile SSU should be visually inspected for: Loose bolts and nuts Dust and foreign particles Dislocated parts Filing and chips Deformation, damage and wear Dislocated connectors and pins Loose switch terminals Rust Abnormal noise or smell Non working indicators 5.1.5.2.2.
Impedance to Earth of the Common Earth Grid
It is essential that the common earth grid is tested in order to ensure that the impedance to earth is not greater than the value required as calculated using IEEE Std 80 as in Subchapter 9.3. 5.1.5.2.3.
Insulation Resistance
The cable insulation resistance tests shall be carried out between phases and earth, between phases, and between phases and neutral.
5
144
Substation Design Manual
5.2.
Flood Prone Areas
5.2.1.
Overview
Generally, new substation sites should not be placed in flood prone areas. Meanwhile for existing substations in flood prone areas, mitigation steps need to be taken to prevent damage of substation equipment. The objectives of substation equipment for this process are: 1. 2.
5
3.
To minimize the risk of damage to TNB electrical installations during flooding. To ensure that the supply to the flooded area can be restored immediately once the water recedes. To maintain electricity supply to any unaffected area downstream even though there is a flood at the upstream of the electrical network.
The following flood mitigation techniques are summarized from Pekeliling PBK (Pengurusan Aset) Bil. A22/2012 – Kaedah Mitigasi Pencawang 11kV dan 22kV di Kawasan yang Dilanda Banjir.
5.2.2.
Methodology
The standard methodology for electrical installations flood mitigation is outlined below: 1.
2.
Maximum Flood Level – Get historical and expected worst flood level information from Jabatan Pengairan dan Saliran / Drainage and Irrigation Department (DID). This information will be used to construct the substation floor to a higher level than the worst flood level. Mitigation Technique – Select the appropriate mitigation initiatives. In general, the most suitable mitigation method shall comply to the following: (a) Safety issues when operating the equipment shall not be compromised. (b) The minimum clearance between tools/workers and the live parts should be met.
Design for Substations with Special Requirements
145
Initiatives for new and existing substations to reduce the effect of flooding upon the distribution network are explained as follows: 5.2.2.2.
New Substations
For new substations, the following should be implemented: (a) Site selection – avoid flood plains altogether. (b) Equipment selection – choose more flood resilient equipment. 5.2.2.3.
Existing Substations
In the case of existing substations, the aim is to elevate the substations above known flood levels and block water entry. Several mitigation options are suggested below: (a) Protection of individual equipment – raise plinth level for the equipment or the floor of the substation. (b) Protection of buildings – build a flood wall at the substation door (indoor), block water entry through cable trench or install submersible pump to pump out water from the substation. (c) Convert to pole mounted substation. (d) If the above mitigation options cannot be implemented, relocate the substation. Selection of mitigation techniques are based on the height of flood level and type of substation involved. The mitigation techniques for the following types of substations are further discussed in this chapter: 1. 2. 3. 4. 5.
Pole mounted substation (PAT) with feeder pillar Pole mounted substation (PAT) with RMU Outdoor substation Indoor substation Compact substation
5
146
Substation Design Manual
5.2.3.
Mitigation for PAT with Feeder Pillar
For flood level of less than 3 feet:
Raise feeder pillar plinth level to one foot above the flood level.
For flood level more than 3 feet:
If the water level reaches the transformer, the substation must be relocated.
This configuration will ensure that the MV feeder can still supply to other unaffected areas.
5
Figure 5-14: Raised feeder pillar plinth
5.2.4.
Mitigation for PAT with RMU
For flood level less than 3 feet:
Raise RMU plinth level to one foot above the flood level; or Replace the RMU with load break switch (LBS).
For flood level more than 3 feet:
If the water level does not reach the transformer, replace the RMU with load break switch. If the water level reaches the transformer, PAT must be relocated.
Design for Substations with Special Requirements
5.2.5.
147
Mitigation for Outdoor Substation
For flood level less than 3 feet:
Raise the RMU, transformer and feeder pillar plinths to one foot above the flood level; or Raise the substation floor to one foot above the flood level.
For flood level more than 3 feet:
Raise the substation floor to one foot above the flood level. If raising the floor is not possible, change the substation to pole-mounted substation (PAT). If both are not practical, the substation has to be relocated.
5
Figure 5-15: RMU, transformer and feeder pillar plinths are raised higher than the flood level
Figure 5-16: Pole-mounted substation (PAT) in a flooded area
148
Substation Design Manual
5 Figure 5-17: Raised substation floor level under 3 feet
Figure 5-18: Raised substation floor for flood level of more than 3 feet
Design for Substations with Special Requirements
5.2.6.
149
Mitigation for Indoor Substation
For flood level less than 3 feet:
Raise the RMU, transformer and feeder pillar plinths to one foot above the flood level; or Raise substation floor to one foot above the flood level; or Construct a water barrier / flood wall at the substation door and install a submersible water pump. Water entry through cable trenches should be blocked to minimise the amount of water entering the substation.
For flood level more than 3 feet:
Install flood walls and water pumps as above. If it is not practical to install flood walls at such height, the substation has to be relocated.
Figure 5-19: Raised RMU, transformer and feeder pillar plinths to above the flood level
5
150
Substation Design Manual
5
Figure 5-20: Water barrier / flood wall constructed at the substation door
Figure 5-21: Higher flood walls may require staircase access to be built
Design for Substations with Special Requirements
5.2.7.
151
Mitigation for Compact Substation
For flood level less than 3 feet:
Raise compact substation plinth to one foot above the flood level.
For flood level more than 3 feet:
Raise compact substation plinth one foot above the flood level. If this is not practical, change to PAT or relocate the substation.
5
Figure 5-22: Raised compact substation plinth one foot above the flood level
152
Substation Design Manual
5.2.8.
Guideline for New Substations
For new substations, the planner should consider the following:
All new substations should not be constructed in flood-prone areas. If this is unavoidable, the substation need to be built using the mitigation techniques suggested previously in this chapter. TNB may also request the developer to build a custom-designed substation building. An example is shown in the figure below.
5
Figure 5-23: Custom-designed substation building for flood-prone areas
Primary Equipment
Chapter 6:
153
Primary Equipment
6.1.
Transformer
6.1.1.
Overview
In “IEC Standard 60076 – Part 1: Power Transformers”, a transformer is defined as a static piece of apparatus with two or more windings which, by electromagnetic induction transforms a system of alternating voltage and current in one winding into another system of alternating voltage and current in one or more other windings, usually of different values and at the same frequency for the purpose of transmitting electrical power. An alternating voltage applied to one of the winding produces, by electromagnetic induction, a corresponding electromotive force (EMF) in the other windings. Thus energy can be transferred from the primary circuit to the other circuits by means of the common magnetic flux. Thus, a transformer is a device which transfers electric power from one circuit to another without electric connection while maintaining the frequency of the power source as a result of the transfer of energy. Laminated Core
primary
secondary
Figure 6-1: Magnetic circuit and windings of a transformer
6
154
Substation Design Manual
6.1.2.
Transformer Category
According to IEC 60076-1, windings in transformer can be classified into high voltage (HV) or low voltage (LV) windings. HV winding is defined as the winding having the highest voltage whilst LV winding is defined as the winding having the lowest voltage. Referring to this definition, transformers in TNB distribution system can be categorized into four categories:
6
Category 1 – Free breathing power transformers with On-Load Tap Changer (OLTC). This category of transformer has capacity above 5 MVA up to 30 MVA. Category 2 – Free breathing power transformers with Off-Circuit Tap Changer (OCTC). This category transformer has capacity of 3 MVA up to 5 MVA. Category 3 – Small power transformers with Off-Circuit Tap Changer (OCTC). However, this category of transformers has capacity above 1 MVA but not larger than 3 MVA and can be either free breathing or hermetically sealed transformers. Category 4 – Distribution transformer. It has primary and secondary windings designed to operate at high and low voltage or vice versa depending whether it is a step down or a step up transformer. This category of transformer has capacity not larger than 1 MVA and can either be a free breathing or hermetically sealed transformers.
Primary Equipment
6.1.3.
Transformer General Arrangement
6.1.3.1.
Distribution Transformer (9)
155
(8)
(10)
(7)
(11) (12)
(6) (1)
(5)
(2)
1. 2. 3. 4. 5. 6.
HV bushing Sampling/drain valve Jacking pad Corrugated fin wall Off circuit tap changer HV bimetal lug
(4) (3)
7. 8. 9. 10. 11. 12.
Pressure relief device (PRD) Oil level gauge LV bushing flag LV bimetal lug LV bushing Top-mounted thermometer
Figure 6-2: Distribution transformer (external view)
6
156
Substation Design Manual
(8) (9)
(7)
(10) (11)
(6)
(1)
(2)
(3) (5) (4)
6 1. 2. 3. 4. 5. 6.
HV winding LV winding Core (limb) Insulation (press board) Bottom clamping LV connection bar
7. 8. 9. 10. 11.
Top clamping Neutral bar LV bar (red phase) LV bar (yellow phase) LV bar (blue phase)
Figure 6-3: Distribution transformer (internal view)
Primary Equipment
157
6 Figure 6-4: A mock up construction of a distribution transformer showing the internal parts
158
Substation Design Manual
6.1.3.2.
Power Transformer (13)
(12)
(11)
(14) (15) (16) (18)
(17)
(10)
(19) (20)
(9)
(21)
(8) (7)
6 (6)
(1) (2)
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.
(3)
(4) (5)
Cooling radiator Main tank Motor drive unit (MDU) Lifting lug for complete unit HV cable box Oil level indicator Cable box breather Buchholz relay Cooling fan Core earth box Air leak detector
12. 13. 14. 15. 16. 17. 18. 19. 20. 21.
Main conservator OLTC conservator Pressure relief device (PRD) CT terminal box Local control panel (LCP) Inspection vent LV cable box Lifting lug for cover On load tap changer (OLTC) Top cover
Figure 6-5: Power transformer (external view)
Primary Equipment
159
(9) (10)
(8) (1)
(7)
(2)
(3)
(6) (4)
1. 2. 3. 4. 5.
Regulating winding HV winding LV winding Core (limb) Foot
(5)
6. 7. 8. 9. 10.
Support for winding Bottom clamping OLTC Top clamping CT (for winding temperature)
Figure 6-6: Power transformer (internal view)
6.1.4.
Transformer Design Characteristics
The transformers used in TNB distribution system are designed with specific characteristics to suit the system requirement for safe operation under normal service condition. By definition according to IEC 60076-1, normal service conditions are at an altitude of not greater than 1000 m above sea level, within an ambient temperature range of -25:C to +40:C, subjected to a wave shape which is approximately sinusoidal, a three phase supply which is approximately symmetrical and within an environment which does not require special provision on account for pollution and is not exposed to seismic disturbance. The basic design characteristics of distribution as well as power transformers in TNB distribution system are briefly explained in the following sub-chapters.
6
160
Substation Design Manual
6.1.4.1.
Rated Voltage
Rated voltage is the voltage in kV between line terminals at no-load of untapped winding i.e. LV winding or of a tapped winding i.e. HV winding connected on the principal (nominal) tap position.
6.1.4.2.
Voltage Ratio
Voltage ratio is the ratio of the rated voltage of HV winding to the rated voltage of LV winding. On the other hand, the voltage ratio notation for identification is indicated as HV/LV e.g. 33/11 kV for a step down transformer or LV/HV e.g. 11/33 kV for a step up transformer.
6.1.4.3.
6
Rated Power
Rated power is a conventional value of apparent power indicating the capacity of the transformer in kVA or MVA.
6.1.4.4.
Rated Current
Rated current is the current flowing through a line terminal of a winding (line current) which is derived from the rated power and rated voltage for the winding. For a three phase transformer, the rated current iR in the winding under consideration is given by: 𝑖𝑅 =
6.1.4.5.
Transformer Rated Power 3 × Rated Voltage of the Winding
Rated Frequency
The rated frequency corresponds to the network frequency i.e. 50 Hz at which the transformer is designed to operate.
Primary Equipment
6.1.4.6.
161
Short Circuit Impedance (Percentage Impedance)
Short circuit impedance of a transformer is the percentage voltage drop of the no-load voltage at full load current due to the winding resistance and leakage reactance. The impedance of a transformer has a major effect on system fault levels. It determines the maximum value of current that will flow under fault conditions. Thus, the percentage impedance of a transformer is designed to balance between the effect of limiting the short circuit current and at the same time maintaining the voltage drop within a permissible range. By using the percentage impedance of the transformer, a symmetrical three phase short circuit on the LV terminals will produce current if in Amps equal to: 𝑖𝑓 = 6.1.4.7.
Transformer rated power kVA × 100 3 × Rated voltage of LV winding kV × Percentage impedance Winding Connection and Vector Group
The information on winding connection and vector group of a transformer is very important to enable satisfactory operation of transformers in parallel. The interphase connections of the HV and LV windings are indicated by the capital and small letters respectively as shown in Table 6-1 . The winding connection letter is immediately followed by its phase displacement clock number. The letter symbols for the different windings are noted in descending order. Figure 6-7 and Figure 6-8 shows some examples on the phasor diagrams and clock number notations for typical transformer winding connections. Table 6-1: Winding connection designation Winding HV winding
LV winding
Winding Connection Delta Star Interconnected star (zigzag) Neutral Delta Star Interconnected star (zigzag) Neutral
Designation D Y Z N d y z n
6
162
Substation Design Manual
HV Winding
LV Winding
(a) 3-phase Delta-Star connection Dyn11
6
HV Winding
LV Winding
(b) 3-phase Star-Delta connection YNd11 Figure 6-7: Phasor diagrams and clock number notation showing phase displacement of +30⁰ for 3-phase transformers with connection symbols Dyn11 and YNd11
Primary Equipment
HV Winding
163
LV Winding
(a) 3-phase Delta-Star connection Dyn1 HV Winding
LV Winding
(b) 3-phase Star-Delta connection YNd1 Figure 6-8: Phasor diagrams and clock number notation showing phase displacement of -30⁰ for 3-phase transformers with connection symbols Dyn1 and YNd1
6
164
Substation Design Manual
6.1.4.8.
Losses and Efficiency
Losses of a transformer can be expressed in terms of no-load loss and load loss. These quantities are determined by means of tests at rated voltage for no-load test and at rated current for load loss. When a transformer is energised, a magnetising current is required to excite the core through the alternating cycles of a flux at a rate determined by the system frequency. The energy dissipated in doing so is known as the no-load loss, core loss or iron loss and it is present whenever the transformer is energised. Hysteresis and eddy currents losses contribute to over 99% of the no-load loss. The load loss, also known as winding loss, copper loss or short circuit loss of a transformer is generated by the flow of load current which varies as the square of the load current. Load loss can be divided into three categories:
6
2
Resistive loss (I R) within the winding conductors and leads. This type of loss dominates load loss. Eddy current loss in the winding conductors Stray loss due to leakage flux that intercepts the tanks and structural steelwork which give rise to the eddy current flow
Other losses are due to effect known as magnetostriction where magnetic flux in the core, causes it to physically expand and contract slightly with each cycle of the magnetic field, produces the humming sound commonly associated with transformers. This can cause losses due to frictional heating. In addition to magnetostriction, mechanical loss due to fluctuating forces between the primary and secondary windings as the result of the alternating magnetic field. These incite vibrations within nearby metalwork, adding to the humming noise and consuming a small amount of power. The guaranteed no-load loss and load loss in kW of distribution and power transformers are as shown in the tables that follow.
Primary Equipment
165
Table 6-2: No-load loss and load loss in kW of a distribution transformer kVA 100 300 500 625* 750 1000 1250* kVA 100
Load loss (kW) 1.5 2.8 4.1 1.2 1.4
6.6/0.433 kV No-load Total loss loss (kW) (kW) 0.3 1.8 0.6 3.4 1.0 5.1 1.2 1.4
7.2 8.4
22/0.433 kV No-load Load loss Total loss loss 1.6 0.24 1.84
11/0.433 kV No-load Total loss loss (kW) (kW) 0.3 1.8 0.6 3.4 1.0 5.1 1.3 6.0 1.2 7.2 1.4 8.4 1.8 9.7 33/0.433 kV No-load Load loss Total loss loss 1.5 0.3 1.8 Load loss (kW) 1.5 2.8 4.1 4.7 6.0 7.0 7.9
300
4.4
0.7
5.1
4.5
0.73
5.23
500 750
7.3 9.2
0.9 1.2
8.2 10.4
7.18 9.2
1.02 1.385
8.2 6.0
1000
11.7
1.5
13.2
11.85
1.665
7.0
*Note: Step up 0.415/11kV transformers
Table 6-3: No-load loss and load loss in kW of a power transformer
1.5
16.5
33/11 kV No-load loss 1.6
5
3.9
9
48
12.5
80
12
92
15
82
12
94
30
120
15
135
Load loss
22/11 kV No-load loss 2.5
Total loss
MVA
MVA
Load loss
2
19.5
Total loss
14.5
11/33 KV No-load loss 2.4
80
12
92
Total loss
Load loss
18.1
Load loss
22/6.6 kV No-load loss
16.9
Total loss
22
7.5
47
5
52
42
6
48
12.5
80
12
92
75
10
85
30
120
15
135
6
166
Substation Design Manual
The energy efficiency of a transformer is given by the following formula: %Efficiency =
=
Output Output + Losses
P × kVA × p. f × 1000 × 100 P × kVA × p. f × 1000 + NL + LL × P 2 × T
Where, P = per unit loading NL = no-load loss in watts LL = load loss in watts at full load, at 75˚C T = temperature correction factor (T at 75˚C is 1.0) p.f = power factor
6
Example of energy efficiencies at 0.9 lagging power factor for TNB distribution transformers of various sizes calculated using the above formula are as plotted in the graph of Figure 6-9. The graph shows that distribution transformers are most efficient between 0.4 to 0.5 per unit loading. It also shows that bigger capacity transformers by design, for example 1000 kVA, are more efficient as compared to the lower capacity, for example 100 kVA. Despite these facts, loading of a transformer and selection of transformer capacity should not be based merely on losses or efficiency of the transformer but should also consider for asset optimization. This is because the transformer loaded at between 0.5 and 1.0 per unit loading has relatively small difference in efficiency as compared to loading between 0.4 and 0.5 per unit loading.
Primary Equipment
167
Currently, energy efficiency of TNB distribution transformers are at par with the current class 1 energy efficient transformers in the U.S. (NEMA TP-1) and Europe (HD 428 C-C’), and they are comparable with future minimum energy efficient standards in the U.S. (TSL2) and Europe (EN-50464-1:2007 Ao-Ak).
6
Figure 6-9: Energy efficiency of distribution transformers of different capacities at various per unit loading
168
Substation Design Manual
6.1.4.9.
Noise Pressure Level
The average noise pressure level of a transformer is measured at 0.3 m from the radiating surface, where the measurement should be performed according to IEC 60076-10. The maximum permissible sound level by receiving land as recommended by the Department of Environment in its planning guideline for environmental noise limits and controls are as follows: Table 6-4: The Maximum Permissible Sound Level by Receiving Land Receiving Land Use Category
6
Day Time 7.00 am - 10.00 pm
Night Time 10.00 pm - 7.00 am
50 dBA
40 dBA
55 dBA
45 dBA
60 dBA
50 dBA
Commercial Business Zones
65 dBA
55 dBA
Designated Industrial
70 dBA
60 dBA
Noise Sensitive Areas, Low Density Residential, Institutional (School, Hospital), Worship Areas. Suburban Residential (Medium Density) Areas, Public Spaces, Parks, Recreational Areas. Urban Residential (High Density) Areas, Designated Mixed Development Areas (Residential - Commercial).
As such, the design and construction of all types of substations should strictly follow the requirement underlined by the latest revision of ESAH in order to ensure the noise generated by a transformer is contained within the substation so that the noise radiated outwards from the substation will not exceed the specified limits above.
Primary Equipment
169
6.1.4.10. Rated Insulation Level Rated insulation level is a set of standard withstand voltages which characterize the dielectric strength of the insulation used. The level is identified by the highest voltage (rms) for equipment U m, associated with the winding. The rules for coordination of transformer insulation with respect to transient overvoltages are formulated differently depending on the value of Um. The rated insulation levels for standard dielectric insulation requirement, i.e. lightning impulse withstand voltage, LI (peak) for the line terminals and separate source AC withstand voltage (rms) for transformers in TNB distribution network in accordance with IEC 60076-3 are as tabulated in Table 6-5. Table 6-5: Rated withstand voltages for transformer windings Highest Voltage Um of HV & LV Windings
Insulation Level AC
LI
Winding with Um = 36 kV
70 kV
170 kV
Winding with Um = 24 kV
50 kV
125 kV
Winding with Um = 12 kV
28 kV
75 kV
Winding with Um 1.1 kV
3 kV
-
6.1.4.11. Temperature Rise Temperature rise is the difference between the temperature of the part under consideration i.e. top oil or winding temperature and the ambient (surrounding) temperature, when the transformer is loaded up to its nameplate rating. A transformer with a lower temperature rise is more efficient since it consumes less energy and generates less waste heat and contributes to a longer life expectancy. On the other hand, lower temperature rise will incur additional cost since more cooling medium or improved cooling system is required.
6
170
Substation Design Manual
6.1.4.12. Overloading The normal design life expectancy of a transformer is based on continuous duty under design ambient temperature and normal service or rated operating conditions. However, the application of a load in excess of nameplate rating and an ambient temperature higher than design ambient temperature involves a degree of risk and accelerated ageing that reduces the expected design life of the transformer. Although the maximum loading capability of the transformer can be safely set to 100% under normal condition of its capacity for a design ambient temperature of 40:C, it is technically possible to overload the transformer under the following conditions:
6
Normal cyclic loading – loading of a transformer at higher ambient temperature or a higher than rated load current during some part of the 24 hour cycle where the average loading is equivalent to the rated load at normal ambient temperature. Long time emergency loading – loading of a transformer at higher ambient temperature or a higher than rated load current for a prolonged part of the 24 hour cycle due to system outage that will not be normalized before the transformer reaches a new and higher steady state temperature. Short time emergency loading – unusually heavy loading of a transformer of transient nature of less than 30 minutes due to the occurrence of one or more unlikely events which seriously disturb normal system loading.
The risks or consequences of loading a transformer beyond its nameplate rating are:
Damage of the dielectric strength of the transformer insulation due to development of gas bubbles as the result of hot-spot temperature exceeding 140:C that could occur at the winding, leads or cleats. Eddy-current heating in metallic parts as the result of increased leakage flux outside the core. Damage of bushings, tap changer, terminations and current transformer, due to higher stresses beyond their design limits.
Primary Equipment
171
Due consideration should also be given on the withstand capability of other equipment in the system such as power and auxiliary cables, secondary system and equipment as well as settings of protection relays before decision to overload the transformer is made. Overloading of a transformer beyond its nameplate rating shall therefore be performed strictly in accordance with IEC 60076-7 and TNB Distribution Planning Guideline.
6.1.4.13. Tap Changer and Tapping Range Tap changer is a device used for changing the tapping connection of a winding to regulate voltage level affected by load variations. There are two types of tap changer used, the Off-Circuit Tap Changer (OCTC) and On-Load Tap Changer (OLTC) which are explained further under Subchapter 6.1.5.6. Tapping (regulating) range is the variation range of the tapping factor expressed as a percentage of the rated nominal voltage of the tapped winding i.e. HV winding. The typical tapping range of power and distribution transformer tap changers is shown in Table 6-6 below. Table 6-6: Tapping range according to transformer category Tapping Range (%)
Tapping per step on HV Winding (%)
Nominal Voltage on HV Winding (V)
Highest Voltage at Lowest Tap (V)
Lowest Voltage at Highest Tap (V)
33/11, 33/22-11
+10% to -15%
1.67%
33000
36300
28050
11/33
+15% to -10%
1.67%
33000
37950
29700
22/11
+10% to -15%
1.67%
22000
24200
18700
22/6.6
+9% to -16.5%
1.5%
22000
23980
18370
+5% to -5%
2.5%
33000
34650
31350
+5% to -5%
2.5%
22000
23100
20900
+5% to -5%
2.5%
33000
11550
10450
Transformer Transformer Voltage Ratio Category (kV)
Category 1
33/11, 33/0.433 Category 2, 22/11, 11/22, 3&4 22/0.433 11/0.433 0.415/11
6
172
Substation Design Manual
Typical design characteristics for distribution and power transformers are summarized in Table 6-7 and Table 6-8 respectively. Table 6-7: Category 1 & 2 Transformer Basic Technical Parameters Category Rated Voltage Ratio & Power Power Transformer with OLTC (Category 1)
6
Power Transformer with OCTC (Category 2)
Technical Parameter 33/11 kV
7.5 MVA, 15 MVA, 30 MVA
22/11 kV
12.5 MVA, 22.5 MVA
22/6.6 kV
3.5 MVA, 7.5 MVA, 12.5 MVA
33/22-11 kV (Dual ratio)
30 MVA
33/11 kV
7.5 MVA, 15 MVA, 30 MVA
11/33 kV*
7.5 MVA, 15 MVA
33/11 kV
5 MVA
No. of phases & rated frequency
3-phase, 50 Hz
Short Circuit Impedance
9 to 11% at reference temperature of 75°C with tolerance of ±10%
Vector Group
Dyn11, YNd1*, Ynd11*
Losses
Refer to 6.1.4.8
Maximum Noise Pressure Level
55 dBA
Insulation Level
Refer to 6.1.4.10
Temperature Rise
60°C (Top Oil), 65°C (Winding)
Tapping Range
Refer to 6.1.4.13
*Step-up transformer
Primary Equipment
173
Table 6-8: Category 3 & 4 Transformer Basic Technical Parameters Category Rated Voltage Ratio & Power Small Power Transformer (Category 3)
Technical Parameters 33/11 kV
1.5 MVA
22/11 kV
2 MVA
11/22 kV*
2 MVA
33/0.433 kV 22/0.433 kV
Distribution Transformer (Category 4)
11/0.433 kV
100, 300, 500, 750, 1000 kVA
6.6/0.433 kV 0.415/11 kV*
300, 625, 1250 kVA
No. of phases & rated frequency
3-phase, 50 Hz
Short Circuit Impedance
4.75% at reference temperature of 75°C with tolerance of ± 10%
Vector Group
Dyn11, YNd1*, Ynd11*
Losses
Refer to 6.1.4.8
Maximum Noise Pressure Level
60 dBA
Insulation Level
Refer to 6.1.4.10
Temperature Rise
60°C (Top Oil), 65°C (Winding)
Tapping Range
Refer to 6.1.4.13
*Step-up transformer
6
174
Substation Design Manual
6.1.5.
Transformer Construction
The main parts of a transformer are the core, the windings, transformer tank to house the core and windings; bushing terminals for the external electric circuit connection and the cooling arrangements to remove heat generated in the core and winding for dissipation. 6.1.5.1.
Core
The purpose of transformer core is to provide a low reluctance path for the magnetic flux linking primary and secondary windings. The core is made up of stacks of thin laminated magnetic sheet. Each lamination is insulated by a thin non-conducting layer of insulation that increases resistivity of the material to minimize the eddy current loss. The use of high permeability grain oriented silicon steel is preferred due to its improved grain orientation to reduce hysteresis loss.
6
The transformers used in TNB distribution system is of three-phase core with three-limbs which are magnetically connected with each other at the upper and the lower ends by yokes. In three-phase transformers, all the windings for each phase are located at their own limb.
Figure 6-10: Distribution transformer three-limb core
Primary Equipment
175
Figure 6-11: Core construction of power transformers
6
Figure 6-12: Complete core winding assembly
𝜙1
𝜙3
𝜙2
Window
Yoke
Limb
Figure 6-13: Three-limb transformer design that shows the flux
176
Substation Design Manual
6.1.5.2.
Winding
A winding is made up of conductors, coiled concentrically around the magnetic circuit limbs to produce the desired number of turns in which will determine the voltage of the winding. The conductor is usually made of copper which is electrically insulated from each other with paper and in some cases with enamel and paper to ensure that the current travels throughout every turn. The number of turn and the current in the winding primarily determine the choice of winding type. The maximum current density in any winding is 2 designed usually not higher than 3 A/mm to reduce the dynamic effect during short circuit.
6
Figure 6-14: Distribution transformer windings
Enamel coating Conductor
Figure 6-15: Enamelled copper conductor
Primary Equipment
177
Figure 6-16: Single strand with Kraft paper insulation
Figure 6-17: Continuous transposed cable (CTC)
Windings for transformers can be divided into four main types: Layer windings Foil windings Disc windings Helical windings Distribution transformers are usually designed having layer winding on the HV and foil winding on the LV, whilst power transformers have disc winding on the HV and either disc or helical winding on the LV, depending on the value of the rated current. For layer type winding, the turns are arranged axially along the winding. The consecutive turns are wound close to each other without any intermediate space. The winding may be made as a single or multilayer winding.
6
178
Substation Design Manual
Figure 6-18: Layer type windings Foil windings are made of wide copper sheet, from some tenths of millimeter up a few millimeters thick. It is usually used for windings with a small number of turns but relatively high currents. The main technical advantage is that axial mechanical forces acting on the windings in the transformer during short circuit currents become insignificant.
6
Figure 6-19: Foil winding
Primary Equipment
179
The disc winding concept is used for windings with a large number of turns and relatively small currents. It is built up of a number of discs connected in series. The major difference between a helical and a disc winding is the number of turns per disc. In helical windings there is never more than one turn per disc while disc windings have more than one turn per disc.
6
(a)
(b)
(c) Figure 6-20: Disc winding
180
Substation Design Manual
The helical winding is suitable for high currents where the current is shared between several parallel strands. The quantity of conducting material that can be fitted inside a given volume is high compared to other types of winding. Moreover it is mechanically robust and easy to manufacture, particularly when continuously transposed cable is used.
6
(a)
(b)
(c) Figure 6-21: Helical winding
Primary Equipment
181
Tapping (regulating) winding is usually wound at the outermost winding in a power transformer for easy connection to the OLTC. Similar to the type of windings mentioned above, tapping winding can either be made in layer, helical or disc winding depending on the design requirement. 6.1.5.3.
Transformer Insulation
Transformer main insulation can be divided into solid and liquid insulation. Solid insulation in transformers consist mainly of oil impregnated paper and pressboard. These are cellulose materials, which include Kraft, creped, presspaper and diamond dotted paper (presspaper with partial resin coating). Other type of cellulose materials are manila and rag paper as well as cotton jute and linen fibres. Nowadays, thermal upgraded paper is preferred. It is a normal cellulosic paper treated by the addition of stabilizers during manufacture to provide better temperature stability and reduced thermal degradation. Mineral hydrocarbon oil has been the major liquid electrical insulation due to its high dielectric strength to withstand the electric stresses imposed in service. It also has sufficiently low viscosity to circulate and transfer heat, thus it has been used as cooling medium in power transformers. The combination of oil and cellulose material is one of the most satisfactory insulant yet known and the electrical and thermal strength of this combination is much higher than that of the individual materials used separately. For example in terms of temperature rise, cellulose material alone is of Class Y insulation with thermal withstand capability of up to 90:C. However, with the impregnation of oil, the cellulose material has become Class A type insulation with the maximum thermal withstand capability of up to 105:C.
6
182
Substation Design Manual
6
Figure 6-22: Samples of cellulose insulations used in transformers
Primary Equipment
6.1.5.4.
183
Tank and Preservation System
Tanks are designed to house the core and windings complete with oil so that it can be lifted or moved by cranes, winch or jacks without over straining any joints and without causing damage to the internal active parts and cause subsequent leakage of oil. Some tanks are fitted with skid under bases suitable for handling with roller bars. The skids are drilled to accommodate axles and rollers when required. In practice, there two types of transformer tank construction i.e. conventional type tank with flat top cover mounted or belt type tank where the cover junction or belting is near the bottom of the tank, dividing the complete tank into top tank and bottom tank.
6
Figure 6-23: Conventional type tank
Figure 6-24: Belt type tank
184
Substation Design Manual
Distribution transformers have corrugated tank design to function as cooling fins. All distribution transformers in TNB distribution system used after the year 1990 are of cover mounted tank type with hermetically sealed preservation system. The tank, which does not require nitrogen or air cushions, is completely filled with oil. The expansion and contraction of oil, due to temperature fluctuations, is taken up by the expendable tank corrugations. Transformer tanks are designed to withstand an internal overpressure of 28 – 35 kPa (4 – 5 psi) in excess of that required to operate the pressure relief device. The design of the tank is suitable for use as ground mounted or pole mounted transformer. The tank is sealed in every opening point with sealant and O-rings or flat type gaskets made of synthetic rubber bonded cork or hot oil resistance synthetic rubber (Neoprene) that is of chemical and thermal resistant for hot oil up to 120°C.
6
Figure 6-25: Hermetically sealed type transformer
Primary Equipment
185
Another type is a free breathing conservator type transformer where the expansion of oil due to temperature or pressure increase is taken up by the conservator. The most importance feature and use of a conservator are: (a) To allow for expansion and contraction of oil which is temperature dependent. (b) To reduce the surface area of the oil exposed to atmospheric air so that contents of oxygen gas dissolved in the oil is reduced, thus reduces the rate of oxidation of the oil which would otherwise tend to shorten insulation life. (c) To allow the main tank to be filled to the top cover, thus permitting oilfilled bushing and the use of a gas actuated relay in the connection pipe between the main tank and the conservator of a power transformer.
6
Figure 6-26: Conservator type distribution transformer
186
Substation Design Manual
Figure 6-27: Conservator type power transformer
6
For distribution transformer, hermetically sealed type is more advantageous compared with the conservator type transformer. The main advantage is that the oil is not in contact with the atmosphere, thus avoiding absorption of moisture and oxygen from the environment that can speed up the degradation process of the insulation.
6.1.5.5.
Cooling System
More than 85% of the heat generated in a transformer is caused by the resistive loss in the winding and the remaining by the stray losses in the structural metal parts of the transformer. Transformers utilize cooling systems to transfer the heat produced to the surroundings and control the temperature rise. This heat transfer mechanism helps to prevent the core, windings, or any structural parts from reaching critical temperatures that could deteriorate the insulation.
Primary Equipment
187
The cooling designations for oil immersed transformers expressed in fourletter code in accordance with IEC 60076-2 are described in Table 6-9. Typical types of cooling systems used in TNB distribution system are ONAN and ONAF. In ONAN type cooling system, heat is transferred from the windings, core and structural metal parts to the oil. The heated oil circulates in the transformer tank by the principle of natural convection and it is cooled by the natural air. Cooling fins and radiators provide the means of increasing the area for heat dissipation. In ONAF type cooling system, fans mounted on the radiators, are used to force an air blast on the radiators to increase the heat dissipation rate. The fans are automatically switched on when the temperature of the oil and windings increases above the permissible value. This happens during heavy load condition and during higher ambient temperatures. Forced cooling can increase the kVA rating of an oil immersed transformer by 15% to 30%. Table 6-9: Cooling designation four letter code First letter O K L Second letter N F D Third letter A W Fourth letter N F
Internal cooling medium in contact with the windings Mineral oil or synthetic insulating liquid with fire point < 300:C Insulating liquid with fire point > 300:C Insulating liquid with no measurable fire point Circulation mechanism for internal cooling medium Natural convection flow through cooling equipment and windings Forced circulation through cooling medium, natural convection in windings Forced circulation through cooling medium, with directed flow through at least the main windings External cooling medium Air water Circulation mechanism for external cooling medium Natural convection Forced circulation (fans, pumps)
6
188
Substation Design Manual
6.1.5.6. 6.1.5.6.1.
Tap Changer Off-Circuit Tap Changer (OCTC)
Off-Circuit Tap Changer (OCTC) or sometimes called De-energised Tap Changer (DETC) is a simple, cheapest but reliable device that can be used as a mean of adjusting transformer voltage ratio by adding or removing tapping turns. It is connected on the HV side and designed only to be operated when the transformer is de-energised. Thus it is only applicable to installations in which the loss of supply can be tolerated. In TNB distribution system it is applicable for distribution and small power transformers up to 5 MVA 33/11 kV. Figure 6-28 shows the typical OCTC used in distribution transformers. The OCTC connection types normally employed in the distribution transformers are Linear and Single Bridging type as shown in Figure 6-29.
6
Figure 6-28: Off circuit tap changer
(a)
(b)
Figure 6-29: Off circuit tap changer basic connection type (a) Linear and (b) Single Bridging
Primary Equipment
6.1.5.6.2.
189
On-Load Tap Changer (OLTC)
The function of an OLTC is to switch from one winding tap to another without interrupting the load current. OLTC can be installed inside the transformer (intank) or in an externally mounted compartment which is welded or bolted to the transformer tank. Figure 6-30 illustrates both of the OLTC installation types.
6
Figure 6-30: Type of OLTC installation showing in-tank (left) and external compartment (right) There are two different designs of OLTC which are the diverter switch type and the selector switch type OLTC. Figure 6-31 (a) shows diverter switch type which has a tap selector and a diverter switch in a separate compartment; and (b) the selector switch type also known as arcing type selector which combines both functions of tap selector and diverter switch in one oil-filled compartment. The oil filled compartment is a free breathing tank connected via a pipe to a conservator with the addition of a dehydrating breather to remove moisture from the air that is in contact with the oil as shown in Figure 6-32. On the other hand, there are two switching principles that have been used for the load transfer operation during tapping transition i.e. by means of high speed resistor or reactor.
190
Substation Design Manual
Change-over selector
Diverter switch
Selector/Arching switch Transition resistors
Tap selector
(a)
(b)
Figure 6-31: Two Different Types of OLTC (a) Diverter Switch Type OLTC, (b) Selector Switch Type OLTC
6
1. 2. 3. 4. 5.
OLTC Cover Oil Compartment (Belly Tank) OLTC Insert Motor Drive Unit Oil Surge Relay
6. 7. 8. 9.
Oil Conservator Horizontal Drive Shaft Vertical Drive Shaft Bevel Gear
Figure 6-32: OLTC general arrangement showing oil filled compartment, conservator and motor drive
Primary Equipment
191
Majority of OLTC designs used in power transformers of TNB distribution system is of in-tank selector switch type with oil immersed switching (arcing) contacts and transition resistors for load transfer operation. The switching arcs occur in oil due to the making and breaking of currents during normal tap change operation. These arcs cause carbonization of oil that reduces the dielectric strength of the insulating medium. They also cause heating of oil that speed up its degradation process thus requires shorter maintenance intervals of the OLTC. The new technology confines the current switching in interrupted vacuum bottles where the switching contacts are no longer immersed in the oil of the OLTC compartment. This new breed of OLTC known as the Vacuum Switch OLTC helps to prevent contamination of oil due to carbonization and hence lower the rate of oil degradation due to heating. As the results, the OLTC has longer maintenance intervals up to 300,000 switching operations and thus reduces maintenance costs.
Change-over selector
Roller type arcing switch
Transition resistors
Figure 6-33: OLTC compartment and insert of oil Immersed switching contacts
6
192
Substation Design Manual
Vacuum switch
6
Figure 6-34: OLTC compartment and insert of vacuum switch OLTC
There are three different kinds of connecting schemes to which the OLTC can be connected to the tapping winding (Figure 6-35) which are: (a) linear, (b) plus/minus; and (c) coarse/fine. Tapping winding in linear arrangement is commonly used for small tapping ranges e.g. 10% of nominal voltage. The addition of the tapping winding connected in series with the main winding results in the addition of voltage across the tapping winding to the voltage across the main winding.
Primary Equipment
193
6 Figure 6-35: Typical arrangements of tapping winding for OLTC connection On the other hand, for larger tapping ranges, tapping winding in plus/minus or coarse/fine arrangements can be used. In plus/minus arrangement, the tapping winding is connected to the main winding via a change-over selector that functions as plus minus switch. This switch provides an ability to add or subtract the voltage of the tapping windings to or from the voltage of the main winding allowing the tapping range to be doubled and at the same time reduce the number of the tapping windings. In a coarse/fine arrangement, the tapping winding is split into two groups, coarse and fine windings. The coarse winding can be connected or disconnected in series to the main winding to provide the larger addition or subtraction of voltage whilst the fine winding is added or subtracted sequentially with the smaller value of tapping step voltage.
194
Substation Design Manual
Oil Surge Relay
The oil surge relay is an oil-flow controlled relay installed between the OLTC head and the conservator. Faults even at low-energy can lead to oil flow in the OLTC oil compartment. The relay will trip when the specified oil flow speed between the on-load tap-changer head and the oil conservator is exceeded. However, any gases generated during OLTC switching will escape via a small opening in the relay unobstructed to the oil conservator. The relay operates according to the principle of a movable flap valve. When triggered, the flap valve operates a reed switch and makes a signal available. Once it has been triggered, the flap valve remains in its position and has to be reset manually.
6
Rupture disk
Oil surge relay
Figure 6-36: Oil surge relay showing the internal components
Primary Equipment
195
Rupture Disk
The rupture disk is a pressure-relief device without signaling contact located in the OLTC cover. Faults with large energy release can lead to strong pressure waves with high pressure peaks, which can damage the on-load tap changer oil compartment. An overpressure of more than 5 bar will rupture the disk and enables the pressure to relieve immediately.
Motor Drive Unit
Generally, on-load tap changers come with a motor to provide the drive to allow the tap changer to operate. A typical OLTC with motor operating mechanism connected to the tap changer is given below in Figure 6-37. The Geneva gear principle is used to change a rotary motion into a stepping motion. Drive is transmitted via a shaft system and bevel gears from the motor-drive mechanism. A spring energy accumulator actuates the Geneva gear. The Geneva gear operates the selector switch and the change over selector. The Geneva gear is also used to lock the moving contact system into position.
Figure 6-37: Typical motor operating mechanisms
6
196
Substation Design Manual
6.1.5.7.
Dimensions & Weight
The maximum dimension and weight for new distribution and power transformers based on rated power is as shown in Table 6-10 and Table 6-11. Table 6-10: Maximum dimension and weight for new distribution transformers 11/0.433 kV
22/0.433 kV
Transformer Rated Power
L x W x H (mm)
Total Weight (kg)
L x W x H (mm)
Total Weight (kg)
100 kVA
1000x700x1200
900
1100x750x1340
1100
300 kVA
1250x870x1370
1410
1350x900x1450
1800
500 kVA
1500x940x1500
2010
1760x1120x1550
2200
750 kVA
1700x930x1630
2460
1710x1040x1830
2500
1000 kVA
1750x950x1800
3200
1950x1200x2030
3800
(a)
6
33/0.433 kV
Transformer Rated Power
L x W x H (mm)
Total Weight (kg)
100 kVA
1200x820x1570
1300
300 kVA
1450x920x1590
2050
500 kVA
1710x1020x1700
2400
750 kVA
1750x1020x1780
2900
1000 kVA
1880x1070x1820
3400
(b) Table 6-11: Maximum dimension and weight for new power transformer 33/11 kV Transformer
Complete Installation Arrangement
Transport Arrangement
L x W x H (mm)
Total Weight (kg)
L x W x H (mm)
Total Weight (kg)
1.5 MVA
2380x1400x2460
5500
2380x1400x2460
5500
5 MVA
3500x3300x3400
15000
3400x1480x2540
12000
7.5 MVA
5890x3140x3120
20000
3640x3020x3120
16550
15 MVA
6160x3730x3380
32300
3940x3730x3380
28750
30 MVA
7390x3900x4120
46800
4390x3900x3190
41900
30 MVA (33/22-11 kV)
7260x4950x4710
54350
4760x4950x3370
49300
Primary Equipment
6.1.5.8.
197
Fittings and Accessories
Transformers are provided with the following standard fittings and accessories: 6.1.5.8.1.
Bushing Terminals
Distribution and power transformers are equipped with outdoor type oil-air bushings made of solid porcelain on HV and LV sides for both phase and neutral terminals. All conducting parts of the bushing are designed for rated current of the transformers and capable to withstand overcurrent during earth fault and cyclic overloading. New distribution transformers come with cover-mounted open bushings whilst most of power transformers have side mounted bushings in air filled cable box. For distribution and power transformers, crimping type terminal lugs are provided where they are bolted onto the HV and LV bushing terminals. For new LV bushing design, bushing flag is provided on the LV and neutral terminals for the cable lug connection. Table 6-12: Crimping type terminal lugs for distribution transformers Transformer Rating
HV Terminals
LV Terminals
6.6, 11, 22, 33 kV
Phase
Neutral
100 kVA
1 x bimetal lug for 2 70 mm Al cable
1 x bimetal lug for 2 300 mm Al cable
1 x bimetal lug for 2 300 mm Al cable
300 kVA
1 x bimetal lug for 2 70 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
500 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x bimetal lug for 2 300 mm Al cable
1 x bimetal lug for 2 300 mm Al cable
625 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x bimetal lug for 2 500 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
750 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x bimetal lug for 2 500 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
1000 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x tinned copper lug 2 for 500 mm Cu cable
1 x bimetal lug for 2 500 mm Cu cable
1250 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x tinned copper lug 2 for 500 mm Cu cable
1 x bimetal lug for 2 500 mm Cu cable
6
198
Substation Design Manual
Table 6-13: Minimum size for crimping type terminal lugs for Power Transformers
6
Tx Rating
HV Terminals 33 kV
LV Terminals 11 kV
Neutral
30 MVA
3 x tinned copper lug 2 for 400 mm Cu cable
9 x tinned copper lug 2 for 400 mm Cu cable
1 x tinned copper lug 2 for 400 mm Cu cable
15 MVA
3 x tinned copper lug 2 for 400 mm Cu cable
6 x tinned copper lug 2 for 300 mm Cu cable
1 x tinned copper lug 2 for 300 mm Cu cable
7.5 MVA
3 x tinned copper lug 2 for 400 mm Cu cable
3 x tinned copper lug 2 for 300 mm Cu cable
1 x tinned copper lug 2 for 300 mm Cu cable
5 MVA
3 x bimetal lug for 2 150 mm Al ABC
3 x bimetal lug for 2 240 mm Al ABC
1 x bimetal lug for 2 240 mm Al ABC
The minimum air clearances between bushing terminals of a transformers for altitude 1000 meters and below, differs according to space constrains on the transformer. When space is a constraint, air clearance particularly in a cable box shall make reference to Surat Pekeliling Pengurus Besar Kanan (Pengurusan Aset) Bil. A17-2011 and BS 6435 where the minimum air clearance is specified according to the following conditions:
Partially insulated cable box – cable cores only are fully shrouded for the appropriate highest system. Fully insulated cable box – All live metal parts and cable cores are fully shrouded for the appropriate highest system voltage.
Primary Equipment
199
The minimum air clearance for open bushing terminals and bushing terminals in cable box is tabulated in Table 6-14 below. Table 6-14: The minimum requirement for air clearances Open Bushing Nominal System Voltage
415 V
Cable Box
Minimum Clearance Phase-toPhase
Minimum Clearance Live Metalto-Earth
Minimum Clearance Phase-to-Phase
Minimum Clearance Live Metal-to-Earth
77
58
-
-
127 (partially insulated) 45 (fully insulated) 242 (partially insulated) 100 (fully insulated) 356 (partially insulated) 125 (fully insulated)
76 (partially insulated) 32 (fully insulated) 140 (partially insulated) 75 (fully insulated) 222 (partially insulated) 100 (fully insulated)
11 kV
254
203
22 kV
330
279
33 kV
432
381
The minimum creepage distance of the bushing insulator is in accordance with IEC 60137 where the specific creepage distance is typically of pollution Level II (20 mm/kV).
6.1.5.8.2.
Gas actuated relay
Gas actuated relay is also known as Buchholz relay after its inventor. The gas actuated relay is fitted in the connection pipe between the main tank and the conservator. The relay has two functions: To collect free gas bubbles on their way up to the conservator from the transformer tank. To detect abnormal oil flow to the conservator in the event of a serious fault such as arcing within the transformer.
6
200
Substation Design Manual
Figure 6-38: Gas actuated relay
6
Figure 6-39: Buchholz relay cross-section At all times, the gas actuated relay should be filled with oil. When gas is generated in the transformer due to incipient fault, the gas will displace the oil in the relay and float will sink down. The protection is therefore arranged in such a way that when a minor amount of a gas is collected in the gas actuated relay an alarm signal is actuated. If an additional amount of gas is collected tripping contact may be actuated.
Primary Equipment
201
When a serious fault such as arcing occurs in the transformer, the gas evolution will push a burst of oil up towards the conservator causes the lower element to be deflected, actuating the contacts of the tripping circuit, thus disconnecting the transformer from the supply.
6.1.5.8.3.
Temperature indicator
HV WTI
HV WTI
OTI
Figure 6-40: Winding temperature indicators for power transformer (left) & distribution transformer (right) A new distribution transformer uses a top-mounted type thermometer fitted on the transformer tank cover for direct measurement of top oil temperature. For power transformer, the top oil temperature is measured using a sensor or a bulb in the thermometer pocket on the top tank cover. The measurement of winding temperature can be carried out in a direct or indirect method. For a direct measurement, fibre optic sensors can be used to measure the winding temperature. For indirect measurement, a thermal image of the winding can be made to simulate the winding temperature of the HV and LV windings. In this type of measurement, a current transformer on the HV or LV winding supplies the output current to a heating element that produces a temperature rise in addition to the oil temperature measured by the sensing bulb in the thermometer pocket on the top tank cover. The heating element is provided with an adjustable shunt or a calibration circuit so that the precise thermal image can be set by shunting the CT output current. In TNB distribution system, a single CT system is used where only one CT is used on the HV and LV winding respectively.
6
202
Substation Design Manual
Dedicated CT Calibration circuit Calibration circuit Temperature sensing bulb Capillary tube Dial gauge & switches
Figure 6-41: Winding temperature indicator schematic arrangement
6
The temperature of the winding depends on the transformer load and the temperature of the cooling medium. These two parameters are measured and made to interact in the temperature indicator. The winding temperature is therefore measured by adding the temperature difference of the winding to top oil temperature. Fans are preferably activated as soon as the temperature hits the set value, but it is not switched off again until the oil has truly cooled. There should be a 10 degree temperature difference in fan auto start and stop to avoid hunting. The recommended temperature settings are: 1. 2. 3. 4. 5. 6.
Fan auto Start: 70:C Fan auto Stop: 60:C Top oil temperature alarm: 80:C Top oil temperature trip: 90:C Winding temperature alarm: 95:C Winding temperature trip: 105:C
Primary Equipment
6.1.5.8.4.
203
Oil Level Gauge (OLG)
The new hermetically sealed distribution transformer design uses magnetic type OLG, fitted on top of the transformer tank. The indication for maximum and minimum is given by colour coding. The various brands of oil level gauge have different colour coding. The maximum level indicated by the oil gauge should correspond to the level of oil near the tip of HV bushings. For power transformer, magnetic type OLG is used to gauge the level of oil in the conservator for main tank and OLTC. Both magnetic types OLG for power and distribution transformers have a float inside the main tank or conservator tank where the position is transmitted magnetically through the tank walls to the indicator installed on the tank surface.
6
Figure 6-42: Magnetic oil level gauge for (left) the conservator tank; and (right) top cover of hermetically sealed distribution transformers
Pressure Relief Device Oil Level Gauge
Figure 6-43: Conventional oil level gauge and pressure relief device at distribution transformer
204
Substation Design Manual
6.1.5.8.5.
Pressure Relief Device (PRD)
PRD is used to release overpressure build up in the transformer tank so that tank rupture can be prevented. It is a spring operated self-resealing PRD that operate at absolute overpressure between 28 and 35 kPa (4 – 5 psi). PRD for power transformers are equipped with a micro-switch. The operation of the spring will in turn trigger the contacts of a micro-switch and trip the transformer. It should be noted that PRD is not used for alarm indication.
6
Figure 6-44: Pressure relief device for power transformer
Figure 6-45: Pressure relief device for distribution transformer
Primary Equipment
6.1.5.8.6.
205
Dehydrating Breather
The dehydrating breather contains silica gel crystals. During expansion and contraction of transformer oil due to change in temperature, the air passes over the crystals which absorb any moisture in the air. Thus, allowing only dry air goes inside the tank and reducing the amount of moisture absorbed in the oil and winding insulation that can speed up degradation process. Due to moisture absorption, the silica gel changes colour from blue to pink in the course of time. On the other hand, new type of silica gel is cobalt chloride free and is non-carcinogenic. It changes colour from orange when dry to green or colourless when contains moisture. The amount or mass of silica gel used is calculated based on among others the mass of oil used, the maintenance interval and the average thermal cycle of the transformer. Silica gel can be dried and restored to the original colour by heating, though, proper health and safety cautions should be taken. The dehydrating breathers are also provided with an oil trap, preventing continuous contact between the moist air and the silica gel, thus allowing a longer life and lower maintenance of the silica gel.
<10%
35% 50% 60% 90% (a)
(b)
(c)
Figure 6-46: Dehydrating breather showing (a) conventional silica gel, (b) new cobalt free silica gel that changes colour depending on the percentage of moisture content, and (c) oil trap
6
206
Substation Design Manual
Other standard fittings and accessories include: Table 6-15: Standard fittings and accessories of a transformer Standard Fittings
Description
Drain/Sampling valve
The valve is used for sampling and draining oil from the tank. For conservator type transformers, the valve is in the form of either gate, globe or ball type, and is provided at the bottom of the main tank. However for hermetically sealed transformers, the valve should not be operated unless guided by an expert or the manufacturer.
Earthing terminals
Two earthing terminals on opposite long sides positioned closed to the bottom are provided for the tank. Both terminals should be connected to earth at all times during operation.
Top cover earthing connections
External earthing connections positioned diagonally on opposite top corners of the tank are provided for ensuring earth continuity between top cover and main tank.
Core earth terminal
The core earth terminal box is provided for power transformer and located on top of the transformer main tank cover to facilitate testing on transformer core. Only single point bonding from core to the transformer body is allowed to prevent circulating current in the core and metal structure.
6
6.1.5.8.7.
Valves
Figure 6-48 and Table 6-16 below shows typical schematic drawing for valves arrangement and their functions respectively for power transformers.
(a) (b) (c) Figure 6-47: Typical valve used for different functions on power transformers. (a) Showing gate type valve with flanges, (b) Gate type valve with sockets and (c) Plate or butterfly type valve
Primary Equipment
207
Valve Legend Open while transformer is in operation Close while transformer is in operation
Figure 6-48: Schematic drawing showing typical valves arrangement and positions Table 6-16: Description of typical valves and types used for power transformer Item 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.
Description Oil sampling/complete drain valve Filter valve (top) Shut off valve for HV disconnecting chamber Buchholz relay shut off valve Radiator shut off valve OLTC conservator drain valve Return valve for OLTC Oil drain valve for HV disconnecting chamber Oil surge relay shut off valve Main conservator drain valve Suction valve for OLTC
Size 50 mm gate type 50 mm gate type 25 mm gate type 80 mm gate type 80 mm plate type 25 mm socket type 25 mm gate type 25 mm socket type 25 mm gate type 25 mm socket type 25 mm gate type
6
208
Substation Design Manual
6.1.5.9.
Terminal Markings
The terminal markings have been standardised for many years based on the British Standard, BS 171 using the alphabets ABCN and abcn as the phase and neutral symbols. For the 3-phase transformers used in TNB distribution system, when facing the HV side, the position of the HV terminals from left to right are in the order of ABC for delta connected winding or NABC for star connected winding. When facing the LV side, the position of the LV terminals from left to right are in the order of cban for star connected winding or cba for delta connected winding.
n
6
b
a
A
B
a
c
C
N
b
A
c
B
C
Figure 6-49: Typical terminal markings for step-down (left) and step-up (right) transformers
6.1.5.10. Rating Plate Figure 6-50 and Figure 6-51 in the following pages show typical rating plates for distribution and power transformers containing basic design data of the transformers.
Primary Equipment
209
6
Figure 6-50: Example of rating plate for distribution transformer
210
Substation Design Manual
6
Figure 6-51: Example of rating plate for power transformer
Primary Equipment
6.2.
Switchgear
6.2.1.
Overview
211
In “IEC 62271-1 Part 1: High-voltage Switchgear and Controlgear – Common Specifications”, switchgear is defined as a general term covering switching devices and their combination with associated control, measuring, protective and regulating equipment, also assemblies of such devices and equipment with associated interconnection, accessories, enclosures and supporting structures. The distribution system has predominantly indoor air insulated switchgear (AIS) installations while the current trend is to employ gas insulated switchgear (GIS) on the 33 kV network. Ring main units (RMU) are used in the distribution network for the purpose of providing economical ring reticulation systems. Sulphur hexafluoride (SF6) insulated RMUs are being used extensively in the distribution network while existing oil RMUs in the system are gradually being phased out. Switchgears used in TNB distribution network are in the form of extensible metal-enclosed switchboard and complying with IEC Standards such as IEC 62271-100, IEC 62271-200 and IEC 62271-1. The switchgear used in TNB distribution system is designed with specific characteristics to suit the system requirement for safe operation under normal service condition. By definition according to IEC 62271, normal indoor switchgear service conditions are at an altitude of not greater than 1000 m above sea level, within an ambient temperature range not exceeding 40:C, with no solar radiation consideration. The ambient air is not significantly polluted by dust, smoke, corrosive and/or flammable gases, vapours and salt. Also, the relative humidity level shall not exceed 90% for duration of one month and a seismic activity is also not considered as external vibration forces on the switchgear.
6
212
Substation Design Manual
For outdoor switchgear, consideration would be taken into account of the solar radiation, the ambient air may be polluted by dust, smoke, corrosive gas, vapours or salt but does not exceed pollution level II (medium) according Table 1 of IEC 60815. 6.2.1.1.
Enclosure/Panel
Installations are designed so that their insulation capacity, degree of protection, current carrying capacity, switching capacity and mechanical functions conform to TNB requirements. These designs are tested against the IEC standards to verify that the design could withstand and perform within their designated rating. 6.2.1.2.
6
Insulation Material
The rated value for the insulation level of a switchgear must be selected on the basis of the requirements at site, e.g. on a 33 kV or 11 kV network. Consideration is also made for the lightning and switching overvoltage impulses and earthing/neutral configuration. Switchgears used in TNB distribution network utilises these forms of insulation within the switchgear enclosure:
Atmospheric air Fluid form e.g. SF6 gas, oil
Solid insulation are utilised in the metal-enclosed switchgear to provide support to the current carrying conductor within the metal enclosure. Normally epoxy resins insulation is used and they must possess the necessary creepage distance between live parts and earth, also would be able to withstand electrodynamics stresses during short circuits.
Primary Equipment
6.2.2.
213
Air Insulated Switchgear (AIS)
Air insulated switchgears comprise of busbars, circuit breakers and cable termination compartments insulated by air at atmospheric pressure. Busbars are supported by specially designed resin bushing / insulator. Typical air insulated switchgear is as shown in the figure below. (1)
(2)
(3)
(4)
6
(5) (12) (6)
(7) (8)
(11) 1. 2. 3. 4. 5. 6.
(10)
Metering Compartment Railing Drawout VT Truck Pressure Relief Flap Busbar Cable termination
7. 8. 9. 10. 11. 12.
(9) Multi Core Cable Box Earth bar Arc protection Heater Vacuum Circuit Breaker Air Filter
Figure 6-52: Side View of AIS Switchgear
214
Substation Design Manual
6.2.2.1.
Enclosure/Panel
Metal-enclosed switchgear panels normally consist of: 1. 2. 3. 4.
Circuit breaker compartment Busbar compartment Cable compartment LV compartment
6.2.2.1.1.
Circuit Breaker Compartment
To house the withdrawable circuit breaker and the facility to test the circuit breaker in isolated position. A set of metal shutters is provided to cover each 3-phase group of stationary isolating contacts. Each set is capable of being individually operated and padlocked closed. The shutters shall open and close automatically by a positive movement. When padlocked the shutters shall prevent access to the fixed isolating contacts.
6
Figure 6-53: Withdrawable Circuit Breaker Truck
Primary Equipment
215
Metal shutter
Earthing switch
Space heater
Figure 6-54: Circuit Breaker Compartment with safety shutters in closed position (Double Busbar)
Reserve busbar spout
Cable spout
Main busbar spout
Figure 6-55: Circuit Breaker Compartment showing live electrical contacts (Double Busbar)
6
216
Substation Design Manual
6.2.2.1.2.
Busbar Compartment
Busbar is an electrical conductor, adequately insulated at a specific voltage level and capable of carrying a high current and normally a common connection between several circuits in the system. The busbars and connections is in accordance with IEC Recommendations and is continuously rated for the site conditions and currents specified. Any insulating material used as the busbar insulation is capable of withstanding the heating effects of the rated short time current and rated continuous current without permanent deformation or deterioration and complies with IEC 60085 on thermal stability and IEC 60466 on flammability.
6
The busbars shall be adequately supported against short circuit forces and provision shall be made to allow for thermal expansion of the conductors due to normal and pulse load currents and short circuit current. The busbars shall be contained in a separate compartment within the general casing of the switchboard.
Figure 6-56: Busbar compartment in air (AIS)
Primary Equipment
6.2.2.1.3.
217
Cable Compartment
The cable compartment is designed to cater for the connection of the power cables and the switchgear. This is to provide lasting and dependable connection of cable conductors and the switchgear. The methods of connection employed could be of the bolted or the plug in method. In the case of air insulated switchgear panels, cable compartment would cater for a 3-phase air insulated cable box suitable for dry type non thermal termination system. The cable box shall be suitable for terminating the maximum size of the following types of cables: 1. 2. 3.
2
33 kV, XLPE, single core, 630 mm , Aluminium 2 11 kV, XLPE, single core, 500 mm , Aluminium, with M16 bolts 2 11 kV, XLPE, three core, 240 mm , Aluminium, with M12 bolts
Cable bushings should be designed to terminate with the open palm to accommodate bimetal termination lugs suitable for deep indentation crimping in accordance to TNB Distribution Technical Specifications. Provisions shall be made for earthing the body of each cable box. Adjustable cable clamps and cable box base plate with approved cable entry seals that can accommodate different cable sizes shall be provided. For single core cables, ferrous base plate MUST NOT be used to prevent damaging heating effect to the cable due to circulating current that flows on the ferrous plate
Figure 6-57: AIS Cable compartment
6
218
Substation Design Manual
6.2.2.1.4.
LV Compartment
Depending on type of installation, provision for the controlgear and protective relays can be made at the top of the switchgear panels or in the Control Relay Panel.
6 Figure 6-58: Control relay panel at the top of the switchgear
Figure 6-59: Control gear and protective device inside the control relay panel
Primary Equipment
6.2.2.2.
219
Circuit Breakers
Circuit breakers must be capable of making, conducting and breaking off current under normal operational conditions. Furthermore, they have to trip / open in accordance with a defined current / time characteristic under overload and fault condition. This can be achieved with protection relays. Circuit breakers used complies with the requirements of IEC 62271-100 and meets the technical specification of TNB Distribution. All circuit breakers having the same rating shall be identical in arrangement and shall be interchangeable. Operating mechanisms shall be operated electrically by DC Motor, and the operating voltage of the DC motor shall correspond with the specified voltage level at the substation. The operating mechanisms shall have a proven operational endurance equivalent to the mechanical life of the circuitbreaking unit and consistent with a low maintenance requirement. The circuit breaker type is differentiated by its arc extinction medium for example vacuum, SF6 gas and dielectric oil. The type of circuit breakers that has been used in TNB Distribution system is as follows: 6.2.2.2.1.
Bulk Oil/Minimum Oil Circuit Breaker
Bulk and minimum oil circuit breaker utilize transformer insulating oil for arc extinction. In bulk oil circuit breakers, the contacts are separated inside a steel tank filled with dielectric oil while in minimum oil circuit breaker, the three phase contacts are mounted in separate insulated housing filled with dielectric oil. Bulk and minimum oil circuit breaker has been phased out due to environmental and operational issues.
6
220
Substation Design Manual
Figure 6-60: Example of bulk/minimum oil circuit breaker
6 6.2.2.2.2.
Vacuum Circuit Breaker
In vacuum circuit breakers, the fixed and moving contacts are housed permanently inside a sealed vacuumed ceramic bottle. The arc is quenched as the contacts are separated in vacuum. In the MV switchgear range, vacuum is the most predominant insulating medium for circuit breaking.
Figure 6-61: Example of vacuum circuit breaker
Primary Equipment
6.2.2.2.3.
221
Gas Circuit Breaker
Gas circuit breaker employs Sulphur Hexafluoride (SF6) gas for its arc quenching medium. The three phase breaking contacts are individually housed in gas filled insulated chambers at pressures of above 1 bar. The pressure and gas flow for arc quenching is obtained by piston action.
Stationary arc contact
Stationary contact Nozzle
Moving arc contact
Moving contact Piston rod
Cylinder
Piston Opening
Opening
Figure 6-62: Arc quenching mechanism for gas circuit breaker
Figure 6-63: Example of gas circuit breaker
6
222
Substation Design Manual
6.2.2.3.
Earth Switch
Earth switches are installed in switchgears primarily near the cable termination end and in some cases, busbars. Every earthing switch must be able of conducting its rated short-time current without damage. TNB Distribution Division requires that the earth switch be provided to earth the outgoing circuit. Circuit earthing shall be carried out by means of three phase quick-acting fault-making earthing switches which forms an integral part of the switch panel. The design utilised for earth switches is normally of the manual charged spring operation.
6
Figure 6-64: Typical earth switch device used in AIS switchgear 6.2.2.4.
Pressure Relief
For both air insulated and gas insulated switchgears, pressure relief facility is provided to ensure that the any arc discharges that the operating personnel may be exposed to, in the course of their duty e.g. operation of pressure relief devices with arc discharges deflected in all directions, side and rear of panel where operator may be working/ standing. 6.2.2.5.
Indicators
Capacitive voltage indicator is provided for every feeder to give indication if the every phase of the feeder is live or not. Mounted on the front fascia, the indicator typically uses neon bulbs that light up or blink when the circuit is energised.
Primary Equipment
6.2.2.6.
223
Ingress Protection
IEC 60529 defines the Ingress Protection (IP rating) and rates the degrees of protection provided against the intrusion of solid objects (including body parts like hands and fingers), dust, accidental contact and water in mechanical casings and with electrical enclosures. Ingress protection specified for Air Insulated Switchgears in the TNB distribution network is as follows: 6.2.2.7.
IP42 externally & IP4X in-between compartments Interlocks
All switchgears shall be provided with a comprehensive system of strong mechanical interlocking device as well as electrical and software interlocks to prevent any dangerous or undesirable operations. The interlocks are to ensure safety to operators and correct sequence of operation of all circuit breakers, load break switches, isolators, earthing switches. Examples of mechanical interlocking facilities in the TNB Switchgear are:
Switching on the earth switch when the Circuit Breaker in CLOSED position Racking in the CB when the Earth Switch is in CLOSED position
The complete interlock scheme shall be subjected to TNB Distribution Division specification and requirement.
6
224
Substation Design Manual
6.2.2.8.
Typical Rating of AIS Table 6-17: Ratings of air insulated switchgear 11 kV Switchgear
22 kV Switchgear
33 kV Switchgear
50 Hz
50 Hz
50 Hz
2. Rated voltage
12 kV rms
24 kV rms
36 kV rms
3. One minute power frequency withstand voltage
28 kV rms
50 kV rms
70 kV rms
4. Impulse withstand voltage
75 kV peak
125 kV peak
170 kV peak
5. Rated short time current
20 kA rms
25 kA rms
25 kA rms
6. Rated duration of short circuit
3 seconds
3 seconds
3 seconds
7. Rated 15 minutes DC withstand voltage of parts directly connected to power cables
28 kV dc
50 kV dc
70 kV dc
None
None
None
AIS Parameter 1. Rated frequency
6
8. Visible or audible corona
6.2.2.9.
Configuration for 11 kV Bulk Supply Switchgear Table 6-18: Configuration of 11 kV Bulk Supply Switchgear
Requirements VCB Rating Differential Protection Relays
Protection CTs Metering CT Voltage Transformer Ammeter/Voltmeter Relay Test Terminal Block Trip Circuit Supervision
A1 A4 A5 A6 VCB=12 kV, 630 amps. Fault rating at 20kA, 3sec. Busbar = 800 amps Areva Siemens Siemens MICOM 7SD610 Solkor N P541 5P20 600/300/5 Amps for OCEF
5P20 600/300/5 Amps for OCEF Class X 600/300/5 Amps
Not Required Not Required Ammeter to be in built in Relay but voltmeter is required Automatic current shorting and isolating trip circuit to be provided To utilize relay in built functions
Primary Equipment
225
Table 6-19: Configuration of 11 kV Bulk Supply Switchgear (continue) Requirements VCB Rating Protection CTs
Metering CT
B2(A)
B2(B)
C1
VCB=12 kV, 630 amps. Fault rating at 20 kA, 3 sec. Busbar = 800 amps 5P20 600/300/5 amps for OCEF
B2-50 = 50/5 CT B2 -75= 75/5 CT B2-100= 100/5 CT B2-150 = 150/5 CT
B2-200= 200/5 CT B2-300= 300/5 CT B2-400 = 400/5 CT
Voltage Transformer
11/0.11 kV(sq.rt 3)
Ammeter/Volt meter
Ammeter to be in built in Relay but voltmeter is required
Relay Test Terminal Block
Automatic current shorting and isolating trip circuit to be provided
Trip Circuit Supervision
To utilize relay in built functions
Not Required
6 To provide push buttons
Where, A1 – Circuit Breaker with Overcurrent & Earth Fault Protection Relay A4, A5, A6 – Circuit Breaker with OCEF, inclusive of Class X 600/300/5 CT’s with relays for unit protection with specific relays B2 (1) – Circuit Breaker with OCEF Protection Relay and VT &CT for metering (wound) B2 (2) – Circuit Breaker with OCEF Protection Relay and VT & CT for metering (ring) C1 – Bus Section
226
Substation Design Manual
6.2.3.
Gas Insulated Switchgear (GIS)
In Gas Insulated Switchgear (GIS), all live parts of the gas insulated switchgear are enclosed in a compressed SF 6 gas system. SF6 gas with its good dielectric strength provides the basic insulation medium for the switchgear. Currently, GIS is mandatory for all new PPUs in the 33 kV and the 11 kV Class 1 systems. (11) (1) (2) (10)
(3) (4)
6
(5)
(6) (8)
(9) (7)
1. 2. 3. 4. 5. 6.
LV compartment Relays Gas density meter Single line diagram / semaphore indication CB operating mechanism Live indicator
7. 8. 9. 10. 11.
Current transformer Cable termination Circuit breaker Disconnectors/Isolators Busbar in SF6
Figure 6-65: Example of GIS Switchgear
Primary Equipment
227
13 8 10 12 2 13
1
10
3 9
8
4 5 6
7
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.
2
Three position disconnector Multifunctional protection and control unit Gas density sensor and filling valve Vacuum circuit-breaker Cable socket Inner cone cable connector Plug-in voltage transformer – feeder Pressure relief disk Current transformer or combined current and voltage sensor Pressure relief duct Measuring sockets for capacitive voltage indicator system Busbars Plug-in voltage transformer – busbar
Figure 6-66: Vacuum Interrupter in SF6 enclosure switchgear, with rated three position disconnector (isolator)
6
228
Substation Design Manual
6.2.3.1.
Enclosure/Panel
The gas-insulated and metal-enclosed switchgear has been designed to optimize availability and operator safety. The advantages of having gasinsulated switchgear are as follows:
Insensitive to environmental influences, such as humidity, dust and aggressive gases. To provide high degree of personnel safety by having complete metal enclosure for all live parts.
6.2.3.2.
Cable Compartment
For Gas Insulated Switchgears, the type of termination kits to be supplied with each panel shall be of the inner cone or outer cone system and shall be designed for use on the various types of cables used by TNB. The termination kits are type tested in accordance with the relevant IEC Standards.
6
Figure 6-67: Cable termination compartment with inner cone connectors
Primary Equipment
229
Figure 6-68: Cable termination compartment with outer cone bushings
6.2.3.3.
Vacuum Circuit Breaker
GIS only utilises vacuum circuit breakers (VCB) as the breaking mechanism. In vacuum circuit breakers, the fixed and moving contacts are housed permanently inside a sealed vacuumed ceramic bottle. The arc is quenched as the contacts are separated in vacuum.
2 1
1. 2.
Circuit breaker compartment with front cover on CB compartment with front cover removed
Figure 6-69: Typical fixed type circuit breaker used in GIS
6
230
Substation Design Manual
Vacuum Interrupter
Contact fingers (fixed type)
6 Figure 6-70: Typical Fixed Type CB used in GIS 6.2.3.4.
Pressure Relief
In the event of an internal fault, a pressure relief device operates before the internal pressure exceed design pressure limit of the switchgear. The pressure relief device should direct all the harmful gases and by products of the internal fault away and safely from the operating personnel. 6.2.3.5.
Indicators
Another important indicator is the SF 6 gas level gauge, also called manometer. The manometer gives indication whether sufficient level of SF 6 is present inside the tank especially prior to operation of the switches.
Primary Equipment
6.2.3.6.
231
Ingress Protection
Ingress protection specified for Gas Insulated Switchgears in the TNB distribution network is as follows: 6.2.3.7.
IP42 externally and IP65 for gas enclosures Interlocks
The interlocks are to ensure safety to operators and correct sequence of operation of all circuit breakers, load break switches, isolators, earthing switches. For gas insulated switchgear, interlocks are enabled during operation of isolators when the circuit breaker is in CLOSED Position. 6.2.3.8.
Disconnector/Isolators with Earthing
Disconnectors are mechanical switching devices which provide an isolating distance in the open position. They are capable to open or close a circuit if either a negligible current is switched or there is no significant change in voltage between the terminals of the poles. Currents can be carried for specified times under normal operating conditions and under normal conditions. In gas-insulated switchgear, the earthing of the feeder is often achieved by the earth-switch and completed by the closing of the circuit breaker 6.2.3.9.
Typical Rating of GIS Table 6-20: Rating of Switchgear Panels
Rating of Switchgear Panels a b c d e
Feeder Panel Transformer Panel (LV Side) Transformer Panel (HV Side) Bus Section Bus Coupler
11 kV
33 kV and 22 kV Transformer Capacity
630 A 2000 A
90 MVA 1250 A 2000 A
45 MVA 1250 A 2000 A
30 MVA 1250 A 2000 A
N/A
N/A
N/A
1250A
2000 A N/A
2000 A 2000 A
2000 A 2000 A
2000 A 2000 A
6
232
Substation Design Manual
6.2.4.
Ring Main Units (RMU)
6.2.4.1.
Overview
In general, the Ring Main Unit (RMU) is a combination of two units of switches, which are Load Break Switch (LBS) for the incoming and outgoing feeders and switch-fuse or circuit breaker for the transformer T-off feeder. All these switches are contained inside a tank filled with insulation. To operate the switches inside the tank, operating mechanisms are mounted externally on the tank and actuated manually using operating handles. When SCADA function is required, motors connected with RTU for communication and battery charger for dc supply are installed within the operating mechanisms to enable switches to be operated remotely or via supervisory.
6
In TNB, the RMU is the switching equipment used extensively in the 11 kV and 22 kV systems as it suits the system configuration and protection practice. Additionally, the RMU offers the following advantages: (a) (b) (c) (d)
Economical Ease of maintenance Space saving Suitable for indoor and outdoor use
The suitability of indoor and outdoor applications depends on the degree of protection of the RMU (Ingress Protection (IP) rating). IP42 is suitable for indoor while outdoor applications require a minimum of IP54. To achieve the IP54 requirement, the RMU is clad with mild steel enclosure to cover the front fascia. The definition of this IP is given in Appendix C.
Primary Equipment
233
SF6 tank
Operating mechanism
Figure 6-71: Example of operating mechanisms mounted on the tank in a RMU (the front fascia of this RMU was removed) Different types of RMU configuration (number of LBS and switch-fuse/circuit breaker in the RMU unit) are used depending on the network requirement at the substation. Typical configurations used in TNB are:
2L + 1T or 2S+1F ( referring to 2 LBS and 1 switch-fuse/circuit breaker) 2L + 2T or 2S+2F 3L + 1T or 3S+1F 3L + 2T or 3S+2F 3L of 3S
For the insulation, RMU can either use mineral oil or Sulphur Hexafluoride (SF6) gas. The insulation is responsible to clear the arc during operation. Other than that, the insulation will also assist in cooling the bus-bar and the switch blade inside the tank. In TNB, the RMU installed in the system is currently of SF6 gas insulated.
6
234
6
Substation Design Manual
(a) (b) Figure 6-72: (a) Example of an outdoor RMU with front enclosure to achieve IP54 requirement (b) When the enclosure is opened, the front fascia can be accessed for operation and to observe indications.
Figure 6-73: An Example of Indoor RMU (Toprank Model TPM)
Primary Equipment
235
The typical ratings for the RMU are given in the following table. Table 6-21: Typical ratings for the RMU Parameters Continuous normal current Short-time Withstand Load break switch Earthing switch Making capacity Load break switch Earthing switch Power frequency withstand Voltage Across earth and between poles Across isolating distance Lightning impulse withstand Voltage Across earth and between poles Across isolating distance
12 kV 630 A
24 kV 630 A
20 kA, 3 sec 2.1 kA, 1 sec
20 kA, 3 sec 2.1 kA, 1 sec
50 kA peak 5.4 kA peak
50 kA peak 5.4 kA peak
28 kV 32 kV
50 kV 60 kV
75 kV 85 kV
125 kV 145 kV
Additionally, the RMU is internal arc tested to minimum 20 kA, 1 second for the tank with accessibility Type A. Internal arc test is a type test used to verify that the RMU is able to withstand the overpressure within the RMU due to fault or flashover and hence to contain the arc internally without endangering the authorised operators present near the RMU. Pressure relief valves are installed on the tank usually at the bottom and are designed to rupture first when there is overpressure inside the tank to release the arc away from the authorised operators. Tank
Pressure relief device
Figure 6-74: Pressure relief device
6
236
Substation Design Manual
6.2.4.2.
Load Break Switch
Switches are mechanical switching devices, which not only make, carry and interrupt current under normal conditions in the network but must also carry for a specific time and possibly make currents under specified abnormal conditions in the network. A load break switch (LBS), as used in an RMU, can be used to make and break a circuit under normal load current. However, it can only make but cannot break the circuit during short circuit or fault conditions. Due to this characteristic, the operating handle supplied with the RMU to activate the operating mechanism of the LBS must have features to prevent inadvertent breaking on fault to occur within 3 seconds after unintentional closing on fault during operation. This requirement can be achieved for example by the use of anti-reflex handle. The LBS is gang-operated to ensure the 3 phases are operated simultaneously.
6
Figure 6-75: Internal view of LBS in Merlin Gerin RM6
Primary Equipment
237
Figure 6-76: Internal view of LBS in Tamco GR1
6
Figure 6-77: Example of anti-reflex handle for LBS (Siemens 8DJ 20)
238
Substation Design Manual
6.2.4.3.
Switch-Fuse
The main function of this switch-fuse is to control the T-off circuit, which is connected to the distribution transformer. Switch-fuse is essentially an LBS connected in series with a fuse. Other than the closing and opening operations, this switch is able to trip and isolate the supply automatically during overload and fault conditions. In order to trip and isolate, a medium voltage fuse is used to trigger the tripping mechanism. Alternatively, the switch-fuse can also be replaced by a circuit breaker to control the transformer T-off feeder. The tripping of this circuit breaker is controlled by a time-lag fuse. The correct ratings of high voltage fuse and time-lag fuse must be ensured for proper protection is achieved. 6.2.4.4.
Interlocks
The RMU is equipped with mechanical interlocking facilities to ensure safety to operators by principally preventing the following operations:
6
Earthing the circuit while it is in live condition Opening the testing access or the cable compartment and the fuse compartment when the circuit is not earthed Switching ON of the circuit when the cable box compartment is opened
6.2.4.5.
Indicators
Capacitive voltage indicator is provided for every feeder to give indication if the every phase of the feeder is live or not. Mounted on the front fascia, the indicator typically uses neon bulbs that light up or blink when the circuit is energised. It is possible to conduct low voltage live phasing of the ring feeders at the capacitive voltage indicator. Another important indicator is the SF6 gas level gauge also called manometer. The manometer gives indication whether sufficient level of SF 6 is present inside the tank especially prior to operation of the switches. 6.2.4.6.
Ingress Protection
IP42 for indoor application and IP54 for outdoor application
Primary Equipment
6.3.
Neutral Earthing System
6.3.1.
Overview
239
TNB distribution practices an “effective system earthing” policy where the source of supply at PMU and PPU must be earthed at the star point on the secondary side of the transformer. This type of earthing system is known as Neutral Earthing System where neutral is earthed by means of solid or resistive earthing. Resistive earthing is achieved by the use of Neutral Earthing Resistor (NER). The main purpose of the NER is to limit the single phase to earth fault to a transformer rated full load current, thus protecting installations, such as cables and transformers from damages due to extreme heat generated by the fault current.
6 NEI
NER
Figure 6-78: Neutral earthing system showing NER & NEI
240
Substation Design Manual
Figure 6-79 below shows a schematic diagram of a Neutral Earthing System setup on the star side of power transformers which consists of NER, Neutral Earthing Isolators (NEI) and associated earthing conductors and devices. Busbar NEI Close
Open
Isolator NEI
Close
Open
Transformer 1 (T1)
6
Solid Earthing
NER
Transformer 2 (T2)
Figure 6-79: Neutral earthing system configuration NER is installed at the star points of a large-capacity transformer that normally exceeds 12.5 MVA. In most cases, transformers rated below 7.5 MVA do not require NER. As such, only solid earthing is required. Table 6-22 summarizes the normal rating of voltage, current and the size of NER and NEI used. Table 6-22: Standard ratings of voltage, current and the size of NER and NEI Power Transformer
NER
NEI NEI Secondary Secondary Voltage Current Voltage Current Voltage Capacity Resistance Busbar voltage current rating rating Rating Rating ratio (kV) (MVA) (Ohm) size rating (V) rating (A) (V) (A) (V) (A) 2 (mm ) 33/22-11 30 22 787 16* 22 1600 10x100 36 1600 33/22-11 30 11 1575 4* 22 1600 10x100 36 1600 33/22 30 22 787 16 22 800 10x100 36 1600 33/11 30 11 1575 4 11 1600 10x100 12 1600 11/33 15 33 262 24 33 800 10x100 36 1600 33/11 15 11 787 8 11 800 10x100 12 1600 22/11 12.5 11 656 16 11 800 10x100 12 1600 22/6.6 12.5 6.6 1093 4 11 1600 10x100 12 1600 *Note: NER dual rating specific for connection of star point transformer dual ratio 33/22-11 kV
Primary Equipment
6.3.2.
Design and Construction
6.3.2.1.
Neutral Earthing Resistor (NER)
241
There are two types of NER i.e. liquid and dry metallic type. Liquid type NER requires frequent maintenance to ensure the electrolyte solution is kept topped up and at the correct ionic strength where the bulk resistance value of the electrolyte must be accurately calibrated so that the value will not increase significantly with the increase in surrounding temperature. Furthermore, dry metallic type NER does not suffer from evaporation, freezing and leakage. For this reason, dry metallic NER is preferred and it has been used as early as 1990 to replace the liquid type NER in PMU and PPU. Dry metallic type NER, comprises of non-corroding heavy duty metallic resistor elements, enclosed in a ventilated cubicle made of stainless mild steel or galvanised steel, suitable for outdoor installation on concrete flooring.
6
Figure 6-80: Dry metallic type NER showing the metallic resistor elements (grid)
242
Substation Design Manual
6.3.2.1.1.
Voltage
NER is often described by the system or line voltage of the supply, e.g. 11 kV NER. The maximum voltage that NER actually experiences in service is the line to neutral or phase voltage. The available voltage ratings of the NER in TNB distribution network is as shown in Table 6-22. 6.3.2.1.2.
Continuous Current & Ohmic Resistance
NER is rated by current at phase voltage and it is usually chosen to be equal to or lower than the rated current of the transformer on the star side as shown by the formula below. Ifull
load
MVA
=
3 × Vline
System impedances are ignored. This implicitly specifies the ohmic resistance value of the NER as follow.
6
NER =
Vphase Ifull load
By Ohms Law, the ohmic resistance value of the NER can also be calculated by: NER =
V 2 line MVA
Example: For 30 MVA 33/11 kV Transformer, Ifull
load
=
30 3 × 11
= 1574 A
The ohmic resistance value for the transformer is thus, NER =
112 =4Ω 30
Table 6-22 provides a comprehensive list of the current ratings and ohmic resistance values according to the transformer capacity.
Primary Equipment
6.3.2.1.3.
243
Time
Resistors are generally rated to carry their current for a time of 10 seconds. The current will actually flow for a much shorter time than this. The 10 second time is chosen to allow for the occurrence of multiple events. This can happen when auto-reclosers are used. It also allows for the operation of an upstream backup protection device, if the protection relay fails. 6.3.2.1.4.
Insulation Levels
NER never experience voltages in excess of phase voltage. However, insulation level is designed based on the line voltage. This has minimal impact on size, weight and cost of the NER designed for medium voltages. 6.3.2.1.5.
Temperature Rise
Temperature rise is limited to 760°C maximum, in strict accordance to ANSI/IEEE 32, 1972. This was based on the resistor alloy and insulation technology available in 1972. Current technology may allow for a rise of 1000°C, maximum. The specification of a 1000°C design may significantly reduce size, weight and cost. 6.3.2.1.6.
Temperature Coefficient of Resistance (TCR)
Metallic resistors have a positive temperature coefficient of resistance (TCR). This means that the current flowing will not exceed the rated value. Current reduces as the NER warms up. In general the TCR is limited to 3.5% per 100°C rise. 6.3.2.1.7.
Termination
NER has three main terminals or connection points. The first terminal connects one end of the resistor to the neutral of the transformer. The second terminal connects the remaining end of the resistor to earth. The third terminal provides enclosure earth bonding. The enclosure earth terminal and resistor earth terminal is separated to facilitate for testing on site.
6
244
Substation Design Manual
The resistor neutral terminal is typically in the form of a porcelain bushing rated for the line voltage. The resistor earth terminal is typically in the form of a bushing rated for 1.2 kV. The enclosure earth terminal is usually in the form of a M12 stud. 6.3.2.1.8.
Ingress Protection (IP) Rating
The NER in TNB distribution network is typically designed to have the degree of ingress protection for the enclosure of at least IP23 in accordance with IEC 60529. The materials used within a NER typically include resistive alloys, stainless steels, ceramics, galvanised steel and copper. All of these materials are durable in harsh environments. Hence the need for stringent environmental protection is low.
6
Higher IP ratings of the NER in excess of IP54 can significantly restrict the escape of heat from the resistor. High IP requirement thus can significantly increase size and weight of the NER to cater for effective heat dissipation. This will result in higher cost. NER is hot during and after operation. The IP rating does not infer that it is safe to touch the NER. 6.3.2.1.9.
Enclosure
The enclosure is made of stainless mild steel or galvanised steel for free maintenance. 6.3.2.1.10.
Neutral Earthing Interlock
The NER is normally provided with interlocking mechanism so that it can be interlocked (electrical or mechanical) with the 33/11 kV transformer incoming circuit breaker. The interlock works in such a way that it is not possible to close the transformer 11 kV incoming circuit breaker if its respective earthing link is open.
Primary Equipment
6.3.2.2.
245
Neutral Earthing Isolator (NEI)
NEI is a simple switching mechanism to provide isolation of the NER for maintenance of any section of the substation. The NEI is designed for outdoor operation, complete with supporting steelwork with minimum safety clearances in accordance with IEC 60071. The Isolators are typically single pole double air break, centre rotating post type with minimum 50 degree blade opening and is of wall mounted type. Neutral busbars is made of tinned copper. The isolator blade is made of copper where its tip is coated with silver for good electrical contact. The neutral earth switch is normally provided with vertical drive rod and mechanism box. The adjustable drive rod is made of galvanised steel pipe with length and diameter suitable for easy operation. Adjustable rod clamp is also provided to allow for on-site adjustment of the vertical drive rod. Neutral cable connections to the NEI shall be insulated with non-thermal termination kit. The typical ratings of NEI use in TNB distribution network was tabulated in Table 6-22 and Figure 6-81 shows typical arrangement of NEI for 11 kV 1600 A ratings. 6.3.2.2.1.
Ratings
The ratings of the NEI namely, voltage, impulse withstand voltage continuous current and time are designed to be at least equal to the ratings of the NER. The minimum short circuit current rating of the NEI is shown in Figure 6-22 below. Table 6-23: Minimum short circuit current rating of the NEI NEI Rated Voltage
Short Circuit Current
11 kV
20 kA, 3 secs
22 kV
20 kA, 3 secs
33 kV
25 kA, 3 secs
However, most of the NEI used in the system is often rated at 25 kA, 3 secs.
6
246
Substation Design Manual
50˚ blade opening
NEI busbar Adjustable drive rod
Disconnectors Vertical drive rod Non-thermal termination
Adjustable drive clamp
Mechanical switch assembly Connection from transformer 1
Connection from transformer 2
Figure 6-81: Typical arrangement of NEI rated at 11 kV 1600 A
6
6.3.2.2.2.
Size of Conductors
The conductors are sized so that they are capable of carrying the continuous current rating of the NER. The typical size of the main busbar conductors was summarized in Table 6-22. 6.3.2.2.3.
Clearance
The air gap between terminals of the same pole with the isolator open is designed to be of a length to withstand a minimum impulse voltage wave of at least 115 percent of the specified impulse insulation rating to earth. The typical distance of the gap between the terminals of the same pole for NEI rated at 33 kV is 500 mm. 6.3.2.2.4.
Ancillary Equipment
NEI installations should be equipped with the following accessories: i.
ii.
2 units of outdoor ring current transformer (CT) of Class X and frequency 50 Hz for REF protection. The knee point voltage V KP and CT resistance RCT are to be determined based on the relaying scheme. 2 units of outdoor ring CT of Class 5P20, frequency 50 Hz and burden 15 VA for SBEF protection.
Primary Equipment
247
Sample calculation to determine REF and SBEF CT ratios for 30 MVA 33/22 kV transformers neutral earthing system is as follows.
NER
22,0002 30,000,000
16
INER = IEF = IFL ≈ 800A
IFL = 524.9A ≈ 600A
CTSBEF = 800/5A 900/1 A
3
800/5 A
3
30 MVA 33/22 kV
SBEF
REF
IFL = 787.3A ≈ 800A
NER
CTREF 600
33 / 1 900 / 1A 22
22 kV 800 A 16 Ω
6 Sample calculation to determine REF and SBEF CT ratios for 30 MVA 33/11 kV transformers neutral earthing system is as follows.
NER
11,0002 30,000,000
4
INER = IEF = IFL ≈ 1600A
IFL = 524.9A ≈ 600A
CTSBEF = 1600/5A
IFL = 1574.6A ≈ 1600A
1800/1 A
3
1600/5 A
3
30 MVA 33/11 kV
SBEF
REF
NER
CTREF 600
11 kV 1600 A 4Ω
33 / 1 1800 / 1A 11
248
Substation Design Manual
In practice, a dual ratio CT is mostly used to cater for upgrading of transformer capacity in the PMU and PPU. Table 6-24 lists the typical CT ratios used according to the transformer ratings. Table 6-24: CT ratios for REF and SBEF protection Power Transformer
NER
Voltage ratio (kV)
Capacity (MVA)
33/22-11
30
Secondary voltage rating (V) 22
33/22-11
30
11
33/22
30
33/11
30
33/11
15
11/33
15
22/11 22/6.6
CT Ratio
Resistance (A)
REF (A)
SBEF (A)
16*
1800/900/1
1600/800/5
4*
1800/900/1
1600/800/5
22
16
1800/900/1
1600/800/5
11
4
1800/900/1
1600/800/5
11
8
1800/900/1
1600/800/5
33
24
600/300/1
600/300/5
12.5
11
16
800/1
800/5
12.5
6.6
4
800/1
1200/5
6 CT 1
CT 2
Figure 6-82: Installation of CT 1 and CT 2 for REF and SBEF protection respectively
Primary Equipment
iii.
249
Neutral Switch Auxiliary Contacts enclosed in stainless steel cubicle for each isolator connecting to Transformers 1 and 2, NER and direct earth connection and is rated for 110 VDC with eight numbers (8 Nos.) of Normally Open and eight numbers (8 Nos.) Normally Close contacts.
Figure 6-83: Neutral Switch Auxiliary Contacts cubicle for indication of the isolator’s open-close operation
6.3.3.
6
Safety
During single line fault to ground, fault current will flow through NER, copper conductor connecting NER to NEI, copper busbar on the NEI and back to the transformer star point via the neutral cable as depicted by Figure 6-84. Red Phase
Star Point
VNER
NER
Yellow Phase
Blue Phase If
Fault
Earthed Sheath Cable
Figure 6-84: Fault current flowing If due to phase short circuit to earth
250
Substation Design Manual
The fault current flowing through the NER will instantaneously produce a voltage across it approximately equal to the value of the phase voltage or VL/√3. For example, the voltage across the NER connected on the star point of a 33/11 kV transformer during single line to ground fault is approximately 6.35 kV. This proves that NER and NEI including all neutral earthing conductors are High Voltage equipment as defined in TNB Safety Rules since during single line to ground fault the equipment will experience phase-toearth voltage of more than 600 V. As such, NER, NEI and all neutral earthing conductors shall be treated strictly in accordance with TNB Safety Rules. In the event where NER is isolated and transformer star point is connected directly via solid earthing, fault current will flow directly to earth. This will produce a voltage approaching the earth potential or 0 V. However, the value of the fault current will rise as no NER is connected to limit the fault current. Hence, when working with NER, NEI and all neutral earthing conductors, the procedures stipulated in Subchapter 6.3.4 shall be strictly observed.
6 6.3.4.
Procedures When Working with NER, NEI and Neutral Earthing Conductors
6.3.4.1.
General Procedures:
(a) The NER Bay shall be locked at all time to prevent anyone from entering the area without the permission from TNB authorized personnel. (b) All TNB personnel or contractors must wear safety shoes provided or approved by TNB when entering the high voltage zone including the NER Bay. (c) All TNB personnel must wear the personal protective equipment (PPE) when operating the high voltage equipment during shutdown and normalization of supply. (d) Only TNB approved wooden ladder shall be used when working in the high voltage zone including the NER Bay.
Primary Equipment
6.3.4.2.
251
Procedures When Working with NER or Conductors Directly Connected to NER for Maintenance, Repair or Replacement Work
Prior to commencement of work on the NER or any parts of the conductors directly connected to the NER, a shutdown of the power transformers connected to the common neutral earthing system must be performed in accordance with Seksyen 3, Aturan Keselamatan Elektrik, Bahagian Pembahagian TNB, where the transformers shall amongst others be made dead, isolated, proven dead and earthed at all points of isolation of supply to the transformers including points of isolation from the neutral earthing equipment.
6.3.4.3.
Procedure When Working with Exposed Neutral Earthing Conductors on Neutral Bushing and Neutral Cable of the Transformer, NEI Busbar or Conductors Directly Connected to the NEI and Transformer Star Point
When work requires direct contact on the exposed metal parts of the Neutral Earthing Conductors on the neutral bushing and neutral cable of the transformer, NEI busbar or conductors directly connected to the NEI and transformer star point, a shutdown of the power transformers connected to the common neutral earthing system must be performed in accordance with Seksyen 3, Aturan Keselamatan Elektrik, Bahagian Pembahagian TNB, where the transformers shall amongst others be made dead, isolated, proven dead and earthed at all points of isolation of supply to the transformers including points of isolation from the neutral earthing equipment.
6.3.4.4.
Procedure When Working with Solid Earthing Conductor
When work requires direct contact on the exposed metal parts of the solid earthing conductor, the respective isolator or disconnector for the solid earthing on the NEI must be made open and any parts of the solid earthing conductor shall be inspected to ensure all connection to the NEI busbar and to any one of the transformer star point is safely disconnected before allowing permission to work.
6
252
Substation Design Manual
6.3.4.5.
Prohibitions
(a) Any work performed on the NER, NEI and neutral earthing conductors that are directly connected to NER, NEI Busbar and star point of any energised transformer is totally PROHIBITED. This is to avoid danger to the personnel resulting from the high voltage produced in the event of single line to earth fault. (b) Bypassing the NER by means of connecting the solid earthing to the neutral earthing system at any time is totally PROHIBITED. This is to protect the respective apparatus such as cables and transformers from damage due to infinitely high fault current due to the absence of the NER. (c) Concealing the neutral earthing conductors underneath the surface of the substation wall is PROHIBITED. The fault current will leak through the wall surface under wet condition and can cause electrical shock to personnel touching the wet wall. Additionally, heat caused by the fault current will cause surface crack and degradation of the wall.
6
6.4.
Medium Voltage Fuse
Medium voltage (MV) fuses are used in the switch-fuse of RMU to provide fast isolation of circuit when there is fault in the distribution transformer or transformer tail on the HV and/or LV side. A fuse interrupts excessive current (or termed as blows) so that further damage to the equipment protected is prevented. MV fuses used in RMU in TNB system are of high rupture capacity (HRC) and back-up current limiting type. A HRC fuse is a fuse that is filled with silica sand surrounding the fuse link. It is used on applications where the fault current needs to be suppressed fast and with no flash over. On a fault current a tremendous amount of heat is created within the fuse. That heat melts the silica sand into glass, and glass being an insulator, suppresses the arc over and breaks the circuit instantaneously.
Primary Equipment
253
MV fuses used in RMU in TNB system are also fitted a striker mechanism. This would provide the user with a visual indication that the fuse link has operated. Striker mechanisms are driven by explosive charges or compressed springs and both are triggered by a thin fuse in parallel with the elements that when a current flows through it, the elements would melt. The current would then heats up the wire and detonates the explosive charge or melt the wire and releases the spring, pushing the striker pin out of the fuse link’s end cap. A suitable mechanism is used to prevent from the pin being pushed back into the fuse body.
End cap
Porcelain barrel
Moisture tight seal
Star core
6 Fuse elements
Granular Quartz Striker coil
Figure 6-85: Front view of MV fuse
Star core
Silver ceramic point contact Striker coil
Granular Quartz
Fuse elements Porcelain barrel
Figure 6-86: Cross-section of MV fuse
Expelled striker
254
Substation Design Manual
Another type of fuse used for transformer protection in RMU utilising circuit breaker is the time lag fuse. This type of fuse, also known as anti-surge, or slow-blow is designed to allow a current which is above the rated value of the fuse to flow for a short period of time without the fuse blowing. This situation normally arises in magnetising inrush current of transformers which can draw larger than normal currents for up to several seconds when first energised.
6
Figure 6-87: Time Lag Fuse
6.4.1.1.
Dimension and Design of Fuse Contact
MV fuses are available in different dimensions and designs of the fuse contacts which are selected according to the types of RMU where the fuses will be used (refer to Table 6-25). For SF6 gas insulated RMU, the MV fuse shall comply with dimension as specified in DIN 43625. Often, this fuse is referred to as MV DIN fuse.
Primary Equipment
255
Table 6-25: Type of fuses in different RMUs No. 1.
Type of RMU SF6 – gas insulated Example: RMU Tamco GR1, RMU Indkom, RMU Merin Gerin RM6
Features Based on DIN 43625 standard
442 mm 22 kV
11 kV 292 mm
2.
Oil insulated with in-air fuse compartment Example: HFU Tamco, HFU Cutler-Hammer
Based on IEC 60282-1 Type III with type D tags
6 Side view
Top view
3.
Oil insulated with the fuse compartment immersed in oil Example: RMU ABB (oil type), RMU Long and Crawford, RMU EPE Rokks
Based on IEC 60282-1 Type II
256
Substation Design Manual
6.4.1.2.
Fuse Rating
The rating of the MV fuse to be used depends on the capacity of the distribution transformer connected to the switch-fuse feeder and is determined based on the following characteristics: (a) Shall provide 3-phase protection against short-circuit current that occurs in the HV or LV side of the transformer (b) Able to withstand transformer inrush magnetising current which is typically 12 x full load current transformers for 100 ms (c) Able to withstand the usual periodic overcurrent up to 150% of transformer full load current (d) Giving discriminatory grading with low voltage (LV) fuses for the highest rating used in the LV system which is 250 A. This is to ensure that the LV fuses operate properly when there is fault in the LV system.
6
Referring to the time-current characteristics for MV fuse, the ratings in Table 6-26 should be observed for 11 kV and 22 kV SF6 gas insulated RMU. Table 6-26: The fuse rating must be suitable with the transformer ratings System voltage
11 kV
22 kV
Transformer capacity (kVA)
Fuse rating (A)
100
16
300
31.5
500
50
750
80
1000
100
100
6.3
300
16
500
25
750
40
1000
50
Primary Equipment
6.5.
Feeder Pillar
6.5.1.
DIN-Type Feeder Pillar
257
Feeder pillars (FP) are used as an LV distribution point from the substation transformer outgoing feeder to the customers. In TNB, feeder pillars used are designed based on standards developed by the German Institute for Standardization or Deutches Institut fur Normung (DIN). Previously, the feeder pillars installed in the system were of the British Standards (BS) design. The design and technology of the DIN-type feeder pillar has been used by TNB for feeder pillar rated at 400 Amps (also known as mini feeder pillar) since 1999. Based on the experience of using DIN-type feeder pillar 400 Amps, TNB has started to migrate to DIN-type feeder pillar for rating 1600 A since 2010, and since 2012 for 800 A rating.
6
Figure 6-88: DIN-type feeder pillar rated at 400 Amps (or mini feeder pillar)
258
Substation Design Manual
Figure 6-89: Example of a BS Type 1600 A feeder pillar
6.5.2. 6
Rational for Using the DIN-Type LV Feeder Pillar
There are several advantages of using DIN-type feeder pillar compared to BS type feeder pillar. The features of DIN type feeder pillar are: 1) 30% reduction of size from the existing BS type feeder pillar 2) Operational safety due to the fully shrouded concept 3) The design which can minimize the risk of vandalism and theft: Red phase, Yellow phase and Blue phase busbars are not easily accessible as the incoming and outgoing units are installed onto the busbars very close to one another with gaps of less than 10 mm between the units. Neutral busbar is also not easily accessible as it is mounted behind the front plate. All bolts and nuts securing the busbars to the feeder pillar frame are applied with special chemical called thread locker to prevent these bolts and nuts from being opened by spanner. No link and fuse carriers are present in the DIN-type feeder pillar as in the BS type. These link and fuse carriers contain copper and are very prone to theft. In the DIN-type feeder pillar, all copper contacts are embedded within the incoming and outgoing unit bodies and are hence difficult to be stolen.
Primary Equipment
259
Copper contacts
Figure 6-90: Copper contacts on fuse carrier of BS-type feeder pillar
6
Copper contacts
Figure 6-91: Copper contacts embedded within the disconnector body of DIN-type feeder pillar
260
Substation Design Manual
6.5.3.
Design and Construction of Feeder Pillar
The design for the 1600 A, 800 A and 400 A feeder pillars (FP) are essentially similar in terms components and functions. The differences lie in the size of current-carrying components used to suit the required ratings, the number of incoming and outgoing units to suit network requirement as well as methods of cable termination.
(1) Instrument panel (4) Fuse-switch disconnector (Outgoing)
(2) Disconnector unit (Incoming)
6
(3) Cable termination
Figure 6-92: DIN-type 1600 A LV feeder pillar In general, feeder pillars consist of four main components as shown in Figure 6-92 and provide the functions as follows: 1.
Instrument panel Instrument panel is only available in FP 1600 A and 800 A. It is frontmounted and is equipped with ammeter with maximum demand indicator and 13 A, 3 pin switched socket outlet. Additionally, the instrument panel is fitted with 60 A cartridge type fuse wired to the blue phase busbar and one neutral link wired to the neutral busbar to facilitate the connection of auxiliary single phase loads such as substation lighting, portable tools, etc.
Primary Equipment
261
Figure 6-93: Close up of the instrument panel 2.
3.
Incoming disconnector unit Rating: 2 x 1000 A (for FP 1600 A and 800 A) Contains copper solid link rated 1000 A or size NH3 Single-pole operated For FP 400 A, the incoming consists of direct terminations of incoming cables onto the busbars. Function: Provide means to isolate the FP from the source/supply Cable termination Cable cores of the incoming and outgoing cables for Red, Yellow and Blue phases are terminated via bolted connection in the termination area provided at the bottom of the respective incoming disconnector and outgoing fuse-switch disconnector units (for FP 1600 A and 800 A).
Figure 6-94: Close up of cable termination for one feeder
6
262
Substation Design Manual
4.
6
For FP 400 A, the incoming cables are directly terminated via bolted connection onto the busbars. The outgoing cables are connected to the termination area provided at the bottom of the outgoing fuse rail units via core clamps. All neutral cores are terminated directly via bolted connection onto the neutral busbar.
Outgoing fuse-switch disconnector Rating: 8 x 400 A (for FP 1600 A), 5 x 400 A (for FP 800 A) and 6 x 160 A ( for FP 400 A) Contains LV DIN fuse blade contact type of size NH2 (for FP 1600 A and 800 A) and size NH 00/000 (for FP 400 A). Depending on the operation requirement the available fuse ratings are as follow: o 125 A, 160 A, 200 A and 250 A for NH2 o 50 A, 80 A and 100 A for NH 00/000 Function: o Provide fast isolation through interruption by fuse when fault occurs at outgoing feeders o Provide means to isolate the outgoing feeders from source/supply
Figure 6-95: LV DIN fuse blade contact type of size NH2 used in the outgoing unit
Primary Equipment
5.
Busbar The phase busbar system is designed to carry the rated continuous current Made of tinned copper with the following minimum copper equivalent dimension: o 80 mm x 10 mm (for FP 1600 A) o 38 mm x 10 mm (for FP 800 A) o 6 mm x 40 mm (for FP 400 A) The neutral busbar has similar material and dimension to the phase busbar. The neutral busbar is connected to the earth bar through braided copper wire.
6.
Feeder pillar enclosure The enclosure is made of electro galvanised steel. Sufficient ventilation is provided to permit natural circulation of air. The doors are equipped with camlock for locking of the doors. The camlock is opened using the Allen Key provided by manufacturer with every feeder pillar. As such, standard padlocks are no longer required to lock the doors. The padlocking facility provided on the door is to enable Authorised Persons to use non-standard lock during shutdown or breakdown as per safety requirement.
Camlock Handle
Padlocking facility
Camlock
Figure 6-96: Camlock with Allen key
263
6
264
Substation Design Manual
6.6.
Current Transformer (CT)
A current transformer (CT) is a device for sensing current flowing through a power system and sending current signal to a protective relay system. The functions of current transformer are: (a) To reduce power system current to lower value for measurement (b) To insulate secondary circuits from the primary (c) To permit the use of standard current ratings for secondary equipment The differences between current transformers (CT) for metering and protection are shown in Table 6-27. Table 6-27: Difference between CT for metering and protection Metering
Protection
1
Used for instrumentation such as ammeter, energy meters, transducer etc.
Used for operation of protective devices such as relays in CBs and reclosers. Can be connected is series with ammeter
2
Accuracy is paramount
Reliability and stability during operation up to accuracy limit current
3
Specified in accuracy class e.g. 0.2 and 0.5
Specified in accuracy and accuracy limit factor (ALF) e.g. 5 P 10, 5 P 20, cl X, S etc.
4
Operate at rated accuracy class between 100%-120% current ratings. Normal operating range is 20%100%. Beyond 120%, CT saturates so no further increase in secondary current with further primary current rise
Accurate from rated primary to accuracy limit (ALF) current
6
Primary Equipment
265
The protective current transformer must be capable of providing an adequate output over a wide range of fault conditions, from a fraction of full load to many times full load. The CT standards are governed by IEC 185:1987, IEC 44-6:1992, BS 3938: 1973, and BS 7626. Characteristics and specifications of the current transformer include:
Current transformer is normally of the dry type design using epoxy resin as insulation and tested to IEC 60044-1. The CT shall be capable of carrying rated primary current for one minute with the secondary winding open. Where open circuit secondary voltage would exceed 3.5 kV, suitable protection shall be provided at the secondary terminals to limit the voltage. The CT is installed on the circuit side of the circuit breaker except on busbar sectionalising and coupling equipment as may be required.
6
(a) Ring type
(b) Wound type
Figure 6-97: MV current transformer
266
Substation Design Manual
Protection CTs
Metering CTs
Figure 6-98: CT for protection and metering inside switchgear
6 6.6.1.
Protection Current Transformer (CT)
The protection CT has the following characteristics: 1.
2. 3.
The output of each protection CT is 15 VA with an accuracy limit factor of 20. The adequacy of these figures can be confirmed by calculation. The CT Class is typically 5P20 for protection. For high impedance unit protection where specified in the specification, class X CT is used. The knee point voltage is confirmed by calculation. The classification of CT for protection is normally written as 5P10 or 5P20; 5 are 5% composite error at 10 or 20 times of the rated current, while P denotes protection CT.
Primary Equipment
6.6.2.
267
Metering Current Transformer (CT)
One of the characteristics for metering CT is the accuracy class that is typically 0.2 and 0.5. This means that the errors have to be within the limits specified in the standards for that particular accuracy class. Specifications of metering CTs for consumers taking 415 V are:
Ratio
:
Is 5A *where Is is the primary ratio of the metering CT
Class
:
0.2
Burden
:
7.5 VA
Unit
:
3 Nos. (One for each feeder)
Standards
:
IEC 60044-1 (1996)
Specifications of metering CTs for consumers taking 6.6 kV, 11 kV, 22 kV and 33 kV (indoor breaker) are:
Ratio
:
6
Is 5A *where Is is the primary ratio of the metering CT
Class
:
0.2
Burden
:
15 VA
Unit
:
3 Nos. (One for each feeder)
Standards
:
IEC 60044-1 (1996)
Table 6-28: Current Transformer (CT) sizes LV CT ratio
100/5, 150/5, 200/5, 300/5, 400/5, 500/5, 600/5, 800/5, 1000/5, 1200/5, 1600/5
MV CT ratio
50/5, 75/5, 100/5, 150/5, 200/5, 300/5, 400/5
An example of metering Current Transformers (CT) installed for each phase is shown in Figure 6-99.
268
Substation Design Manual
Figure 6-99: Example of Metering Current Transformer (CT) Example: Current Transformers (CT) Size Calculation To determine CT size, the following calculation should be done: 𝑃=
6
3 × 𝑉𝑝−𝑝 × 𝐼 × cos 𝜃
𝐼=
𝑃 3 × 𝑉𝑝−𝑝 × cos 𝜃 cos 𝜃 = 0.85
Where:P Vp-p
= Apparent power = Line voltage system I = Line current ampere cos θ = Power factor
For example: I=
500 𝑘𝑊 3 × 0.415 𝑘𝑉 × 0.85 I = 818.36 𝐴
Thus, the suitable CT size is 1000/5 A. Note: Metering CT size should be higher than the calculated value.
Primary Equipment
269
Figure 6-100: Armoured cable is used to connect the CT and PT to the meters
6 Table 6-29: Armoured Cable Configuration Cable No.
Cable configuration
1
S1 terminal red phase current transformer
2
S2 terminal red phase current transformer
3
S1 terminal yellow phase current transformer
4
S2 terminal yellow phase current transformer
5
S1 terminal blue phase current transformer
6
S2 terminal blue phase current transformer
7
Red phase voltage
8
Yellow phase voltage
9
Blue phase voltage
10
Neutral
11&12
Earthing
270
Substation Design Manual
6.7.
Potential Transformer (PT)
Potential Transformers (PT) are used to step down the voltage for measurement, protection and control. TNB Distribution Division only uses electromagnetic type potential transformers. The functions of the PT are for: (a) Measurement/metering (b) Automatic Voltage Regulation (AVR) (c) Protection for directional OCEF relay
6
The PT is normally of the cast resin filled type and it is complies with IEC 60044-2 with a class of 0.5. The rated output of the PT is normally specified at 50 VA per phase but alternatively adequacy can be determined by calculation of the burden. The normal ratio of PT is normally to the rating of 33 kV, 22 kV, and 11kV/110V (3 single phase star-connected and neutral earthed). The PT should be able to be isolated from the circuit during testing by means of isolatable links or withdrawable mechanism.
Figure 6-101 below shows an example of an electromechanical PT and Figure 6-102 shows the location for the PT inside a switchgear compartment.
Figure 6-101: Electromechanical PT
Primary Equipment
271
Potential Transformer
Figure 6-102: Potential Transformers inside the switchgear compartment
6 Specifications of potential transformers are:
Ratio
: Vs
3
110 3 *Where Vs is the supply voltage given to the consumer
Class
: 0.5
Burden
: 50 VA minimum. Sharing between protections and metering PT can be allowed provided that separate fusing is provided and the burden of the shared load does not exceed 10 VA. If the burden of the shared load is more than 10 VA, then 100 VA PT should be used.
Unit
: 3 Nos. (one for each feeder)
Standards
: IEC 60044-2 (1997)
272
Substation Design Manual
Figure 6-103: Potential Transformer Fuse Each PT is equipped with PT fuse normally rated at 3.15 A. This fuse will isolate the PT from the system in the event of fault at the PT i.e. internal winding, secondary bushing. Therefore, the system will not trip or deenergize.
6
However, the fuse will not blow if the fault is at the secondary circuit because the fault current equivalent at the primary side is too small to blow the fuse. Normal practice is to place fuse or MCB at the secondary side to protect the circuit, but they are prone to tampering and nuisance tripping causing incorrect energy consumption recorded by the meter. For the future, TNB will replace these fuses with copper links to avoid PT fuse blow issue and solely depends on OCEF protection to trip if there is any fault caused by the PT.
Secondary Equipment
Chapter 7: 7.1.
273
Secondary Equipment
Overview
Secondary equipment is needed to ensure reliable operation of the primary equipment. They cover the functions of protection, monitoring, control, automation and communication.
7.2.
Protection/Protective Relaying
7.2.1.
Protection System
Protection System is a branch of electrical power engineering concerned with design and operation of primary equipment. It detects abnormal power system conditions to rapidly remove and selectively isolate such conditions from service in order to return affected power system to its normal state. There are 3 main functions of Protection System: 1.
To safeguard the entire system to maintain continuity of supply
2.
To minimize damage and repair costs where it senses fault
3.
To ensure safety of personnel.
7.2.1.1.
Components of Fault Isolating System
Fault isolation system consists of: 1.
Protection Relay / Equipment
2.
Current Transformer (CT) & Potential Transformer (PT)
3.
Circuit Breaker
4.
DC System
Each component above is explained further in the following subchapters. The relationship among these components is as shown in Figure 7-1.
7
274
Substation Design Manual
Protection System Circuit Breaker CT Protection Equipment / Relay
CB Mechanism
Trip Coil
PT
DC System
CT – Current Transformer PT – Potential Transformer CB – Circuit Breaker
Figure 7-1: Fault Isolation System 7.2.1.2.
7
Protection Relay
A protection relay is a device that monitors power system parameters such as current, voltage and frequency input. It triggers alarm or initiate trip to the circuit breaker if the input measured is outside its preset range. Protection relays respond to abnormal system conditions such as short-circuit, open-circuit, overloading, and reverse power flow. Particularly for transformer, it responds to the oil and winding temperature as well as gas pressure. There are 3 types of relays used in TNB Distribution Division system: 1.
Electromechanical relay
2.
Electronics/static relay
3.
Numerical Intelligent Electronic Device (IED)
Secondary Equipment
7.2.1.2.1.
275
Electromechanical Relay
Electromechanical relays are constructed with electrical, magnetic and mechanical components, have an operating coil and various contacts and are very robust and reliable. Time dial sets the stop position of the disk and therefore sets the contact travel distance
Upper poles Metal disk Moving contact Damping contact Fixed contact Direction of torque produced on disk
Current Spring Lower pole
Shaft
Restraining force of spring; normally holds disk at rest against mechanical stop
Pickup point adjusted by selecting current tap
Figure 7-2: Basic principle of electromechanical relay Although this type of relay has been in operation for many years, there are several limitations such as: (a) Demagnetizing problem due to ageing (b) Limited functionality as compared to numerical relays
7
276
Substation Design Manual
The figure below shows an example of CDG 36 type electromechanical relay.
Figure 7-3: Electromechanical relays (CDG 36)
7
7.2.1.2.2.
Static Relay
Static relays with no or few moving parts became practical with the introduction of the transistor. Static relays offer the advantage of higher sensitivity than purely electromechanical relays, because power to operate output contacts is derived from a separate supply, not from the signal circuits. Static relays eliminate or reduce contact bounce, and could provide fast operation, long life and low maintenance. Limitation for this relay is mainly on the expected lifespan which is approximately based on TNB Distribution Division maintenance policy. An example of a static relay that is used in TNB Distribution Division is shown in Figure 7-4.
Secondary Equipment
277
Figure 7-4: Examples of static relay (MCGG52)
7.2.1.2.3.
Numerical Intelligent Electronic Devices (IED)
Numerical Intelligent Electronic Devices (IED) is a relay that converts voltage and current to digital form and processes the resulting measurements using a microprocessor. The digital relay can emulate functions of many discrete electromechanical relays in one device, simplifying protection design and maintenance. A typical IED contains protection functions, control functions controlling separate devices, an auto-reclose function, self monitoring function, communication functions etc. IEDs receive data from sensors and power equipment, and can issue control commands, such as tripping circuit breakers if they sense voltage, current, or frequency anomalies, or raise/lower voltage levels in order to maintain the desired level.
7
278
Substation Design Manual
Among the features available in a numerical relay include: (a) (b) (c) (d) (e)
Facility for local and remote relay setting Event recording Group setting features Password protected Fault disturbance waveform
One of the advantages of the IED relay is that size is significantly reduced compared to the electromechanical type. Examples of IED relays used in TNB Distribution Division are shown in Figure 7-5.
7
(a) SIEMENS SIPROTEC 7SD61
(b) MICOM P123
Figure 7-5: Examples of Numerical IED relays
7.2.1.2.4.
List of Accepted Relays
TNB implements stringent standard procedure for product acceptance for procurement of relays. The list of the TNB accepted relays is kept and updated by Transmission Protection.
Secondary Equipment
7.2.1.3.
279
Current Transformer (CT) & Potential Transformer (PT)
The Current Transformer and Potential Transformer are part of the components in the switchgear as discussed in Subchapter 6.6 and Subchapter 6.7. 7.2.1.4.
Circuit Breaker
Circuit breaker is primary equipment that isolates faults. The device is as discussed in Subchapter 6.2. Generally, under fault condition, protection relay receives and analyzes information and closes its contacts. This will energize the trip coil inside the CB and operate its opening mechanism to isolate the faulty circuit from the power system. 7.2.1.5.
DC System
Protection system requires uninterrupted and independent power source. Typically, DC supply is preferred over AC supply due to its reliability and immunity to disturbance and surges. DC system is required to power up the relays and CB auxiliaries. It will be further elaborated in Subchapter 7.4
7.2.2.
Protection Scheme
Physically, protection relays are connected to other components such as CT, PT, time-delay relays, auxiliary relays, secondary circuits, trip circuits, auxiliary wiring, fascia, and tripping relays to make up for a protection scheme. This protection scheme is designed to safe guard primary equipment from various type of fault. The design of such scheme varies depending on the:
Type and rating of the primary equipment to be protected Size and the complexity of the substation
Examples of protection schemes are overcurrent earth fault scheme, pilot wire protection scheme, current differential scheme, transformer differential scheme, etc.
7
280
Substation Design Manual
7.2.2.1.
Protection Schemes for PPU
Figure 7-6 shows general protection schemes for PPU. Solkor RF/Current Differential OC/EF 33 kV 33 kV Outgoing 1HO
2HO
Tx Differential Tx Guard OC/EF
Tx2
Tx1
Tx Differential Tx Guard OC/EF
NER
31
OC/EF REF
Bus Section
11 kV Outgoing
7
32
SBEF Tx1 SBEF Tx2
OC/EF Translay
Figure 7-6: Protection schemes for PPU
OC/EF REF
Secondary Equipment
7.2.2.1.1.
281
Underground Feeder
Protection schemes implemented are:
Over Current Earth Fault (OCEF) Current Differential (CD) using fibre optic or Pilot Wire Protection Directional OCEF Other alternatives subject to the network configuration.
7.2.2.1.2.
Overhead Feeder
Protection schemes implemented are:
OCEF Auto reclose Other alternatives subject to the network configuration.
7.2.2.1.3.
Transformer Feeder HV
Protection schemes implemented are:
Transformer Differential OCEF Transformer mechanical protection – refer to Subchapter 6.1.5.8 o Gas activated relay (Buchholz) o Winding and oil temperature o Pressure Relief Device (PRD) Other alternatives subject to the network configuration.
7.2.2.1.4.
Transformer Feeder LV
Restricted Earth Fault Standby Earth Fault OCEF
7
282
Substation Design Manual
7.2.2.1.5.
Busbar
Protection schemes implemented are:
Busbar separation scheme (BSS) - The scheme is to separate the busbar when outgoing feeder fails during fault. Busbar/switchgear protection scheme - TNB Distribution Division employs arc protection technique as the busbar protection scheme. It comprises of: o Master relays installed at independent arc protection panel for transformer LV incomers and feeder incomers. o Slave relays located in switchgear, and o Sensors in switchgear and busbar compartments.
Current input to the scheme is taken from the LV incomer. The scheme is such that outgoing feeder breaker will trip for downstream fault in the switchgear and the scheme will trip LV incomers for busbar fault. In case of a transformer breaker failure or delays to open, an intertrip to HV transformer feeder will take place.
7
VAMP 220 (Master) Master
Master VAMP 220 (Master) Ib> T2
T2
VX010 (Slave)
VX010 (Slave) CB1
T1
CB2
T1
CB3
X2
X1
Sensors
Figure 7-7: Example of Arc Protection Scheme
Secondary Equipment
7.2.2.2. 7.2.2.2.1.
283
Protection Schemes for 11 kV Stations Underground Feeder
Schemes implemented for underground feeder protection are:
Over Current Earth Fault (OCEF) Current Differential (CD) using fibre optic or pilot wire protection (Translay) Directional OCEF Other alternatives subject to the network configuration.
7.2.2.2.2.
Overhead Feeder
Schemes implemented for overhead feeder protection are:
OCEF Other alternatives subject to the network configuration.
7.2.2.2.3.
11kV/0.4kV Distribution Transformer Feeder
Scheme implemented for 11kV/0.4kV distribution transformer feeder protection is:
OCEF
7
284
Substation Design Manual
7.3.
Control
Control hierarchy is designed in TNB equipment to ensure safety to personnel in the field by restricting the permission to control the equipment. It comprises: 1. 2. 3.
Local Control (Highest Priority) Remote Control (Second Priority) Supervisory (Least Priority)
This priority determines how the internal wiring will be designed. Descriptions of the controls are as follows: 1.
Local Control Personnel are required to do switching at the equipment or switchgear. This facility is to facilitate maintenance, inspection and emergency operation.
2.
Remote Control In this mode, personnel are required to do switching activities from the control room.
7
Permission for switching from supervisory is determined here. 3.
Supervisory Control Switching activities are done from Regional Control Centre (RCC), where principal items of substation are controlled and monitored via SCADA system. The SCADA is covered in Chapter 8.
Secondary Equipment
7.3.1.
285
Control Hierarchy for PPU
For PPU, the control hierarchy is achieved by using the Control and Relay Panels (CRP). CRP facilitates centralized control, monitoring and status of primary equipment in that particular substation. The control panel incorporates: (a) Protection relays (b) Alarms fascia - Alarm handling facilities for operational personnel (c) Switches - Inclusive of control switches (discrepancy switch), remote/supervisory switch (d) Analogue meter (Ammeter and Voltmeter) - Indicating actual current and voltage reading. (e) Auto/Manual trip counter for circuit breaker - Auto is for cumulative number of CB tripping while manual is for cumulative number of CB opening. (f) Auxiliary relays (g) Interposing transformers - An instrument installed in overcurrent circuit to protect transducer, ammeter. (h) Fuses (i) Links (j) MCBs (k) Test terminal blocks - Facilities for secondary testing. (l) Transducer - An equipment to provide remote on line system parameters. (m) Semaphore - Visual indication of the status or position of its primary equipment. (n) Mimic and labels - A representation of the primary equipment and its voltage rating. - In the mimic diagram, the breakers are systematically numbered/coded.
7
286
Substation Design Manual
The colour coding for the mimic as practiced in TNB are as follows: Table 7-1: Colour coding for the mimic Colour
Voltage
Yellow
11 kV
Blue
22 kV
Red
33 kV
Green
132 kV
Brown
275 kV
Black
Neutral/Ground
Metering Windows Alarm Fascia Protection Relay
7
Mimic Diagram & Control
Figure 7-8: An example of Control and Relay Panels In the mimic diagram, each circuit breaker is uniquely numbered for ease of identification. These numbers are always referred to during operation. The standard numbers are as explained in Subchapter 3.3.1.
Secondary Equipment
7.3.1.1.
287
Interlock
Mechanical and electrical interlocks are included on mechanisms and in the control circuits of apparatus installed in substations as a measure of protection against an incorrect sequence of manoeuvres by operating personnel. The common interlocks are: 1. 2. 3. 4. 5. 6.
7.3.2.
Opening & closing of NER Opening & closing of transformer isolator Insertion of PT Transformer HV and LV opening and closing interlock Busbar live transfer Earthing interlock
Control Hierarchy for 11 kV Stations
Generally, for 11 kV stations only the local control mode is available. If the station is equipped with Remote Control Box (RCB) the three levels of control hierarchy can be achieved. The Remote Control Box (RCB) can be incorporated into existing 11 kV circuit breaker / RMU to provide control and indication of the circuit breaker / LBS (RMU). The control panel incorporates: (a) Two different coloured lamps to show the status of the circuit breaker/LBS (RMU): i. Green lamp : “OFF” condition of circuit breaker/LBS (RMU) ii. Red lamp : “ON” condition of circuit breaker/LBS (RMU) (b) Feeder signal (c) Station alarm (d) Switches i. Supervisory remote switches ii. Open/close switch iii. Earth switch
7
288
Substation Design Manual
The RCB indicators are shown in Figure 7-9.
Figure 7-9: RCB indicators The RCB is SCADA ready for future interconnection with RTU. The signal must include:
7
Supervisory Open Command: signal from RTU to trip circuit breaker Supervisory Close Command: signal from RTU to close circuit breaker Supervisory Indicator: signal to be sent to RTU to indicate the selector switch selected to supervisory mode Remote Indicator: signal to be sent to RTU to indicate the selector switch selected to remote mode CB Open Indicator: signal to be sent to RTU to indicate the circuit breaker “OFF” condition CB Close Indicator: signal to be sent to RTU to indicate the circuit breaker “ON” condition
Each RCB box can control up to 4 feeders. Where space is a constraint, RCB can be mounted outside the substation’s wall as shown in the Figure 7-10.
Secondary Equipment
289
RCB
Figure 7-10: Remote Control Block (RCB) for P/E
7.4.
DC & AC Auxiliary Systems
7.4.1.
DC System
In a substation, Direct Current (DC) system is used to provide power to all auxiliaries such as: (a) Protective devices (b) Tele-control equipment such as Remote Terminal Unit (RTU) (c) Circuit breaker auxiliaries 7.4.1.1.
DC System for PPU and SSU
The DC system for PPU and SSU is rated at 110 V DC; comprising chargers, battery banks (86-88 cells) and DC distribution board. The DC system is of dual parallel redundant chargers with interlocking system and operating in parallel with battery banks.
7
290
Substation Design Manual
Battery charger DC distribution board
Battery bank
Figure 7-11: DC system in the battery room
7.4.1.1.1.
7
Charger
A charger is an equipment that rectifies AC supply into DC. It is used as the main DC source to supply station DC auxiliaries and at the same time to charge the standby battery bank during normal operation.
Charger 1
Charger 2
DC distribution board
Figure 7-12: Dual battery charger panel and DC distribution board (110 V)
Secondary Equipment
7.4.1.1.2.
291
Battery Bank
Battery bank is used as backup to supply station auxiliaries whenever station AC supply fails. It is designed to cater for 5 hours during any station AC supply blackout. It also serves as an extra DC source whenever the station DC load requires supply more than what can be delivered by the charger. Battery banks and battery chargers must be well maintained to ensure that the protection system functions properly.
7
Figure 7-13: A dual battery bank
7.4.1.1.3.
DC Distribution Board
The DC distribution board distributes the 110 V DC supply to the required apparatus, for example CBs trip coil, protection relays and annunciators. The DC distribution board can be seen in Figure 7-12.
292
Substation Design Manual
7.4.1.2.
DC System for P/E with VCB Switchgear
The DC system for P/E with VCB switchgear is rated at 30 V DC. The system comprises charger, battery bank (25 cells) and terminal blocks that are incorporated in a single cubicle as shown in Figure 7-14.
7 Figure 7-14: A typical single cubicle battery charger (30 V DC) in an 11 kV substation
Secondary Equipment
7.4.2.
293
AC System
AC System is required to supply all substation AC auxiliaries such as:
OLTC driving mechanism Remote Tap Changer Control Panel Each Battery Charger Control and Relay Panel – Heater & Lighting Switchgears – Heaters
The AC supply can be derived from:
Local transformer LV Distribution Board (DB) in the case of PPU; or LV distribution transformer or LV mains from SAVR; or Customer AC supply
Figure 7-15 shows an example of an LVAC Switchboard.
7
Figure 7-15: LVAC Switchboard
294
Substation Design Manual
7.5.
Heater
7.5.1.
Heater for 33 kV Switchgears
For 33 kV switchgears, heaters are installed at 3 locations in the switchgear: 1. 2. 3.
Breaker compartment Cable compartment CT compartment
All the heaters are installed in parallel. The power capacity and the number of heaters are dependent on the type/model of the switchgear. The typical ratings for the heaters are given in Table 7-2. Table 7-2: Heater rating 33 kV switchgear Heater Location
Power Rating
Breaker compartment
120 W
Cable compartment
80 W
CT compartment
80 W
7 Fuse
ON/OFF Switch
Thermostat
Heater 3
Heater 2
Heater 1
L
Link N
Figure 7-16: Circuit for heater installation inside 33 kV switchgears
Secondary Equipment
7.5.2.
Heater for 11 kV Switchgears
7.5.2.1.
Heater for 11 kV Switchgears at PPU and SSU
295
For 11 kV switchgears at PPU and SSU, heaters are installed at 2 locations of the switchgear: 1. 2.
Breaker compartment Cable compartment
Both heaters are installed in parallel. The power capacity and the number of heaters are dependent on the type/model of the switchgear. The typical ratings for the heaters are given in Table 7-3. Table 7-3: Heater rating 11 kV switchgear Heater Location
Power Rating
Breaker compartment
80 W
Cable compartment
80 W
Fuse
ON/OFF Switch
Thermostat
L
Heater 2
Heater 1
7
Link N
Figure 7-17: Circuit for heater installation inside 11 kV switchgears
296
Substation Design Manual
7.5.2.2.
Heater for 11 kV Switchgears at P/E
For 11 kV switchgears at P/E, heaters are generally installed at the breaker compartment and cable compartment. However, sometimes a breaker is installed only at the breaker compartment. The power capacity and the number of heaters are dependent on the type/model of the switchgear. These heaters are typically rated at 80 W and 100 W.
7.6.
Secondary Wiring
7.6.1.
DC Wiring
DC wiring is the nerve for the control and the protection of station auxiliaries. 2 Wires of multistrand 2.5 mm grey insulated coloured are used as standard DC wiring. Special tagging is required for tripping circuits whereby the wires should be labelled with red coloured TRIP tagging.
7.6.2. 7
AC Wiring
AC wiring is the nerve for all the AC station auxiliaries. 2 Black coloured 2.5 mm wiring 1000 V grade is used for AC circuitries. AC wiring should be segregated from DC wiring for fear that induced AC will be present in the DC system. Special attention should be given to CT wiring as it is required to be colour coded as per the phase that it carries namely RYB and the size of 2 the conductor shall be 4.0 mm . All circuitries are to be numbered for its usage as per BS 158.
Secondary Equipment
297
Wiring for measurement
Wiring for tripping circuit
Figure 7-18: Secondary wiring
7.7.
Metering
The purpose of metering in the substation is as follows: 1.
2.
MV metering (a) For customer taking bulk supply 6.6 kV, 11 kV, 22 kV, 33 kV, 66 kV, 132 kV, 275 kV. (b) For PMU between transmission and distribution (c) For PPU between primary distribution medium voltage (33 kV & 275 kV) and secondary medium voltage (22 kV and 11 kV) (d) For P/E between neighbouring area or ‘Kawasan’ LV metering (a) For customer taking bulk supply more than 100 A (b) for recording substation use or free units
For metering installations up to 33 kV, CTs and VTs shall be provided and installed by TNB at TNB's outgoing switchgear. A floor mounted metering cubicle shall be provided by the consumer in the specified metering room for the installation of TNB meters.
7
298
Substation Design Manual
For LV metering and supply scheme with substation, the meter panel/cubicle is installed inside TNB substation perimeters (refer ESAH).
Figure 7-19: Typical LV meter wall-mounted in a substation
Table 7-4 shows the comparison between MV metering and LV metering. Table 7-4: Comparison between MV metering and LV metering.
7
Voltage
Parameter
MV
LV
CT operated
With PT
Without PT
110 V
415 V
63.5 V
240 V
Phase to phase Phase to neutral Current (max)
5 A (10 A) 1 A (2 A)
5 A (10 A)
Example of MV metering wiring configuration is shown in Figure 7-20.
Secondary Equipment
299
Metering Panel Main meter kWh/kVARh
Check meter kWh/kVARh
Voltage Isolators
Potential Transformer
110 V (Line)
Test Terminal Block
11 kV (Line) PT Fuse (PT)
7
Figure 7-20: MV wiring The main and check meters are located at the front panel of the metering compartment as shown in Figure 7-21. Main meter is on the left side and check meter is on the right side.
Feeder main meter
Feeder check meter
Figure 7-21: Typical MV metering panel with main and check meter
300
Substation Design Manual
7.7.1.
Test Terminal Block (TTB)
The Test Terminal Block (TTB) is located inside the Meter Test Box (MTB) in the metering panel. It is used to isolate the meter from the current source to perform maintenance works on the meters. The number of TTBs required depends on the number of feeder, i.e. 1 TTB per feeder.
(a) TTB connections label
7
(b) Installation with wiring inside MTB Figure 7-22: Test Terminal Block (TTB)
Secondary Equipment
7.7.2.
301
Voltage Isolators
The function of the voltage isolators is to replace fuse to overcome the latter’s disadvantage in terms of possibility to blow. It is used to isolate the meter from the current source to perform maintenance works on the meters. The number of voltage isolators required depends on the number of feeder, i.e. 6 voltage isolators per feeder.
Figure 7-23: Voltage isolators
7.7.3.
Meter Test Box (MTB)
The main function for Meter Test Box (MTB) is to cover and protect the installation of voltage isolators and the Test Terminal Block (TTB). This Meter Test Box (MTB) is installed inside the meter panel. The external view of the Meter Test Box (MTB) is shown in Figure 7-24 whereas the internal view is shown in Figure 7-25.
Figure 7-24: Meter Test Box (external view)
7
302
Substation Design Manual
Voltage isolators
Test Terminal Block (TTB)
Figure 7-25: TTB and voltage isolators inside MTB (internal view)
7.8. 7
Communications
Two types of communication cables exist in TNB, i.e. fibre optics and pilot cables. They are both used for Supervisory Control and Data Acquisition (SCADA), communication and protection system. Currently, TNB only use fibre optics for new installation.
Figure 7-26: Cross-sectional view of armoured pilot cable (left) and an optical fibre cable (right)
Secondary Equipment
7.8.1.
303
Pilot Cable
Typical number of pilot cable pairs currently being used according to distribution network needs are summarised in Table 7-5. Table 7-5: Typical no. of pilot cable pairs used in the distribution system Voltage (kV)
No. of pairs
No. of pair used for unit protection
No. of pair used for SCADA to RCC 1-2 pairs per communication loop
12 pairs 11
1 pair 8 pairs for telecontrol & telecoms
37 pairs 33
37 pairs
17 pairs for telecontrol
1 pair
10 pairs for telecoms
Table 7-6 below shows the diameter resistance and elongation of conductor in completed cable. Table 7-6: Diameter resistance and elongation of conductor in completed cable Resistance of Conductor/km at 0 20 C
Diameter
Elongation
Overall Diameter of Insulated Conductor
Nominal
Max
Min
Max
Min
Nominal
mm
mm
Ω
Ω
%
mm
0.918
0.920
25.32
27.04
18
2.00
Table 7-7 shows the maximum mutual capacitance and capacitance unbalance with the conductor size. Table 7-7: Mutual capacitance and capacitance unbalance Conductor Size
Maximum Mutual Capacitance
Maximum Capacitance Unbalance
mm
µF/km
pF/161m
0.914
60
200
7
304
Substation Design Manual
Table 7-8 shows the core identification for the pilot cable. Table 7-8: Core identification Size 12 Pairs
37 Pairs
Core No. 1
Black/Red
Core No. 2
4
Black/Green
7 10 1 4
7.8.2.
Black/White
5
Black/Yellow
6
Black/Brown
Black/Grey
8
Black/Orange
9
Black/Violet
Red/Blue
11
Red/White
12
Red/Green
Black/Red
2
Black/Blue
3
Black/White Black/Brown
Colour
Colour
Black/Green
5
Black/Yellow
6
7
Black/Grey
8
Black/Orange
9
Black/Violet
10
Red/Blue
11
Red/White
12
Red/Green
13
Red/Yellow
14
Red/Brown
15
Red/Grey
16
Red/Orange
17
Red/Violet
18
Blue/White
19
Blue/Green
20
Blue/Yellow
21
Blue/Brown
22
Blue/Grey
23
Blue/Orange
24
Blue/Violet
25
White/Green
26
White/Yellow
27
White/Brown White/Violet
28
7
Black/Blue
Core No. 3
Colour
White/Grey
29
White/Orange
30
31
Green/Yellow
32
Green/Brown
33
Green/Grey
34
Green/Orange
35
Green/Violet
36
Green/Brown
37
Yellow/Grey
Optical Fibre
There are two types of fibre optic used in TNB Distribution Division: 1. 2.
Slotted Loose tube
The loose tube type is more preferable as it is easier to do splicing whereas the slotted type requires a special splicing machine.
Secondary Equipment
305
Fibre optic cables provide better performance compared to pilot cables. The reasons behind the use of optical fibre cable as against pilot cables are: (a) (b) (c) (d) (e) (f) (g) (h)
No signal degradation Immune to electromagnetic interference No electrical interferences Higher speed and longer distance coverage Support more RTUs in a communication loop Less repeater needed to boost signal for long distance Better dependability and security Lower capital costs
Table 7-9 and Table 7-10 show the underground fibre optic cable specifications and underground fibre optic characteristics. Table 7-9: Underground fibre optic cable specifications Particulars Cable sheath material
Construction
Cable marking Mechanical properties
Optical properties
5
Details 1. 2. 3. 1. 2.
UV resistant Fungus resistant Black colour Slotted tube or loose tube construction 24 single mode fibres compliant to ITU-T 5 G.652.C 3. Resistant to water penetration 4. Non-armoured and non metallic Adequate cable identification and marking 1. Proof test (whole length) is 1.0% strain during ≥ 1.0sec 2. Stress corrosion factor (n) is ≥ 18 3. Weibull modulus (calculated from 60% of the fractures) is ≥ 40 Compliant to ITU-T G.652.C
Refers to the fibre optic cable that fulfils the needed criteria to support applications up to capacity of STM-16, and permits the transmission of extended wavelength between the range of 1360nm to 1530nm.
7
306
Substation Design Manual
Table 7-10: Underground fibre optic characteristics Description Fibre type
Silica/Silica doped, Single Mode
Maximum attenuation
0.40 dB/km at 1310 nm 0.25 dB/km at 1550 nm
Average attenuation
≤ 0.35 dB/km at 1310 nm ≤ 0.23 dB/km at 1550 nm
Mode field diameter Peterman II
(8.6 µm – 9.5 µm) ± 0.6 µm @ 1310 nm
Cut-off wavelength
1150 nm – 1330 nm (fibre) ≤1260 nm (cable)
Zero dispersion wavelength
1300 nm – 1324 nm
Maximum dispersion/chromatic
≤ 3.5 ps/(nm*km) at 1310 nm ≤ 18 ps/(nm*km) at 1550 nm
Maximum zero dispersion slope
0.092 ps/(nm *km)
Cladding diameter
7
Details
Attenuation at bending of fibre Attenuation at 1310nm for 100 turns, ø40mm Attenuation at 1550nm for 100 turns, ø60mm
7.8.2.1.
2
125 ± 1 µm
≤ 0.05 dB ≤ 0.05 dB
Cable Sheath
The supplied fibre optic cable is black track resistance high-density polyethylene. The typical value of the dielectric strength is in accordance to IEC 60243 test method. Outer sheath surface is smooth with no irregularities.
Secondary Equipment
7.8.2.2.
307
Colour Coding
The fibre cores are colour-coded using ANSI/TIA/EIA-598-A standard colour codes for ease of identification, as listed in the following table. Table 7-11: Fibre colour coding Fibre/Tube no.
Colour
1 2 3 4 5 6 7 8 9 10 11 12
Blue Orange Green Brown Slate / Grey White Red Black Yellow Violet Rose / Pink Aqua / Turquoise
The fibre core groups for the slotted type cable need to be easily identified by slot Identification markings. 7.8.2.3.
Fibre Optics Boundary of Responsibility
TNB Distribution Division has developed fibre optic infrastructure in power system to replace the pilot cable as a telecommunication medium. In order to ensure efficient management of the fibre optic infrastructure, TNB Distribution Division has agreed to hand over the fibre optic infrastructure to ICT Division (Fibre Optic Distribution Management Charter between ICT 6 Division and Distribution Division, June 2012) . The ICT – Distribution Operational Boundary is shown in Figure 7-27.
6
Fibre Optic Distribution Management Charter between ICT Division and Distribution Division, June 2012
7
308
Substation Design Manual
Patch panel & patch tray
Underground Fibre Optic Cable
110/24 VDC Power Supply (PPU)
Telecommunication equipment MDF/DDF
RTU Communication Box RTU Multi-core/ Control Cable RTU/SCS
Equipment 1
Equipment 2
Legend Distribution ICT
Figure 7-27: ICT – Distribution operational boundary
7
7.9.
Other Secondary Equipment
7.9.1.
Earth Fault Indicator
Earth Fault Indicators (EFI) was introduced in the 11 kV underground systems since 1990 (Arahan Ketua Jurutera Pembahagian 25/90 & 25/90A). The key objective of the EFI installations is to reduce the restoration time through identifying the faulty section in the network. Optimal use right placements and correct installations of the EFI are one of the factors that could contribute towards achieving the targeted key performance index measured by System Average Interruption Duration Index (SAIDI). Typical earth fault indicators are shown in Figure 7-28 and Figure 7-29.
Secondary Equipment
309
A complete unit of EFI consists of: A split-core current transformer – to detect fault current in cable core Indicator unit – for indicator unit, they have two functions: i. Controller box (a) Consist of DIP switch for EFI setting (b) Function as a brain of the EFI where the indicator will blink during fault ii. LED Lens (a) Show indications during fault
(a) Soule Bardin
7
(b) Cabletroll
CT Ring EFI Controller box
LED Indicator
(c) Endau
Figure 7-28: Earth Fault Indicator
310
Substation Design Manual
Figure 7-29: Components inside Earth Fault Indicator 7.9.1.1.
Working Principle of EFI
The EFI used in TNB Distribution Division system is designed to operate in a normally open-ring system with non-automatic feeder switches at all the distribution substations. It basically consists of two components, a core balance current transformer and an indication facility.
7
Its current transformer is attached at the outer sheath of the 3-phase 11 kV cable in each installation either at the incoming feeder cable termination or outgoing feeder cable termination of the substation.
Controller Box (EFI)
Transformer Switch
Incoming
Outgoing
CT
Figure 7-30: Layout location for earth fault indicator (EFI)
Secondary Equipment
7.9.1.1.1.
311
EFI Current Sensor
The EFI current sensor is in the form of a CT ring for the detection unit is an encapsulated split – core design suitable for embracing the sheath of:
2
3 core cables of conductor section of up to 300 mm (maximum diameter – 90 mm) 2 3 single core cables of conductor section of up to 500 mm (maximum diameter – 300 mm)
The current transformer needs to be suitable for use in outdoor installations. 7.9.1.1.2.
Detection Unit
The fault passage indicator is required to detect earth fault currents down to a value of at least 40 A. The detection relay provides for multiple, discrete user settable earth fault current pick up values with a minimum range of 40 A to 240 A. It provides for user settable operation delay time with a minimum range 50 ms to 150 ms. The detection unit is mountable on the inside or outside wall of an indoor type substation or on a compact substation. The enclosure should be at least of protection index IP54 to IEC 529. 7.9.1.1.3.
Signalling Device
The indicator may be a separate unit in itself or form an integral part of the whole device. Indication (light indicator) of the passage of fault current which operates, remains in operated position until reset. The indicator may be mounted on the outside wall of an indoor type 11 kV distribution substation or on some support for an outdoor substation remote from the detection relay.
7
312
Substation Design Manual
CT Ring
Figure 7-31: Location of CT ring
7 EFI Controller Box
Figure 7-32: EFI controller box inside P/E
Secondary Equipment
7.9.1.2.
313
EFI Placement
The placement of EFI is recommended to be placed at outgoing feeder of substations. 7.9.1.3.
EFI Installation
The correct installation of EFI current transformer (CT) is shown as follows in Figure 7-33 and Figure 7-34.
Switchgear body BADAN PERKAKASUIS TAJUK
DILUKIS DISEMAK
GASKET Gasket
SKRU Screw
EFI
CABLE BOX-4
WILAYAH PAHANG
CABLE BOX Cable Box
SOKET 200A Socket 200A
DAERAH TEMERLOH
NO. FAIL
TN/
GAMBAR 4
SOCKET 200A Socket 200A BUMI P/E P/EBUSBAR earth bar SOCKET 200A Socket 200A
TENAGA NASIONAL BERHAD
S. MOGANADAS
DM
CLAMP DI KEKALKAN DAN DISAMBUNG KE BUSBAR BUMI MELALUI PVC COPPER 19/064 (35mmp) KE BAWAH MASUK DALAM CT EFI
Cable Gland
CABLE GLAND
BUAH PLUMB ATAS DI DALAM CT EFI Through the CT ring
SHEATH Sheath EFI CTCT ring
PENGALIR DARI CT KE EFI Conductor from CT to EFI BUAH PLUMB BAWAH
jumper pvc copper 19/064 (35MMP)
PERKARA
AMOURING CABLE Armouring PILC PILC Cable
MOHAN MANON
Figure 7-33: Installation of EFI for PILC cable
7
314
Substation Design Manual
TAJUK
DILUKIS
Switchgear Body BADAN PERKAKASUIS GASKET Gasket
Screw
SKRU
WILAYAH PAHANG
CABLE BOX-8
CABLE BOX Cable Box LOKASI A Location A
RAYCHEM Raychem
SOKET 200A Socket 200A
GAMBAR 8
DAERAH TEMERLOH
NO. FAIL
TENAGA NASIONAL BERHAD
S. MOGANADAS
P/E earth bar connected BUSBAR BUMI P/E DISAMBUNG to cable TERUS KE CABLEbox BOX
Location B LOKASI B JUMPER PVC COPPER 19/064 (35mmp) ATAU "BRAIDED COPPER WIRE"
Braided copper wire
EFI EFI
KABEL PILC ATAU XLPE XLPE cable
Location LOKASI C C
PERKARA
Figure 7-34: Installation of EFI for XLPE cable
7
MOHAN MANON
7.9.1.4. EFI Settings To ensure that the EFI perform according to its desired function, due care must be given when selecting the right settings for current trip level to avoid any form of mal-operations i.e. unnecessary/false indication OR no operation. To avoid these conditions, the following criterion for setting the EFI current trip level is to be adhered: 𝐼𝐸𝐹 > 𝐼𝑇𝑟𝑖𝑝 > 𝐼𝑇𝐶𝑎𝑝 Where: IEF = Prospective Earth Fault Current of feeder (minimum case) ITrip = EFI current trip level setting ITCap = Downstream capacitive current ITCap can be determined by multiplying the charging current (IC) of the various size of cables with the total length of the cables involved downstream from the location of the EFI.
Secondary Equipment
315
Table 7-12 shows the values of charging current (A/km) of various sizes of XLPE and PILC cables as given by manufacturer. Table 7-12: Charging current per unit length of 11 kV XLPE and PILC cables (Ic – Data from manufacturer) XLPE
PILC
Size (mm )
Rating (A)
Charging Current (A/km)
Size (mm )
Rating (A)
Charging Current (A/km)
150
280
0.7587
25
80
0.82
240
350
0.9359
70
140
0.9399
500
550
1.2695
120
200
1.1614
185
250
1.3849
300
330
1.6982
2
7.9.2.
2
Automatic Transfer Scheme (ATS)
A transfer scheme is an electrical switch that reconnects electric power source from its main source to a backup source. Switches may be manually or automatically operated. In the TNB distribution MV network, an Automatic Transfer Scheme (ATS) is often installed at SSU with two different sources which cannot be paralleled but need to be restored within 10 seconds whenever the main incomer fails.
7
316
Substation Design Manual
(a) ATS scheme installed at switchgear PPU 1
PPU 2
CB 18
CB 1 Multiple P/Es
st
1 Leg Main CB 16675 (PT new installation)
7 CB 16676 (PT-existing)
CB 16677
Backup CB 16678 (PT new installation)
P/E
Consumer (b) Single line diagram
Figure 7-35: Automatic Transfer Scheme without bus section
Secondary Equipment
317
(a) ATS scheme installed at switchgear PPU 2
PPU 1
st
CB 14980 NOP
st
1 Leg
1 Leg
Main CB 14976 Bus section (PT-new installation) open
Main CB 18622 (PT-new installation)
CB 14978 CB 14977 (PT existing)
P/E
CB 14979 (PT existing)
CB 14981 NOP
Consumer substation (b) Single line diagram
Figure 7-36: Automatic Transfer Scheme with bus section
7
318
Substation Design Manual
7.9.3.
Supervisory/SCADA Interposing Panel (SIP)
The Supervisory/SCADA Interface Panel (SIP) interfaces the signal from the Control and Relay Panel (CRP) and switchgear to the RTU in order to enable supervisory control point explained in Subchapter 7.3 from the remote control point. The SCADA Interface Panel (SIP) can be either floor standing or wallmounted.
7 RTU SIP
Figure 7-37: SIP and RTU
Secondary Equipment (1) (2)
(3)
319
(4)
(5)
(6)
(7)
(8)
7
(9) 1 2 3 4 5 6 7 8 9 10
(10)
Description Thermostat Miniature circuit breaker – AC power supply Cubicle illumination lamp Door switch Heater ON/OFF switch Terminal block Terminal block Terminal block (AC bus wiring) Heater Earth bar
Figure 7-38: Supervisory Interface Panel (SIP)
320
Substation Design Manual
Chapter 8: 8.1.
SCADA System
Overview
Supervisory Control and Data Acquisition (SCADA) is a concept used to describe a system that enables control and monitoring of devices or equipment remotely. In TNB Distribution Division, SCADA systems are used to assist the operation and management of transmission and distribution of electricity. The advantages of using SCADA system are optimization of plant processes, and provide operations that are more efficient, reliable and safer. The basic overview of a SCADA system is depicted in Figure 8-1. It consists of three (3) main components: 1. 2. 3.
Master System Communication System Remote Terminal Units (RTUs)
A SCADA system consists of a number of Remote Terminal Units (RTUs) collecting field data and sending data back to a Master System via a communication system. The Master System displays the acquired data and also allows the operator to perform remote control tasks.
8
Master Systems are located in Regional Control Centres (RCC). At present there are four RCCs in Distribution, namely, the Metro and Southern Regional Control Centres (MSRCC), located in Kuala Lumpur and the Northern and Eastern Regional Control Centres (NERCC) in Seberang Jaya.
SCADA System
321
Data
Communication Communications System system
RTU
RTU
Master System (RCC)
Communication System
RTU
Remote Terminal Units
Figure 8-1: Overview of SCADA system
Figure 8-2: Metro Regional Control Centre
8
322
Substation Design Manual
8.2.
Master System
The Master System is essentially a network of computer subsystems with various functions to support the operation of the SCADA based control centre, as shown in the Figure 8-3. The Master System consists of basic SCADA functionalities such as data acquisition from Remote Terminal Units (RTUs), processing of acquired data, supervisory control, user interface functionality or Human Machine Interface (HMI), historical data processing, trending, communication with the communication gateway, etc.
Front end Data Servers/Back end
Human Machine Interface Printer Operator’s workstation
Operator’s workstation
Figure 8-3: The basic layout of the Master System
8
Functionally, the Master System consists of three (3) main subsystems: 1. 2. 3.
Front-end Subsystem Server/Back-end Subsystem Human Machine Interface (HMI) Subsystem
SCADA System
8.2.1.
323
Front-end Subsystem
The functions of the front end subsystem are as follows:
Manages communication with the Remote Terminal Units Responsible for the transmission and reception of raw data to/from the Remote Terminal Units Receives data from Remote Terminal Units, pre-process them and send to Server/Back-end Subsystem Receives control requests from Server/Back-end Subsystem and sends to Remote Terminal Units
8.2.2.
Server/Back-end Subsystem
The Server/Back-end Subsystem contains main SCADA applications and databases which holds information of all points. It processes control commands received from the Human Machine Interface (HMI), packages it and sends to Front-end. It also processes data received from the Front-end and sends to HMI.
8.2.3.
Human Machine Interface Subsystem
The Human Machine Interface (HMI) allows the controller to interface with SCADA System. It processes controller commands and send to Server/Backend Subsystem. It also receives information from Server/Back-end Subsystem and presents it to the controller either visually on monitors or printers. It also receives alarms and alerts the controller visually and audibly.
Figure 8-4: Human Machine Interface
8
324
Substation Design Manual
Additionally, two Distribution Management Systems (DMS) are also implemented into the Master Systems:
The first DMS function covers activities and tasks such as Distribution Operation Analysis, Safety Documents, Operational Document Management and Operational Planning. The second DMS function is the Forced Outage Management Functions, which include Fault Location, Isolation, and Service Restoration function, estimation of customer interruption, and Network Normalization Management.
8.3.
Communication System
The SCADA communication system facilitates transfer of data between Master System (RCC) and Remote Terminal Units (RTU). The communication mediums are as below: i. ii. iii. iv. v. vi.
Fibre optic Pilot cable Leased lines GPRS Radio Microwave
The network topology consists of:
8
i. Point-to-point ii. Multi-drop iii. Loop configuration While the communication schemes are: i. Polling ii. Unsolicited reporting The telecontrol protocols currently implemented are: i. ii. iii. iv.
IEC 60870-5-101 DNP 3.0 Extended WISP+ Harris H6000
SCADA System
325
The Extended WISP+ and Harris H6000 are required for legacy systems to support existing RTUs. Whereas the IEC 60870-5-101 protocol is mainly used to communicate with the newer RTUs installed in TNB’s network. The Inter-Control Centre Protocol (ICCP) is also implemented as control centre to control centre communication protocol.
8.4.
Remote Terminal Unit (RTU)
A substation installed with a Remote Terminal Unit (RTU) is considered a remote station. The SCADA equipment in a remote station consists of the RTU and communication equipment. The RTU collects data from the remote station, processes and executes control commands from the Master System. An RTU is a microprocessor-controlled electronic device that interfaces objects in the physical world to a distributed control system or SCADA by transmitting telemetry data to the system, and by using messages from the supervisory system to control connected objects. An RTU monitors the digital and analogue field parameters and transmits data to the Master System. An RTU can be interfaced with the Master System with different communication media and it can support standard protocols. In TNB substations, the RTU can be classified into two types: 1.
Primary RTU for PMU/PPU/SSU 33 kV - RTU cubicle is Floor-Standing type - DC supply is 110 VDC - Generally located in Control Room beside Supervisory Interface Panel (SIP)
2.
Secondary RTU for PE/SSU 11 kV - RTU cubicle is Wall-mounted type - DC supply is 30 VDC - Located in the Switchgear Room beside Wall-mounted SIP
8
326
Substation Design Manual
Master System
Control and Relay Panel
Supervisory Interface Panel
Remote Terminal Unit
SIP
RTU
Figure 8-5: Connection of Control Panels, Relay Panels, SIP and RTU
8.4.1.
8
RTU Requirements
RTU must have a valid Product Certification / “Sijil Guna Pakai” by TNB. RTU and communication module (modem and fibre converter) must derive its power from the substation’s: o 110 VDC supply and expected to operate between the range of 95 VDC to 130 VDC for PMU, PPU and 33 kV SSU. o 30 VDC supply and expected to operate between the ranges of 25 V dc to 40 VDC for 11 kV substations. RTU must be equipped with DC power supply surge protector. RTU must also be equipped with another surge protector to protect line communication module (modem & fibre converter) from electrical surge. RTU shall be able to support all communication protocols listed below: - IEC60870-5-101 (balanced and unbalanced mode) - IEC60870-5-103 - IEC60870-5-104 - DNP3.0
SCADA System
8.4.2.
327
I/O Interface Card
Data and control signals from/to the plant equipment are relayed to/from the Control Centre via the RTU’s input/output interface card module. The RTU input/output interface cards can be configurable and modular to suit different input/output interfaces with various sizes. The RTU input/output interface cards comprise of three (3) main items as described below: 1.
Digital input is typically a voltage-free normally-open contact at the plant side. The opening or closing of the contact will indicate a new status of the plant, e.g. circuit breaker open or close status, link open or close status, protection relay operation alarms and supervisory or local switch status & substation DC system alarms.
2.
Analog input is typically dc current (4-20 mA) that is usable to the RTU. The source is normally transformed value of the CT and/or PT secondary output, converted by transducers. Modern electronic relays may provide the DC current as well e.g. feeder & transformer loadings/amps, PT voltages, tap changer positions and temperature. This analog input may not be available and/or required in some plants.
3.
Digital Output is normally an open contact of interposing relay at the plant side. The momentary closing of the contact, which energizes the closing coil of the interposing relay, simulates the operation of a switch. Energizing the voltage of the coil is normally given by the RTU, from the substation DC voltage supply. Heavy Duty Interposing Relay is normally used to manage high switching current at the plant side.
8
328
Substation Design Manual
Cabinet Lamp
HX RTC Module
RTU Cabinet Indicators Power Distribution and Interport Link Module
RTU Input/Output Module
8
Grounding Bar
Figure 8-6: Example of an RTU in a Primary Substation (RTU type: Viscon Dua)
SCADA System
8.5.
329
SCADA-ready Substations
A substation is said to be equipped with SCADA-ready facilities if the plant equipment has facilities for data acquisition of power system parameters (derived from plant transducers), breaker status (On/Off), protection relays, alarms and control of various power system devices (breaker Trip/Close, motor operated switches Trip/Close and relay reset). Switchgears, Control Panels, Transformers, Earth Fault Indicators (EFIs), Line Fault Indicators (LFIs) and their related components such as indication devices, protection relays and CT/PT outputs are referred to as Plant Equipment. A SCADA system provides monitoring and control facilities for this plant equipment from the Control Centre. A SCADA-ready substation has these facilities wired to an Input/Output Termination Box at the plant side and the connection from the Input/Output Termination Box to the RTU via a Supervisory Interface Panel (SIP) or Remote Control Box (RCB) is known as Plant Interfacing Work. Generally, in the TNB Distribution Division SCADA system, 11 kV substations (including P/E, SS and SSU) are referred to as Secondary Stations whereas 33 kV substations (including PMU, PPU & SSU) are referred as Primary Stations. Plant equipment in Primary Stations are equipped with SCADA-ready facilities. However, most of the plant equipment in Secondary Stations are not.
8
330
Substation Design Manual
Chapter 9: 9.1.
Earthing
Overview
Earthing may be described as a system of electrical connections to the general mass of earth. An earthing system consists of two elements, the earth conductors and the earth electrodes.
The earth conductor is a conductor of low impedance which provides an electrical connection between a given point in equipment (an installation or system) and an earth electrode. The earth electrode is a conductor or group of conductors in intimate contact with and providing an electrical connection to earth.
9.1.1.
Design objectives
In general, there are 3 types of earthing systems: 1. 2. 3.
Safety or equipment earthing i.e. to protect human life against excessive hazardous voltages (touch and step voltages). Power system earthing i.e. to earth the neutral of a system and provide zero reference voltage. Lightning protection system for effective operation of lightning protection devices.
The substation earthing system shall meet two main purposes which are:
9
1.
2.
To provide means to carry electric currents into the earth under normal and fault conditions without exceeding operating and equipment limits or adversely affecting continuity of service. To assure that a person in the vicinity of earthed installations is not exposed to the danger of critical electric shock.
Earthing
331
To meet the design objectives and requirements, the design for earthing of all equipment and the provision of earthing systems and connections shall be in accordance with the recommendations in the following standards:
BS 7430 – British Standard Code of Practice for Earthing IEEE Std. 80 – IEEE Guide for Safety in AC Substation Grounding IEEE Std. 81 – IEEE Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System
9.1.2.
Step and Touch Voltage
When fault current or lightning strikes current flows in the earthing system, a voltage drop or potential difference is created between the earth electrode and radiating points from the electrode as shown in Figure 9-1. As can be seen in the example shown in Figure 9-2, the voltage drops V1, V2, and V3 etc (known as surface potential) vary according to earth resistance and the earth current at particular instant of flow.
/ lightning
9 Figure 9-1: Fault current path to earth and its induced potential gradient
332
Substation Design Manual
Surface of earth Top view of energised electrode V1 V4 V3
V2
Figure 9-2: Top view of surface earthing potential differences
Due to the existence of this potential gradient, two critical potential differences can be defined:
9
Touch voltage – The potential difference between the earth surface on which a person may stand and the surface of an earthed facility the person is touching. Step voltage – The difference in surface potential experienced by a person bridging the distance of 1 metre with the feet without contacting any grounded object.
Earthing
333
Figure 9-3: Critical shock situations Earthing systems shall have an overall voltage rise, touch voltage and step voltage that are uniformly distributed and within the allowed tolerances. The detailed step-by-step calculations to determine the allowable step and touch voltages can be found in IEEE Std. 80.
9.1.3.
Tolerable Current in the Human Body
The magnitude and duration of a current conducted through the human body at 50 Hz should be less than the value that can cause ventricular fibrillation of the heart. Ventricular fibrillation is a heart condition that results in immediate arrest of blood circulation. Fibrillation current is assumed to be a function of duration of the current and individual body weight. The safety of a person depends on preventing the shock energy from exceeding the fibrillation threshold before the fault is cleared.
9
334
Substation Design Manual
9.2.
Earth Connections Above-Ground
Above-ground earthing connections involve the earthing conductors and all intermediate connections made from a given point in the equipment to an earth electrode. Besides using suitable conductor types, the connection method is also important to ensure proper earthing requirements are met. The following are the approved types of earthing conductors and connection methods, followed by above-ground earthing layout for different substations.
9.2.1.
Earth Conductors
Earth conductors are used as circuit protective and bonding conductors:
9
1.
Circuit protective conductor: The conductors that connect each circuit to ensure that the earth fault current will return to its source separately. Includes conductors that connect the supply neutral to the earth electrode. E.g. metallic sheath of a cable, tin-plated copper braid, copper strips.
2.
Bonding conductor: These ensure that exposed metallic parts such as metal enclosures of equipment and other items of conductive material are bonded together and remain at approximately the same potential during electrical fault conditions. E.g. copper strip.
The criteria for selecting the material and sizing of earth conductors are: (a) Compatibility with material of earth electrode to minimise galvanic corrosion. (b) Resistant to corrosion. (c) Sufficient cross-sectional area to carry maximum earth fault current for a short time.
Earthing
335
The following equation is used to calculate the minimum cross-sectional area, Ac, of an earth conductor. It is in accordance to IEEE Std.80. Equation (minimum cross-sectional area, Ac) 𝐼 𝐴𝐶 = 𝑇𝐶𝐴𝑃 ∙ 10−4 𝐾 + 𝑇𝑚 ∙ ln 𝑜 𝑡𝑐 ∙ 𝛼𝑟 ∙ ρ𝑟 𝐾𝑜 + 𝑇𝑎 Where, I is the rms current (kA) Ac is the conductor cross section in mm
2 o
Tm is the maximum allowable temperature in C o
Ta is the ambient temperature in C o
Tr is the reference temperature for material constants in C Ko is the 1 𝛼0 or 1 𝛼𝑟 − 𝑇𝑟 in C o
αr is the thermal coefficient of resistivity at reference temperature Tr in 1/ o C ρr is the resistivity of the earth conductor at reference temperature Tr in 𝜇Ω-cm tc is the duration of current in seconds TCAP is the thermal capacity per unit volume from Table 1, pg 42 IEEE 3 o Std.80, in J/(cm · C) Alternatively, equation from BS7430 can also be used to determine the minimum cross-sectional area, S of earth conductor. 𝑆=
𝐼
𝑡 𝑘
Where, I is the average fault current, in Amperes (rms) t is the fault current duration, in seconds
9
336
Substation Design Manual
The rms current density, k, is derived from: 𝑘 = 𝐾 𝑙𝑜𝑔𝑒
𝑇2 + 𝛽 𝑇1 + 𝛽
Where, o
T1 is the initial temperature, in C o T2 is the final temperature, in C And values of K and β for typical conductor materials are shown in Table 9-1. Table 9-1: Values of K and β Metal Copper Aluminium Steel
K 2 A/mm (rms) 226 148 78
β C 254 228 202 o
Based on the criteria and calculations for selecting earth conductors, the types of earth conductors used in TNB are copper strips and tin-plated copper braid.
9
Earthing
9.2.1.1.
337
Copper Strip
For P/E 11 kV, SSU 11 kV and 11 kV switching room in PMU/PPU: 2 o 70 mm Cu equivalent. e.g. 25 mm x 3 mm For P/E 22 kV, SSU 22 kV and 22 kV switching room in PMU/PPU: 2 o 120 mm Cu equivalent For SSU 33 kV , 33 kV switching room in PMU/PPU: 2 o 300 mm Cu equivalent e.g. 50 mm x 6 mm
Figure 9-4: Copper strips connecting the supply neutral to earth (circuit protective conductor)
9
Figure 9-5: Copper strip for earthing of equipment (bonding conductor)
338
Substation Design Manual
9.2.1.2.
Tin-plated Copper Braid
Tin-plated copper braid with minimum cross-sectional area of minimum 2 16 mm Switchgear body Gasket
Screw P/E earth bar connected to cable box Lug socket Heat shrink
Back to PMU (star point)
Braided copper wire
Earth fault flow PILC or XLPE cable
Earth fault occurring downstream
Figure 9-6: Braided copper wire connecting cable sheath to earth
9
Figure 9-7: Copper braid (circuit protective conductor)
Earthing
9.2.2.
Connection Methods
All connections made in an earthing system shall meet the same general requirements for the conductors used in terms of electrical conductivity and current carrying capacity. The connections shall be strong enough to withstand the mechanical forces caused by the electromagnetic forces of the maximum expected fault currents and be able to resist corrosion for the intended life of the installation. Correct connection technique will ensure minimal contact resistance. Connection methods to be used for above-ground applications are: o Brazing o Bolt and nut
9.2.2.1.
339
Brazing
Connection is made by heating a piece of Silver Copper Phosphorus (SilFos) in between two copper plates. This method gives a solid electrical and mechanical connection.
Silver SilFos
9
Copper plate
Figure 9-8: Brazing
340
Substation Design Manual
9.2.2.2.
Bolt and Nut
The copper plate is first drilled to the required size of the bolt, the plate is then pre-tinned in order to provide a better electrical connection and to avoid oxidation of the copper before connection is made. Brass bolts and nuts are used. The bolts and nuts must be tied firmly to give a solid connection In order to avoid loose connection over a period of time, jam nuts are used.
Brass bolt Brass nut Lock nut 50 mm
Pre-tinned copper plate
Figure 9-9: Bolt and nut
Jam nut
9
Figure 9-10: Jam nut
Earthing
9.2.3.
341
Earthing Conductor Layout in Substations
The above ground earthing conductor layouts in substations are designed to achieve the following: 1) All exposed metallic parts such as metal enclosures of equipment and other installations of conductive material in the substations are interconnected 2) Continuity of the earth conductors to the earth electrode so that earth fault current flow to earth is ensured 9.2.3.1.
Earthing at PPU
For complete protection of the equipment and personnel working in a PPU, earthing conductors must be connected to the following: (a) Lightning arrestors (b) Installations: i. Switchgears ii. Transformers iii. Cable sheath of the power cables iv. Neutral Earth Resistor (NER) and Neutral Earth Isolators (NEI) v. NER Junction Box vi. Remote Tap Changer Cubicle (RTCC) vii. Control and Relay Panel (CRP) viii. Supervisory/SCADA Interfacing Panel (SIP) ix. Remote Terminal Unit (RTU) x. LV AC board xi. Battery charger The earthing for lightning arrestors must have dedicated earth electrodes. The lightning earthing electrodes and system earthing electrodes must be bonded together.
9
342
Substation Design Manual 2
All metal parts shall be bonded together using copper strip of 300 mm Cu equivalent and connected at some points to the earth electrodes. All connections of earth conductors shall be brazed. The design of the earth electrodes (i.e. earthing layout below-ground) shall refer to Subchapter 9.3 in accordance to IEEE Std. 80. Common earthing layout of a typical one and a half storey PPU is shown in Figure 9-11 and Figure 9-12 for each floor.
50 x 6 mm copper tape to be concealed on the floor
9
50 x 6 mm copper tape to be buried under ground
50 x 6 mm copper tape to be buried under ground
Figure 9-11: Earth connection of PPU (Ground floor and cable cellar)
Earthing
343
Copper tape rise from floor below
EF-2
EF-3
Copper tape rise from floor below
9
Figure 9-12: Earth connection of PPU (First floor)
344
Substation Design Manual
Table 9-2: Legend for PPU earth connection figures Symbol
Description
1
Copper tape to be buried inside concrete for all doors
2
Earth chamber including earth rod and connector
3
Jointing to the outside
4
Copper tape to be exposed ( 1 ft from finish stone chipping level)
5
Individual chamber not connected to be grid
TC
Test clamp 50 mm x 6 mm copper tape to be concealed on the floor Individual earth chamber
50 mm x 4 mm copper tape 50 mm x 4 mm copper tape
50 mm φPVC CONDUIT/DUCT
4 mm DIA. HEX NUT
4 mm DIA. BOLT SEALED IN WALL O.2 PCD EQUALLY SPACE 5 mm THK. M.S
9
Figure 9-13: Test clamp detail
Earthing
345
Square Tape Clamp
Ground Level
Copper Tape to be encased on the floor level
450
450
Square Tape Clamp
PVC cover copper tape from first floor
Ground Level
Figure 9-14: Square tape clamp
9.2.3.2.
Earthing for Indoor Substations
The earthing layout for indoor P/E is shown in Figure 9-15 and Figure 9-16. Earth conductors shall connect LV neutral bushing, transformer body, RMU body, feeder pillar body and cable sheaths at termination to the earth rods. The connections of the earth conductors use either bolted connection or brazing. All earth rods are connected in parallel with separation of L to 2L, where L is the length of the earth rod. To achieve the required earth resistance value of less than 3 ohms, more earth rods can be added in parallel. The details of earthing layout for indoor P/E are included in the Substation Design Booklet (Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian, TNB).
9
346
Substation Design Manual
Feeder pillar
Transformer Switchgear
Doors
Earthing point
Earth Chamber
Figure 9-15: Earth Connection of Standalone Indoor Substation – Double Chamber
Metering room
Transformer
Switchgear
Earthing point
Feeder pillar
9
Entrance
Earth chamber
Figure 9-16: Earth Connection of Attached Indoor Substation – Double Chamber with Metering Room
Earthing
9.2.3.3.
347
Earthing for Outdoor Substation
For outdoor P/E, the earthing layout is shown in Figure 9-17. Earth conductors shall connect LV neutral bushing, transformer body, RMU body, feeder pillar body and cable sheaths at termination to the earth rods. The connections of the earth conductors use either bolted connection or brazing. Earthing point
Transformer
Switchgear
Feeder pillar
Earth chamber
Door
Figure 9-17: Earth Connection of an Outdoor Substation
9
348
Substation Design Manual
9.2.3.4.
Earthing for Compact Substation
For compact substation, the earthing layout is shown in Figure 9-18. Within the enclosure, LV neutral bushing, all metallic bodies of the equipment and cable sheaths at termination are bonded using earth conductors. Typically, the enclosure is connected to the earth rods via two earthing points, one from the LV compartment and the other from the RMU compartment. The connections of the earth conductors use either bolted connection or brazing.
LV Feeder Pillar
Transformer
RMU
Doors
Earth chamber
Figure 9-18: Earth Connection of Compact Substation
9
Earthing
9.2.3.5.
349
Earthing for SSU
The earthing layout for SSU is shown in Figure 9-19. Earth conductors shall connect LV neutral bushing, all metallic bodies of the equipment and cable sheaths at termination to the earth rods. The connections of the earth conductors use either bolted connection or brazing. Earthing point
Earth chamber
Figure 9-19: Earth Connection of SSU
9.2.3.6.
Earthing for Pole Mounted (PAT) Substation
For PAT, the earthing layout is shown in Figure 9-20. The lightning arrestors must have dedicated or separate earth electrode or download and connected to a dedicated earth electrode. Meanwhile, earth conductors shall connect LV neutral bushing, transformer body and cable sheaths at termination to the system earth electrode. The lightning earthing electrode and system earthing electrodes must be bonded together.
9
350
Substation Design Manual
Lightning arrester
LV neutral Copper braid from cable termination
Transformer body
Copper strip Add more earth rods in parallel as and when required to improve earth resistance Earth chamber
9
Earth rod
Figure 9-20: Earth Connection of Pole Mounted Substation (PAT)
Earthing
9.2.3.7.
351
Earthing for Pole Mounted (PAT) Substation with RMU
The earthing layout for PAT with RMU is shown in Figure 9-21 and Figure 9-22. Earth conductors shall connect LV neutral bushing, transformer body, RMU body, feeder pillar body and cable sheaths at termination to the earth electrodes.
LV neutral
Copper braid from cable termination
Transformer body
Copper strip
Earth chamber
Earth rod
Add more earth rods in parallel as and when required to improve earth resistance
Figure 9-21: Earth Connection of Pole Mounted Substation (PAT) with RMU (front view)
9
352
Substation Design Manual
Add more earth rods as and when required to improve earth resistance
Copper braid from cable termination Add more earth rods as and when required to improve earth resistance
Copper strip
RMU
Feeder pillar
Earth Chamber
Figure 9-22: Earth Connection of Pole Mounted Substation (PAT) with RMU (top view)
9
Earthing
9.3.
Earth Connections Below-Ground
9.3.1.
Earth Electrode
353
Earth connection below-ground is a system of connected conductors buried in the earth used for collecting ground current from or dissipating ground current into the earth. Criteria of earth electrodes:
Sufficient cross-sectional area to carry the maximum expected fault current for a short time. Good electrical conductivity. Corrosion-resistant in soil: – examples of materials are copper, galvanised steel and cast iron. Aluminium is not suitable as earth electrode as it is susceptible to accelerated corrosion the oxide layer formed is non-conductive.
Typically components for the earth electrode are: 1. 2. 3.
Earth rods Earth plates Horizontal conductors
Earth rods must have rigid cores for easy driving-in. The earth electrode used in TNB is copper-clad steel. Copper-clad steel is used as it has high tensile strength, copper plating for better conductivity. They are able to reach into deeper, low resistivity soil with limited excavation and backfilling. Additionally, they are easy and cheap to install. Minimum size requirement for the earth rod is:
16 mm diameter x 1.5 m (5 ft) long
Earth rods are protected inside earth chambers as shown in Figure 9-24. The earth chamber is specified as:
30 cm x 30 cm (12” x 12”) in size Made of concrete To allow access to earth rod for inspection and testing
9
354
Substation Design Manual
Driving head
Coupler Earth rod
Coupler
Earth rod
Figure 9-23: Earth rod parts
9
Figure 9-24: Earth rod chamber and cover
Earthing
9.3.2.
355
Connection Methods
For below-ground, connection method used to connect earth electrodes is the brazing technique. Bolted connections are not allowed for below-ground connections. Exothermic or heat-releasing welding techniques can also be used for belowground connections. An example of exothermic welding is the Cadweld® technique. This connection method provides strong connections, is corrosionresistant, and is long-lasting even when exposed to harsh environments.
9 Figure 9-25: Cadweld mould (left) and completed connection (right)
The connection to each earth rod inside the earth chamber is considered as an above-ground connection. Hence, bolted connections are allowed between earth conductor and earth rod inside the earth chamber.
356
Substation Design Manual
9.3.3.
PPU Earthing Design
Design must be based on IEEE Std 80 following the following design process:
acquiring data on the proposed substation and site characteristics developing a preliminary design calculating the various hazardous voltages at many locations within and outside the substation to determine the relative safety of the design modifying the design as necessary recalculating the hazardous voltages to insure the design meets the objectives the process may have to be worked through many times before the objectives are achieved
Case study calculations of the Bukit Gambir Containerised PPU can be found in Appendix B. The executive summary and case study results are as follows. The design of the earthing system for the newly proposed Bukit Gambir CPPU has been carried out. Preliminary calculations have been performed using the IEEE Std.80 routines and the final design has been checked using the specialized earthing software package which is Current Distribution, Electromagnetic Fields, Grounding and Soil Structure Analysis (CDEGS). The main parameters and findings are shown in Table 9-3. Table 9-3: Bukit Gambir CPPU site earthing study findings
9
Earth resistance
2.51 Ω
Net single-phase-to-earth fault current
1600 A
Earth potential rise (EPR)
4.02 kV
Maximum touch potential within allowable limit
yes
Maximum step potential within allowable limit
yes
Earthing
9.3.4.
357
SSU/PE/PAT/CSU Earthing Design
Typically, the basic layout uses 4 earth rods connected in parallel using copper strip installed at the corners of the substation. The separations between these earth rods are in the range of L to 2L, where L is the total length of the earth rod. The earth resistance value of the earthing must be less than 3 ohms.
9.3.5.
Earth Resistance Measurement
Earth resistance, RE , is the resistance of the earth electrode with respect to remote/true earth of zero resistance. RE is measured to verify the adequacy of a new earthing system, detect changes in an existing earthing system, determine hazardous step and touch voltages and determine the Earth Potential Rise (EPR).
Legend: 1 – Electrode resistance 2 – Contact resistance 3 – Earth resistance I – Current
I
I
Figure 9-26: Earth resistance
Measurement method used in TNB to determine RE is called the fall-ofpotential (FOP) technique.
9
358
Substation Design Manual
I V
Current electrode
P
E
C
Potential electrode
x Electrode being tested
Current electrode
d
Figure 9-27: Fall-of-Potential (FOP) technique The FOP involves measurement of voltage and current by using potential and current probes driven into the earth. RE is calculated from the measured voltage and current (R = V/I) as a function of distance between the potential probe and the earth electrode under test, x. This is achieved by moving the potential probe at a certain distance from current probe which remains fixed. A typical FOP test result is as shown in Figure 9-28. Auxiliary potential electrode
Earth electrode under test
Effective resistance areas do not overlap
9 Resistance
62% of D
38% of D
Resistance of auxiliary current electrode Resistance of earth electrode
Distance from Y to earth electrode
Figure 9-28: FOP test result
Auxiliary current electrode
Earthing
359
According to IEEE Std. 81, the apparent RE value is the resistance at the 61.8% of the distance between the earth electrode under test and the current probe, D. This 61.8% rule is credible provided the following are met:
Adequate probe distances Homogeneous soil resistivity Identical electrodes
According to IEEE Std. 81, the spacing between the current electrode and the electrode/earth system being tested, D, shall be minimum 6 to 10 times the diagonal size of the earthing system of the substation, d (Figure 9-29).
Diagonal distance Substation earthing system
Figure 9-29: Diagonal size of the earthing system of the substation
This may require the use of extended leads for the current and potential probes as the standard lead’s length provided with earth resistance test equipment is typically 100 m only. The spacing is required to obtain more accurate RE as adequate separation will ensure the return current and voltage measuring points are effectively outside the influence of the earth system to be tested. If separation is not adequate and effective resistance areas overlap, the test result in Figure 9-30 is obtained leading to inaccurate RE. Another source of measurement error in FOP is when the return current and voltage measuring points are within metallic objects inherent of the site such as buried pipes. In this case, the test equipment will read RE value that is not the true apparent value. Therefore, the measurement area must keep away from metallic objects and must minimize their interferences.
9
360
Substation Design Manual
Ground electrode under test
Auxiliary potential electrode
Auxiliary current electrode
Resistance
Overlapping effective resistance areas
Distance from Y to ground
Figure 9-30: FOP test result
9.3.6.
9
Improving Earth Resistance
Earth resistance of earth electrode must be lower than allowable design value to achieve effective earthing Factors affecting RE: – Soil resistivity – Size and type of arrangement of individual earth rods
9.3.6.1.
Soil Resistivity
Soil resistivity varies from one soil spot to another depending on: – Moisture content – Chemical composition – Concentration of salt dissolved in contained water – Grain size and distribution – Closeness of packing of soil grain
Low soil resistivity is desirable to achieve low RE
Earthing
Soil treatment to lower resistivity includes: – Salt treatment (possible leaching, must be renewed periodically) – Bentonite (2.5 Ω·m at 300% moisture, not suitable for very dry environment) – Chemical-type electrodes (copper tube with salt) – Ground enhancement materials placed around rod in-hole or around grounding conductors in trench (e.g. SanEarth, GEM)
A site with low soil resistivity should be chosen when possible
361
9
Figure 9-31: Soil treatment around earth rod to lower soil resistivity
362
Substation Design Manual
9.3.6.2.
Size & Type of Arrangement of Individual Earth Rods
RE can be reduced by: – Increasing the length of buried rod (using coupler to connect additional rod). However this is only effective for soil profile with low resistivity at the bottom layer. – Increasing number of rods connected in parallel. Separation of rods shall be from L to 2L (L is length of rod).
Percent resistance of one electrode
80 Two rod electrodes 3 m long x 15.9 mm diameter 70
60
50
40 0
5
10
30 Electrode spacing, m 0 15
20
25
Figure 9-32: Effect of inter-electrode spacing on combined resistance
9
Fire Fighting System
363
Chapter 10: Fire Fighting System 10.1.
Overview
In case of fire occurring in a substation, a properly designed fire fighting system is important to mitigate and contain the fire. This chapter aims to introduce the basic concepts and requirements for TNB Distribution Substations. Table 10-1 shows requirements for substation fire protection. Table 10-1: Fire Protection Requirements Fire Protection Requirements 1. Collateral Damage IS NOT ALLOWED 2. NO Clean Up Required Electrical Equipment Extinguishing Agent Shall Be Electrically NON-CONDUCTIVE Safety To Human Safety To Personnel: 1. NO Oxygen Deficiency 2. NO Fatality (Lethal) Extinguishing Agent 1. Immediately Vaporize Upon Discharge 2. Leaves NO RESIDUES 3. Do Not Cause Significant Condensation Fire Performance 1. Extinguish All Type Classes of Fires (Class A, B and C) with NO RE-IGNITION 2. Very Fast To Extinguish Fires (Fast Fire Knock Down) Operational Issues Capable to Be Refilled On Side to: 1. Minimize Down Time (Post Accidental Agent Discharged or Post Fire Agent Discharged) 2. Maintain the level of availability of protection at highest level possible. Environmental Minimal Impacts On Environment, ODP = 0, GWP Impacts and ALT are acceptable defined by AHJ (Authority Having Jurisdiction), DOE (Department Of Environment) or EPA (Environmental Protection Agency) - USA Parameters Running 24 x 7
10
364
Substation Design Manual
10.2.
Fire System Requirements for TNB Substations
10.2.1. System Performance Requirements A system installed within TNB substations must meet specific performance requirements. TNB fire suppression system performance requirements include, but are not limited to: (a) Performance Based Design must be used based on the design fire scenario for substation fires applied for each particular enclosure, i.e., control room, switchgear room and indoors transformer room. (b) For halogenated agent, the maximum HF by products shall be LESS than 500 ppm. Engineering correlation may be used to estimate the maximum allowable fire size. (c) Discharge time shall be as short as possible to extinguish fire efficiently and to limit further fire damage on protected equipment. (d) The under/over pressurization in the enclosure due to agent discharge shall be as low as possible to maintain the integrity of the enclosure boundaries (minor building modification is permitted). (e) Pressure relieving vents, located near the finished ceiling, may be necessary to regulate rapid pressure changes during discharge. Comply with the manufacturer’s recommended procedures relative to enclosure venting. (f) System Design Approval - Prior to installation of a fire extinguishing system, the system must be certified or approved as compliant to all TNB’s PSI requirements (ENGR-750-54, ENGR-5202-PSI and ENGR-5203PSI)
10
Table 10-2 and Table 10-3 highlight the extinguishing system performance parameters and minimum standard requirements for detection system.
Fire Fighting System
Table 10-2: Extinguishing Agent System Performance Parameter Minimum Standard Requirement Extinguishing Extinguish all fires without re-flash (re-ignition) Agent 8 AWG, XLPE Cable Fires – 350 Amp Current Flammable Liquid Spilled Fire (Pool Fire) Fast to Ultra Fast Fire Growth Agent Less than NOAEL concentration level or Not to exceed Concentration Maximum PBPK Concentration for 5 minutes exposure time. Enclosure Over Less than Lung Damage: 80 kPa (11.6 psi) Pressure Acid Gases (HF + Potential impact for Equipment: Less than 500 CF2O) by-products ppm peak. Potential impact for Human: Less than 200 ppm for 5 minute exposure to human. Oxygen Level Not below 16% for 5 seconds average Skin Burns Less than second-degree skin burns: o 2 < 1316 C-s over 10 seconds or heat flux < 160 kJ/m o 2 (<2400 F-s over 10 seconds or heat flux < 3.9 cal/cm ) 2 Discharge Forces Not to exceed 78 m/s (8g) over 30 ms Discharge Noise Not to exceed hearing protection level With hearing protection: 162 dB Without hearing protection: 140 dB Agent Accidental Not cause collateral damage (Leaves No Residues). Discharge (No Fire The protected equipments are in good running Discharged) condition 24 x 7, without any personnel intervention. Agent Fire Not cause collateral damage (Leaves No Residues). Discharged (Post The un-damage equipments are still in good Fire Capability) condition and may run (work) 24 x 7. Minimal down time to replace the damage equipment due to fire. Enclosure Venting Minimal Venting Based On: and Integrity 500 Pa Structural Strength 80% Minimum Protected Height During 10 Minutes Holding Time.
365
10
366
Substation Design Manual
Table 10-3: Detection System Performance Parameter Minimum Standard Requirement Smouldering Fires Cross Zoning Detection Systems o Photoelectric Smoke Detector with 10 C Rate o of Rise of Temperature and greater than 40 C o Ionization Smoke Detector with 10 C Rate of o Rise of Temperature and greater than 40 C Flaming Fires Cross Zoning Detection Systems o Photoelectric Smoke Detector with 10 C Rate o of Rise of Temperature and greater than 40 C o Ionization Smoke Detector with 10 C Rate of o Rise of Temperature and greater than 40 C Sensitivity Adjustable with minimum 0.5%/ft Detection Activation Capability to be activated at range of fire size from 100 kW to 200 kW, with onset cable damage at 400 kW fire size. Maintenance Easy to maintain: Intelligent, self diagnostic Built-in Drift Compensation Field Replaceable Optical Chamber Visual indication when time to clean False Alarm Immunity
10.2.2. System Design Approval The certification/approval plan defines the approval requirements for a system and should provide sufficient overall system detail and description so that all certification requirements can be adequately assessed and agreed to. The certification plan includes, but is not limited to, a functional hazard assessment (FHA), a detailed system description and operation, identification and means of compliance to each applicable regulatory requirement, minimum dispatch configuration, certification documentation, and a schedule.
10
ENGR-5202-PSI ENGR-5203-PSI
ENGR-5206-PSI
ENGR-5207-PSI
INSTALLATION
Fire Fighting System
367
A summary of contents from the PSI requirements that are required for system design approval are as follows. 10.2.2.1.1. 1. 2. 3. 4. 5. 6.
Design Brief Site Survey Report Performance Based Design Analysis Hydraulic Flow Calculation Battery Load Calculation Design Drawing (Shop Drawing)
7.
2. 3.
Fire Alarm And Detection Systems Layout Schematic Diagram - Fire Extinguishing System Schematic Diagram – Releasing Agent Control Panel Fire Suppression Piping Layout Fire Suppression Isometric Diagram
ENGR-5203-PSI – Materials Specifications
Technical Specification of the materials (components) used in the proposed design conforming to the SGP material list.
10.2.2.1.3. 1.
Plan Layout Drawing
Cylinder Arrangement and Demarcation Lines Manufacturer Type Endorsement Certificate for Design Analysis
10.2.2.1.2. 1.
ENGR-5202-PSI - Proposed Fire Extinguishing System Design
ENGR-5210-PSI – Delivery Quality Assurance and Installation Quality Control
Product Delivery Quality Assurance Certificate issued by third party appointed by TNB Installation Quality Control Certificate issued by third party appointed by TNB Testing Commissioning and Acceptance
10
368
Substation Design Manual
10.2.3. Component Design Requirements All component used shall be approved (listed) under the following internationally accredited bodies: 1. 2. 3. 4. 5. 6. 7. 8.
Underwriter Laboratories (UL) Factory Mutual (FM) Loss Prevention Certification Boards (LPCB) Vertrauen durch Sicherheit (VdS), German fire protection institute ASME B16.3 (2006) Malleable Iron Threaded Fittings, Classes 150 and 300 ASME B16.39 (2009) Standard for Malleable Iron, Threaded Pipe Unions; Classes 150, 250, and 300 ASTM A106/A106M (2010) Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service ASTM A53/A53M (2010) Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless
Defence-In-Depth (DID) philosophy and concept shall be applied: (a) Minimizing the probability of control panel damage and accidental discharge due to lightning strike.
220 – 240 VAC
Solenoid Actuator
POWER LINE LIGHTNING ARRESTOR
SIGNAL LINE LIGHTNING ARRESTOR
RELEASING AGENT CONTROL PANEL
BACKUP BATTERIES
The use of Power Line and Signal Line Lightning Surge Arrestor have the following benefits:
10
1. 2. 3.
Damaging the control panel system components Maintain the expected backup batteries life and avoiding the premature damage. Minimizing the accidental (voluntary) discharge due to lightning strike
Fire Fighting System
369
(b) In the case of control panel power loss during fire event, the extinguishing agent shall be capable to be discharged manually (redundancy system). MECHANICAL MANUAL DISCHARGE ACTUATOR
AUTOMATIC INITIATING DEVICES
ELECTRIC SOLENOID DISCHARGE ACTUATOR
MANUAL INITIATING DEVICES
CYLINDER VALVE
RELEASING AGENT CONTROL PANEL
AC POWER
BACKUP BATTERIES
The discharge system actuation of extinguishing agent shall have two actuation systems, i.e., electrically and manually. Electrical actuation can be triggered automatically by system detectors or manually by manual release station through control panel. The manual mechanical actuation will be the last survival of the system to enable to discharge the extinguishing agent in the case of electrical power loss during fire event. Any proposed system which has no manual mechanical actuation on the system cylinder will not be considered.
10
370
Substation Design Manual
10.2.4. Testing Requirements (a) Blow Off Testing - To ensure that there will be no residual solid particles inside the discharge piping distribution, which may cause damage to the protected equipment. (b) Extinguishing Agent Integrity Testing - To ensure that all extinguishing agent dispersed and mixed within the enclosure through discharge nozzle, in order to efficiently extinguish the fire. (c) System Component Functionally Testing – To ensure the component functionality as per specification. (d) Functional System Integrity Testing – To ensure the operation sequence of the systems as designed. (e) Room Integrity Testing - To Meet 10 Minutes Minimum Holding Time to ensure No Re-Ignition.
10.2.5. Guarantee Requirements The guarantee is for a period of 5 years with an option for another 5 years subject to the following conditions: (a) Installations and revisions are done by panel contractor (installer) possessing the DITCM (Design-Installation-Testing-CommissioningMaintenance) Approval from manufacturer having SGP from TNB. (b) Installations shall be done according to the Installation and Manual Operation from Manufacturer. (c) The guaranteed of the goods shall be for an initial period of 1 year, subject to an annual revision done by the panel contractor and annually renewed once every revision is done, with maximum guarantee of 5 years.
10
Fire Fighting System
371
Within the guarantee period in force, the manufacturer shall warrant the following conditions: (a) The extinguishing agent discharge shall be clean, non corrosive and will not damage to the machinery and equipment, non toxic and will not harm to human. Under technical advice from manufacturer, panel contractor (installer) shall be responsible for cleaning, repair work or replace or pay the damages claimed by TNB on TNB’s assets which are directly damaged by the voluntary discharge of extinguishing agent. (b) The system components supplied shall be genuine, new and complete system and function within the warranty period. Panel contractor (installer) shall be responsible for the damages or pay damages claimed by TNB on TNB’s assets which are directly damaged from the failure of the system to function during fire. (c) Within the warranty period, the systems shall not have false discharge due to the system manufacturing and/or design defect. Panel contractor (installer) shall be responsible for rectification work on the system supplied and gas refill due to the false discharge.
10.2.6. Sijil Guna Pakai (SGP) All fire fighting systems must utilize products that have obtained the certificate of Sijil Guna Pakai (SGP) from approved panel companies (syarikat panel). Products with the SGP are to be installed, commissioned and maintained by the supplying panel companies for five years after commissioning. A list of presently approved products with SGP can be found in the Circular Surat Pekeliling Pengurus Besar Kanan (Pengurusan Aset) Bil. A14/2012 Menggunapakai Khidmat Syarikat Panel dan Produk Sistem Pemadam Kebakaran untuk Bahagian Pembahagian.
10
372
Substation Design Manual
10.3.
System Components
The fire extinguishing system must be designed, tested and installed to be compatible with the existing building and substation. Typical fixed fire extinguishing system consists of: 1. 2.
Fire Suppression System Components Fire Alarm and Detection System Components
10.3.1. Fire Suppression System Components The set of components for the fire suppression system include the Extinguishing Agent, Master/Pilot Cylinder, Storage Cylinders, Piping Network including Manifold, Valve Opening Actuation Hoses, Manual Pneumatic Discharge Lever, Pneumatic Cones, Pressure Gauge, Safety Burst Disk, Discharge Hoses, Check Valve (Retention Valve), Pressure Switch, Solenoid Actuator and Discharge Nozzle(s).
10 Figure 10-1: Typical system components and arrangement
Fire Fighting System
7
TO PIPE DISTRIBUTION AND NOZZLE(S)
6
5
3 4
2
1. 2. 3. 4. 5. 6. 7.
373
2
2
1
Master cylinder Slave cylinder Solenoid actuator Opening valve connection hose Discharge hoses Manifold Restrictor (pressure reducer only for systems using inert gasses)
Figure 10-2: Arrangement of storage cylinder components
10
374
Substation Design Manual
10.3.2. Fire Alarm and Detection System Component The main detection system component is the Releasing Agent Control Panel. It receives signals from fire detectors and engages the fire suppression system. Other components of the fire detection system are Secondary Power Backup Batteries, Automatic Initiating Devices (Fires Detectors), Manual Initiating Devices (Manual Release and Abort Stations), Alarm Bell, Sounder (Horn/Siren) and Strobe (Beacon), Evacuate Sign, Agent Discharge Sign, LED Beacon. PENGESAN KEBAKARAN AUTOMATIC INITIATING DEVICE (ZONE-01)
RELEASING AGENT CONTROL PANEL
ALARM BELL
HORN STROBE
EVACUATION SIGNAL
AUTOMATIC INITIATING DEVICE (ZONE-02)
PANEL KAWALAN
AC POWER
12VDC BACKUP BATTERY
MANUAL INITIATING DEVICES
EVACUATE
SOLENOID ACTUATOR
BEKALAN ELEKTRIK
Figure 10-3: Releasing agent control panel connections
10
ALARM SYSTEM DEVICES
DETECTION SYSTEM DEVICES
LED BEACON
New Technology
375
Chapter 11: New Technology 11.1.
Mobile Equipment
11.1.1. Mobile Power Transformer 15 MVA 33/11 kV 11.1.1.1. Overview Transformer is the heart of any substation. It provides the power source to serve vast areas and consumer population including domestic, commercial, industrial, hospitals, governmental administrative centres and other critical areas. During its service life, the transformer needs to be maintained as to prolong its life and to prevent catastrophic failures. Often the case, shutting down a 33/11 kV transformer for maintenance or repair is almost impossible especially for areas where supply availability is most critical, for example administrative, commercial or industrial areas with high loading and limited or no injection points, islanded system or single transformer substations with no n-1 capability. Unexpected failures of the transformer as the result of internal failure, natural disaster, sabotage or act of terrorism are also possible resulting in system outage in the surrounding territory. If such failure occurs in the critical areas described above, then complete restoration of supply to such areas may take days, resulting in loss of income and serious damage to TNB reputation. For the reasons mentioned above, many utilities in the world have utilized mobile transformer simply for its main advantage of fast and rapid deployment capability. In short, mobile transformer can be used to ensure supply availability and reliability for the following purposes and conditions:
Planned maintenance Forced outage for transformer repair Supply restoration due to transformer failure Temporary supply before completion of PPU
11
376
Substation Design Manual
11.1.1.2. Design 11.1.1.2.1.
General Concept
The design of the mobile power transformer is based on the following concepts:
Mechanically Robust – To cater for mechanical vibration as the result of frequent movement along various kinds of terrain profiles and road conditions. Higher Thermal Withstand Capability – To suit for the thermal effect due to various load condition at different sites. Installation Flexibility – To be able to connect, terminate or dismantle from system easily and fast. Use of more superior or advance technology for ease of cable laying and connections such as plug-in bushings is being considered. Prolonged Life – To have better or improved design characteristics so that the transformer can be utilized when needed without failing. Environmentally Green – To minimize risk due to pollution of soils and environment with the consideration of the use of green technology i.e. synthetic bio-degradable oil for insulation and cooling. Ease of Installation & Operation – To possess ability for plug-and-play for ease of installation, operation and dismantling. Safety of Operators – To prevent any potential hazards to the operators by taking into consideration security and practicality of the design.
11.1.1.2.2.
Basic Configuration
The mobile power transformer consists of the following main components mounted on a trailer:
11
15 MVA 33/11 kV Power Transformer 11/0.415 kV 100 kVA Auxiliary Transformer Neutral Earthing Resistor (NER), Remote Tap Changer Control (RTCC) Panel
In addition, the mobile power transformer will be fully equipped with a Prime Mover suitable for the application.
New Technology
11.1.1.2.3.
377
Basic Parameters
The basic specification of the power transformer is as shown in Table 11-1. Table 11-1: Basic technical specification of the Power Transformer Category Technical Parameter No. of phases & rated frequency
3-phase, 50 Hz
Short Circuit Impedance
10% at reference temperature of 75°C
Vector Group
Dyn11
No-Load Losses at Nominal Voltage
8.5 kW ± 10%
Load Loss at Nominal Voltage Tap
75 kW ± 10%
Maximum Noise Pressure Level
55 dBA
Core Maximum Flux Density
1.6 Tesla
Winding Maximum Current Density
2.5 A/mm
Temperature Rise
50°C (Top Oil), 55°C (Winding)
Tapping Range
+10% to -15% at 1.67% per step on HV winding
Type of Oil Insulation
Synthetic Ester Bio-degradable Oil
Type of Cooling
ONAN/ONAF
Type of Bushing HV & LV
Plug-in Type
Maximum Dimensions (incl. Trailer & Prime Mover)
17 x 4 x 5 meters (L x W x H)
2
Similar to the power transformer, the auxiliary transformer will also be using synthetic ester bio-degradable oil. All other technical parameters are similar to the specification of a normal distribution transformer. The NER ratings will follow the basic parameters as listed in Table 6-22 Chapter (NER).
11
378
Substation Design Manual
RTCC
Figure 11-1: Illustration of the proposed mobile power transformer arrangement showing the main components
11.1.2. Mobile Step-Up Transformer 625 kVA 0.415/11 kV 11.1.2.1. Overview When power interruption occurs due to power system breakdown or failure of power equipment, system operators are obliged to restore supply as soon as possible to ensure SAIDI is below targeted level. In the process, some operators tend to feed supply into 11 kV network using the existing step down transformer in order to reduce the number of mobile generators used until supply is normalized and fully restored. In the case where breakdown occurred in the rural area, a 500 kW mobile generator may be sufficient to step up supply to feed a number of substations.
11
However, the above practice to step up supply using a normally step down transformer is strictly prohibited by TNB with the issue of the Vice President Directive No. A14-2008. This is because under normal load flow and normal voltage regulation condition, use of step down transformer as step up will work and supply can be fed without any problem. However, problem usually occurs during line-to-earth fault condition in the 11 kV (delta) side. This is because step down transformer with Dyn11 vector group has no star point on
New Technology
379
the 11 kV side and therefore the system protection could not detect the earth fault current to trip the protection device. Under this condition, the faulty phase will normally approach zero volts but the voltage of the un-faulty phases will rise by hazards.
3 times their phase voltage and give rise to safety
11.1.2.2. Use of a Permanently Installed Step-Up Transformer To solve the issue on using step down transformer for stepping up supply, the Senior General Manager (Engineering) has issued a circular No. A17-2009 to give guidelines on the use of permanently installed step-up transformer. The technical requirement set-up in the circular that need to be complied is as follow: i.
ii. iii. iv. v. vi. vii.
viii.
The vector groups for the step-up transformer shall either be YNd11 or YNd1 or YNyn0. For standardization purposes, the use of YNyn0 vector group is not recommended for new project. Voltage ratio shall be 0.415/11 kV. Installation of the step-up transformer shall be at substation on a spur feeder. The selected substation shall be installed with added RMU T-off Transformer Circuit or a VCB. The RMU T-off Transformer Circuit shall be fitted with appropriate fuses whilst the VCB shall be fitted with appropriate relays. LV distribution board or feeder pillar may be installed when necessary. The capacity of the step-up transformer shall be equal or more than the capacity of the mobile generator. For example 625 kVA transformer for 500 kW generator. The step-up transformer shall be tested and proven healthy for use.
The substation selected for the permanent installation may be at the upper stream, middle or downstream of the spur feeder depending on the rating and size of 11 kV cables, logistic and installation suitability, operation and customer requirement as illustrated in the diagram below:
11
380
Substation Design Manual
Step up transformer 0.415/11 kV YNd1 or YNd11
Step down transformer 11/0.415 kV Dyn11
Distribution Board (DB) or Feeder Pillar
Mobile generator set
To LV customer Distribution Board (DB) or Feeder Pillar To the other substation To the other substation
PE 11/0.415 kV
Figure 11-2: Schematic Diagram of 11 kV network showing substation with permanently installed step-up transformer
11.1.2.3. Use of a Mobile Step-Up Transformer 11.1.2.3.1.
General Concept
Based on the Senior General Manager (Engineering) Circular No. 17-2009 described in Paragraph 3 above, the proposed mobile step-up transformer will consist of a step-up transformer 625 kVA 0.415/11 kV securely mounted on a mobile truck or drawbar trailer. Appendix 1 shows the basic layout drawing for the proposed design. For the proposed mobile step-up transformer unit, RMU T-off Transformer Circuit or VCB shall be permanently installed at the selected substation and will not be part of the mobile step-up transformer unit.
11
New Technology
11.1.2.3.2.
381
Design Concept
The proposed concepts for the design of the mobile step-up transformer are:
Mechanically Robust – To cater for mechanical vibration as the result of frequent movement along various kinds of terrain profiles and road conditions. Higher Thermal Withstand Capability – To suit for the thermal effect due to various load condition at different sites. Installation Flexibility – To be able to connect, terminate or dismantle from system easily and fast. Use of more superior or advance technology for ease of cable laying and connections such as plug-in bushings may be considered. Prolonged Life – To have better or improved design characteristics so that the step-up transformer can be utilized when needed without failing. Environmentally Green – To minimize risk due to pollution of soils and environment with the consideration of the use of green technology such as synthetic bio-degradable oil for insulation and cooling. Ease of Operation – To ease in particular, monitoring of the load so that it shall not exceed the capacity of the step-up transformer or the mobile generator. Safety of Operators – To prevent any potential hazards to the operators by taking into consideration security and practicality of the design.
11.1.2.3.3.
Application
It should be noted that the substation or feeder fed by the mobile generator through the step-up transformer shall be operated in islanded operation and isolated from other system or other source of supply.
11
382
Substation Design Manual
11.1.2.4. Rationale for the Use of Mobile Step-Up Transformer and the Advantages over Permanent Installation The rationales and advantages for the use of mobile step-up transformer are as follow:
The step-up transformer if permanently installed will only be utilized when major power interruption occurs. Hence, the use of mobile step-up transformer is practical for effective asset utilization. The use of the mobile step-up transformer will give more flexibility for selection of the substations (indoor or outdoor). This is because the selected substation for stepping up voltage into the 11 kV network will only require added installation of either a RMU T-off Transformer Circuit or a VCB and will therefore solve the issue of space constrain.
Figure 11-3: Illustration the proposed arrangement of the mobile step-up transformer
11
New Technology
383
11.1.3. Mobile Compact Sub The Mobile Compact Substation is basically a compact substation unit (CSU) that is mounted on a mobile platform. It is designed for the following purposes:
Temporary replacement in the event of substation failure due to transformer or switchgear failure. Used for the immediate need of power supply especially for fast track projects while permanent substations are being constructed. Used to fulfil temporary power supply application which require high 3phase load.
The capacity of the transformer of CSU is 1000 kVA and further details are the same as in Chapter 4.6.
Figure 11-4: Mobile compact substation
11
384
Substation Design Manual
11.2.
Energy Efficient Distribution Transformers
11.2.1. Overview Transformers operate 24 hours a day, seven days a week during which time they undergo constant losses of 1 to 2% of the electricity that passes through them. Energy efficient transformers can help to minimize these losses. In Malaysia, more than 80% of electricity generation is by fossil fuel that contributed to the CO2 emission. In financial year 2010/11, a total of 0.54 metric tons of CO2 emission was estimated per MWh of electricity produced by TNB. Thus, by reducing transformer losses, CO 2 emission can directly be reduced to minimize the global green house effect. In TNB distribution network, distribution transformers are the third largest loss-making component after LV and 11 kV overhead and underground cables. The total losses contributed by distribution transformers throughout the distribution network are as shown in Figure 11-5.
Distribution Transformer 1.21%
33kV OH & UG cables 0.29%
22kV OH & UG cables 0.10%
11kV OH & UG cables 1.61%
Power Transformer 0.41%
LV OH & UG cables 1.67%
6.6kV OH & UG cables 0.06%
Figure 11-5: Technical losses by components in TNB distribution system
11
New Technology
385
In order to reduce transformer losses and to achieve overall reduction in technical losses, TNB had acknowledged the following transformer technologies. However, the adoption of these technologies will commence once they are cost effective where the total ownership costs of these transformers are at least equal to the total ownership cost of the conventional silicon steel core transformers.
11.2.2. Amorphous Wound Core Transformer Silicon steel has been used over the years as transformer core material. Silicon steel like most metals, have a crystalline structure. This means that the atoms in the structure arrange themselves in an ordered manner. On the other hand, the atoms in an amorphous metal are not arranged in any ordered structure; rather they have a tightly-packed, but random arrangement. Amorphous metal are formed by cooling the liquid material quickly enough to prevent crystallization; the atoms do not have time to arrange themselves into an ordered structure. Figure 11-6 shows the structure of crystalline, polycrystalline and amorphous materials.
Figure 11-6: Structures of crystalline, polycrystalline and amorphous materials Amorphous metal contains ferromagnetic elements such as iron, or cobalt alloyed with a glass former such as of boron, silicon, or phosphorus. These materials have high magnetic susceptibility, with low coercivity and high electrical resistance. The high resistance leads to low losses by eddy currents when subjected to alternating magnetic fields, a property particularly useful in
11
386
Substation Design Manual
transformers. Typically, core loss can be 70–80% less than with traditional crystalline materials.
Figure 11-7: Flat wound core and coil assembly of amorphous core transformer
As explained in Chapter 6.1.5.1, most distribution and power transformers core construction are typically of stack core type. However, because of the specific characteristics of amorphous metal i.e. brittleness, sensitivity to pressure, low saturation, wafer thickness at only 0.025 mm, etc., the amorphous core is suitable only for wound core and the transformer core design has to be modified; instead of a three legged core, a three phase amorphous transformer needs four cores to form a five legged core as shown in Figure 11-7.
Figure 11-8: Fully assembled oil immersed amorphous core transformer
11
New Technology
387
11.2.3. Tri-Dimensional Wound Core Transformer The improvement in the transformer design has led to the introduction of the tri-dimensional triangular wound core which has changed the existing configuration of the core and coil assembly of the transformer. The tridimensional wound core comprises of three separate cores which are exactly the same, allowing symmetrical and identical magnetic circuit in each core. Each single core of this tri-dimensional core is wound with several trapezoid shaped grain oriented silicon steel strips continuously in order, avoiding air gap that cause high resistance due to laminating joints. The cross sectional area at any point of the core frame is almost a semicircle and with rounded corners as well as shorter yoke length, high flux density can still be achieved with less utilization of core material.
Figure 11-9: Structure of tri-dimensional wound core
When fully assembled, the joined sections of the laminated cores form three identical columns or limbs which are almost perfectly round in shape with cross sectional filling factor reaching 99%, avoiding magnetic flux distortion at joined sections. All the above factors contribute to the reduction of no-load loss by 15 ~ 20% and noise level improvement by 5 ~ 10 dB for the same silicon steel grade. In addition, for the same cross sectional area of the limb, the average length of the winding can be reduced by 2 ~ 3% as compared to the conventional stack core due to the more circular cross sectional area of the limb as shown in Figure 11-10.
11
388
Substation Design Manual
Figure 11-10: Cross sectional area of a tri-dimensional core limb (left) and conventional stack core limb (right)
Figure 11-11: Complete assembly of oil immersed tri-dimensional wound core transformer showing before tanking (left) and after tanking (right)
11
New Technology
389
11.2.4. Performance Comparison between Amorphous Wound Core and Tri-Dimensional Wound Core Transformers
The Amorphous Wound Core Transformer has higher energy efficiency followed by the 3-D Wound Core Transformer as compared to Conventional Transformer for all loading profiles and sectors as shown in Figure 11-12. The higher energy efficiency of the Amorphous Core Transformer is mainly due to its very low no-load loss even though its load loss is slightly higher than the 3-D Wound Core and the Conventional Transformers as indicated in Table 11-2. The results shows that generally the transformers reach their maximum energy efficiency at 30-50% of their loading capacity. The 3-D Wound Core Transformer has relatively lower material utilization as indicated by its weight for low load loss and noise level performance. The Amorphous Wound Core Transformer demonstrated the highest energy efficiency and reduction for total energy loss and CO 2 emission followed by the 3-D Wound Core Transformer.
Table 11-2: Main Features of 11/0.433 kV Amorphous Core and TriDimensional Core Transformers 300 kVA as compared to Conventional Silicon Steel Core No 1
Transformer TNB Specified Maximum Limit Conventional Silicon Steel Stack Core
No-Load Loss (watts)
Load Loss (watts)
Noise Level (dBA)
Weight (kg)
600
2800
60.0
-
547
2662
58.6
1650
2
Amorphous Wound core
111
2719
44.7
1270
3
Tri-Dimensional Silicon Steel Wound Core
480
2655
42.0
1124
11
390
Substation Design Manual
Figure 11-12: All-day efficiency of Amorphous Core and Tri-Dimensional Core Transformers as compared to Conventional Transformer for all loading profiles and tariff sectors
11.3.
Cast Resin and Synthetic Ester Bio-Degradable Oil Immersed Transformers
11.3.1. Overview
11
TNB has been using oil filled transformers in its system. However there are issues such as fire (flammability) environmental concerns (low biodegradability), leakage and maintenance associated with these transformers. These concerns are magnified for those transformers located in the densely populated areas, public areas, shopping centres, especially when the substations are attached to the building. Hence, the use of cast resin transformers and synthetic ester bio-degradable oil immersed transformers have been approved for use in indoor and outdoor (including pole mounted and mobile) distribution substations respectively for less flammable and more environmental friendly insulation materials.
New Technology
391
11.3.2. Cast Resin Transformer The use of cast resin transformer is recommended in location where the fire risk associated with the use of mineral oil is considered to be unacceptable, for example in substation buildings attached to shopping complexes, offices, apartment buildings, hospitals and the like. The metal parts of a cast resin transformer account for around 90% of its total weight. The insulation materials amount to only about 10%. Of this, less than half can be considered flammable because typically about two-thirds of the resin compound is silicon dioxide filler (quartz powder) and much of the insulation material of the LV winding is glass based. Hence not more than 56% of the total weight of the transformer comprises of flammable substances. In addition, the resin used has typical self ignition temperature of 450 ⁰C at which the material will start to ignite. Some main features of cast resin transformer are as follow:
Uses epoxy resin reinforced with glass fibre which prevents cracking of epoxy compound even under overload conditions. Epoxy resin has excellent electrical properties, low shrinkage, good adhesion to many metals and resistance to moisture, thermal and mechanical shock. By molding process.
Figure 11-13: Typical Cast Resin Transformers
11
392
Substation Design Manual
Table 11-3: Main Difference in Construction and Manufacturing Techniques of Cast Resin Transformers Parts
Main Features
Construction/Manufacturing Methods
Type of Conductor
Type of Insulation Layer
HV Winding
Type Embedding Techniques
Type of Conductor
LV Winding
Type of Insulation Layer Type of Embedding Technique
Note:
11
Cu – Copper Al - Aluminium
Cu or Al round or rectangular shape with or without enamel coating Cu or Al foil Glass fleece layer Non-layer glass mat on inner and outer surface Very thin layer or turn insulation Mylar foil Vacuum cast quartz powder filled resin Epoxy glass vacuum Epoxy quartz + Al(OH)3 Vacuum cast glass fibre laminated Epoxy no vacuum (high risk of bubbles formation)
Cu or Al foil
Layer insulation pre-impregnated (pre-preg); polyester foil with glass resin coating
Polymerized by heat treatment
New Technology
393
Table 11-4: Technical Comparison between Cast Resin Transformer and Hermetically Sealed Oil Immersed Transformer Criteria
Cast Resin Transformer
Hermetically Seal Oil Immersed Transformer
Environmental Effect
Not polluting
Yes (mineral oil leakage which is not biodegradable)
Temperature Rise Limit
100 K
60 K
Flash Ignition Temp/ Flash point (Liquid)
Flash Ignition Temp = 310˚C (Temperature at which gases evolve from the material can be ignited by a spark)
Flash point = 150˚C (Lowest temperature at which it can vaporize to form an ignitable mixture in air)
Self Ignition Temp/ Fire Point (Liquid) (Insulating liquid below ≤ 300°C is considered flammable liquid)
Self Ignition Temp 450˚C (Epoxy Resin) = temp at which the material will spontaneously ignite
Fire point = 170˚C The fire point is the temperature at which lubricant combustion will be sustained
Typical Dimension (L x W x H) mm
1590 x 900 x 1750 (without enclosure)
1700 x 950 x 1525
Weight
3100 kg (Cu); 3400 kg (Al)
3190 kg (Cu)
Ventilation
The current TNB substation ventilation is sufficient based on CFD study
Normal ventilation.
Repair
The replacement of a winding can be done on site
The replacement of a winding can only be done in the factory
Maintenance
CBM
CBM
11
394
Substation Design Manual
11.3.3. Synthetic Ester Bio-Degradable Oil Immersed Transformer Synthetic ester oils have been used in distribution transformers since 1970s in the Europe with no reported problems. For power transformer, the synthetic ester oil has been used in 238 kV power transformer located in Sweden. Synthetic ester oil being completely biodegradable makes it more environmentally friendly and thus harmless to marine life. It is typically manufactured from compounds which are largely sourced from vegetables and it has proved to be of very low toxicity. In certain cases it has been shown to be many times less toxic than highly refined petroleum oil. It has a very high flash point of 310°C and an auto-ignition temperature of 435°C, makes it less flammable and suitable for use in fire hazards environment. The dielectric strength of synthetic ester oil is less affected by moisture than mineral oil. Under normal transformer loading, synthetic ester oil can retain higher moister content as compared to mineral oil and therefore allow more migration of moisture from paper insulation into the oil. This “drying” property can contribute to preserve cellulose life. Furthermore, synthetic ester is highly stable towards oxidation and the by-products as the result of aging of synthetic ester oils are less aggressive than mineral oil and hence less harmful to paper insulation. This property of synthetic ester oils makes it suitable for use in a free breathing transformer. However, the synthetic ester oil has slightly higher viscosity as compared to the mineral oil. This is a disadvantage for efficient cooling and during impregnation process. In addition, the dielectric strength of synthetic ester impregnated paper against rms and impulse breakdown voltage is relatively lower compared to the mineral oil. However, these disadvantages can be remedied through improved design clearance and modification on the cooling fins as well as through longer impregnation under vacuum during manufacturing. DGA can be still used as a condition assessment tool for synthetic ester oil, but the diagnosis criteria and interpretation need to be adjusted.
11
New Technology
395
Table 11-5: Technical Comparison between Synthetic Ester with Other Fluids Fluids/ Criteria
Mineral Oil
Silicone Oil
Synthetic Ester
Natural Ester
BDV (kV) Typical Value
55
50
70
70
Viscosity (Typical Value)
9.24
40
28
33
Design, Manufacturing and Operational
-
Needs modification on cooling fins
Needs modification on cooling fins
Prone to Ageing.
Safety & Fire Classification
O
K3
K3
K2
Environmental & Health
Non-Bio Effect to Health
Non-Bio Effect to Health
Biodegradable No Effect To Health
Biodegradable No Effect To Health
11.4.
RMU CB
11.4.1. Overview The ring main unit with circuit breaker (RMU CB) is RMU with circuit breaker function installed at the outgoing feeders. This tripping of the circuit breaker is controlled by self powered relay. As in a conventional RMU, the incoming feeder still uses load break switch (LBS) and the transformer T-off feeder still uses switch-fuse combination with MV DIN fuse. Features:
Incomer – Load Break Switch Transformer – Switch-Fuse Outgoing – Circuit Breaker Protection – Self Powered Relay
11
396
Substation Design Manual
RMU CB
Figure 11-14: Single Line of RMU CB
11
Figure 11-15: Example of RMU CB (Indkom)
New Technology
397
Figure 11-16: Example of RMU CB (Siemens)
Currently, some RMUs used in TNB have circuit breaker function but only for the transformer T-off feeders. Its tripping function is controlled using time lag fuse. This kind of circuit breaker is usually of the rotating arc type which has very limited number of switching operation at rated short circuit breaking current i.e. 20 kA. Additionally, the integral earth switch in series with this circuit breaker has rated short time withstand current of 2.1 kA, 1 second. Therefore, by design this kind circuit breaker cannot be used for outgoing feeders whereby circuit breaker with more superior performance such as vacuum circuit breaker is required.
11
398
Substation Design Manual
Figure 11-17: Example of RMU with CB for transformer feeder (Clockwise from top: Lucy Sabre VRN2a, Merlin Gerin RN2, Tamco GR1)
11
New Technology
399
11.4.2. Self Powered Relay Self powered relay used in the RMU CB is a numerical relay that has three phase non-directional overcurrent and non directional earth fault protection with selectable inverse time (IDMT) or definite time for low-set and high-set stage. It does not require any auxiliary voltage supply and consequently it can also be used for switchgear without external batteries. It takes its power supply energy from the CT circuits and provides the tripping pulse energy to the circuit breaker. The CTs are installed/mounted on bushings in the cable compartment with fixed mounting brackets. The electrical clearance and voltage stress management are ensured to avoid any partial discharge in the CT and bushing vicinity. The relay is buffered by a battery for feeding the liquid crystal display as well as for memorising fault values and reset of the trip relay. Failure of the battery has no effect on the protective functions of the relay. The battery has a typical service life of more than 10 years. The front portion of the relay is protected by a transparent cover and meets IP54 requirement and hence is suitable for outdoor application.
Figure 11-18: Example of self powered relay (Woodward WIP1)
11.4.3. Configuration of RMU CB As with conventional RMUs, RMU CBs are non-extensible and are available in several configurations to suit network requirement. The notation for the configuration of RMU CB in TNB is given by 3 numerals; first numeral refers to the number of incoming with LBS, second numeral refers to the number of switch-fuse/circuit breaker for transformer T-off feeder and third numeral
11
400
Substation Design Manual
refers to the number of outgoing feeders with circuit breaker controlled by self powered relay. Examples of typical configurations used in TNB are as follow:
RMU CB 101: 1 load break switch + 1 circuit breaker outgoing feeder RMU CB 101M: 1 load break switch + 1 circuit breaker outgoing feeder with energy meter (for border metering) RMU CB 111: 1 load break switch + 1 switch-fuse/circuit breaker + 1 circuit breaker outgoing feeder RMU CB 121: 1 load break switch + 2 switch-fuse/circuit breaker + 1 circuit breaker outgoing feeder RMU CB 112: 1 load break switch + 1 switch-fuse/circuit breaker + 2 circuit breaker outgoing feeder RMU CB 102: 1 load break switch + 2 circuit breaker outgoing feeder RMU CB 122: 1 load break switch + 2 switch-fuse/circuit breaker + 2 circuit breaker outgoing feeder
11.4.4. Advantages of Using RMU CB
SSU
Improved fault sectionalising capability Reduce the time to find the failures and expedite the restoration of supply Reduce the number of effected customers in tripping especially on long feeder and worse performance feeder (WPF). This is because faults occurring downstream of RMU CB will be cleared by the RMU CB instead of the by the CB at the PPU or SSU further upstream. Hence, SAIDI will be improved.
PMU
Sebelum
a)
Figure 11-19: Single Line Diagram before using RMU CB
11
New Technology
401
SSU
PMU
Selepas
RMU-CB
Figure 11-20: Single Line Diagram after using RMU CB b) Does not require substation building RMU CB can be installed in outdoor P/E substation such as existing outdoor conventional RMU as it has degree of protection IP54. Does not require external LV supply because it uses self-powered relay and hence battery and battery charger are not required Economical due the cost of RMU CB installation is lower than SSU construction complete with VCB panels, battery and battery charger However, SSU construction is more relevant for certain cases. In cases when SCADA facility is required, external voltage supply is required for battery and battery charger (DC system) needed for the motorisation devices, RTU etc. To ensure protection coordination is achieved, selection of substation/placement of RMU CB has to be planned together with State Protection Unit.
Figure 11-21: RMU CB installed in Outdoor Substation
11
402
Substation Design Manual
11.5.
Containerised PPU
11.5.1. Overview The containerised PPU uses GIS-type for both 33 kV and 11 kV switchgears. The advantages of this containerised PPU include:
Suitable for limited land size Components are readily installed at the factory, therefore shortening the construction period as compared to conventional PPU. The typical duration for commissioning of conventional PPU is 12 months whereas the duration for the containerised PPU is 6 months.
However, there are several disadvantages such as:
11
Space limitation for extension Cabin lifespan is shorter than conventional PPU building Aesthetically inferior than conventional PPU building
Figure 11-22: Containerised PPU
New Technology
403
Each Containerised Primary Distribution Substation (CPPU) 33/11 kV 7 2 x 30 MVA consists of: (a) 1 x Pre-fabricated container unit complete with external walkway/platform housing of about 17 panels of metal-clad 2000 A 25 kA 3 s 11 kV Single Bus-bar GIS with non-withdrawal circuit breaker. (b) 1 x Pre-fabricated container unit complete with external walkway/platform housing of about 7 panels of metal-clad 2000 A 25 kA 3 s 33 kV Single Bus-bar GIS with non-withdrawal circuit breaker. (c) 1 x Pre-fabricated container unit complete with external walkway/platform housing 11 kV and 33 kV Relay, Control Panels, Charger and 110 volt DC Battery Banks. The DC Battery Banks are located in a separate room with proper ventilation to eliminate the risk of vaporised battery chemicals which may cause corrosion to the equipment. (d) 1 x Compact substation rated at 11/0.433 kV 500 kVA. (e) 1 x 11 kV 1600A 50 Hz 4 Ohm Neutral Earthing Resistor (NER) complying with ANSI/IEEE Std 32-1972 (Reaffirmed 1990)
11.5.2. Engineering Specification The following engineering specifications are for a conventional and standard Switchgear & Control Room. However, designs incorporating tried and tested alternative space saving technology with equivalent or superior performance and reliability compared to conventional designs are encouraged and preferred.
The CPPU shall have the following features:
8
7
Design, fabricate, supply, install and commission containerised primary distribution substation (CPPU) at PPU Jalan Bukit Gambir, for TNB Distribution Pulau Pinang (Volume i)-Part 1: Instruction To Tenderers (ITT)
11
404
Substation Design Manual
(a) 33 kV switchgear container All 33 kV metal-clad switchgears shall be of Single Bus-bar (SBB) GIS and non-withdrawal type. These switchgears shall be housed separately from the 11 kV panels. The total number of panels shall be 7:4 feeder panels, 2 transformer incomer panels, and 1 bus-section panel. The feeder earth shall be integrated into the feeder panels. Bus-bar earth (LHS & RHS) shall be integrated into the bus-section panel. (b) 11 kV switchgear container All 11 kV metal-clad switchgears shall be of Single Bus-bar (SBB) GIS and non-withdrawal type. The total number of panels shall be 17:2 transformer incomer panels, 1 bus-section panel and 14 feeder panels. The feeder earth shall be integrated into the feeder panels. Bus-bar earth (LHS & RHS) shall be integrated into the bus-section panel. (c) Insulation compartment It is mandatory that all busbars, circuit breaker and the cable termination be in gas compartments. It is also mandatory that the main bus bar and the circuit breaker compartments be segregated. However, the circuit breaker and cable termination compartment can be constructed as one. It is preferred that the CT and PT are installed in air.
8
11
Design, fabricate, supply, install and commission containerised primary distribution substation (CPPU) at PPU Jalan Bukit Gambir, for TNB Distribution Pulau pinang (Volume i)-Part 2c: Technical Specifications (CPPU)
New Technology
405
(d) Circuit breaker rating is as per the following table. Table 11-6: Circuit breaker rating for containerised PPU Type
33 kV 25 kA 3 s
11 kV 25 kA 3 s
1.
Feeder
1250 A
630 A
2.
Incomer from transformer
1250 A
2000 A
3.
Bus section
2000 A
2000 A
(e) Switchgear main bus-bar rating is as per the following table. Table 11-7: Switchgear main bus-bar rating for containerised PPU Type
33 kV 25 kA 3 s
11 kV 25 kA 3 s
1.
Feeder
2000 A
2000 A
2.
Incomer from transformer
2000 A
2000 A
3.
Bus section
2000 A
2000 A
11
406
Substation Design Manual
Appendix Appendix A: Metering Calculations The resistance of a conductor (with a constant cross-sectional area) can be calculated from the equation: 𝑅 = 𝜌×𝑙 𝐴
(1) o
Where, 𝜌 = resistivity of the conductor material (given typically at +20 C) 𝑙 = length of the conductor 𝐴 = cross-sectional area Table A-1: Resistivity and temperature coefficient for copper (Cu) o
o
Material
Resistivity 𝝆 (+20 C)
Resistivity 𝝆 (+75 C)
Copper
0.0178 μΩ·m
0.0216 μΩ·m
Temp. Coefficient 𝜶 –1
0.0039 K o
Table A-2: Resistance per one meter cable length (+75 C) for copper 2
Material
2.5 mm
Copper
0.00865 Ω/m
4 mm
2
0.00541 Ω/m
6 mm
2
0.00360 Ω/m
Using the MV wiring connection in Figure 7-20, the worst case scenario is with o resistance per cable length at +75 C, maximum secondary current 5 Amps flowing in the circuit, CT burden is given as 15 VA, while main and check meter burdens are 1 VA each. The conductor is laid from CT (S1 pin) to the main meter, then through the check meter, and back to CT (S2 pin). Thus the total conductor length is 2 x L, where L is the distance from the meter to the CT. 2 With this information, the maximum allowable distance, L, for a 2.5 mm copper cable can be calculated as follows: Cable burden = 𝑆 = 𝐼 2 𝑅 Total CT burden − meter burden = 𝐼 2 × 𝜌 × 𝑙 𝐴 15VA − 2 × 1VA = (5 Amps)2 × 0.0216 μΩ ∙ m × 1m/2.5mm2 × 2𝐿 13 = 0.432 × 𝐿 𝐿 = 13/0.432 𝐿 = 30.09 m
Appendix
Appendix B: CPPU Bukit Gambir Earthing Calculations
B.1
Introduction
The Bukit Gambir Containerised Primary Distribution Substation (CPPU) has been proposed to be constructed next to the existing P/E Bukit Gambir 2. A consultant has been engaged to design the earthing system for the substation. This earthing design report is concerned with the following work: 1. 2. 3. 4. 5. 6.
Soil resistivity measurements and the derivation of the electrical soil model. Calculation of the current carrying capability of the proposed earth electrode. Calculations of the tolerable touch and step potentials. The calculations of earth resistance touch and step potentials based on IEEE Std.80-2000 routines. Presentation of the proposed earthing design. Validation of the earthing design using a specialist earthing software package.
Calculations carried out are earth resistance, touch and step profiles for the whole substation and the surface potential profile of the surrounding area of the substation.
407
408
Substation Design Manual
B.2
Site Resistivity
B.2.1
Introduction
The soil resistivity measurements were carried out using the Wenner method. The measurements were taken on the actual substation site on 1 December 2010. Two measurements traverses were conducted, as shown in Figure B-1. The traverses were chosen based on the best available land area in order to maximize the spacing and minimize the likely interference from buried metallic objects. Both traverses R1 and R2 were conducted using Wenner spacing of up to 13.5 metres.
R1 R2
Figure B-1: Measurement traverse at substation site
Appendix
B.2.2
Soil Resistivity Measurement Procedure
Soil resistivity testing is the process of measuring a volume of soil to determine the conductivity of the soil. The resulting soil resistivity is expressed in ohm-metre (Ω·m) or ohm-centimetre (Ω·cm). The Wenner 4-point Method is by far the most used test method to measure the resistivity of soil. Other methods do exist, such as the General and Schlumberger methods, however they are infrequently used for earthing design applications and vary only slightly in how the probes are spaced when compared to the Wenner Method. A four-terminal earth tester is required, equipped with four short test rods and connecting leads. The test leads should be checked for continuity and condition prior to use. Before carrying out any testing, checks should be made from cable records or by using above-ground detection equipment, for the location of any buried cables, earth conductors or metal pipe work. These would adversely affect the accuracy of the readings taken, particularly if they are parallel to the measurement traverse. Clearly this will not be an issue at most rural locations. The traverse locations chosen should be preferably be free of long buried metal pipes etc., but if this is not possible the measurement traverse should be as near perpendicular to them as possible. The route chosen should not be close and parallel to the overhead line support or route. As the line supports are earthed, then their close presence and the counterpoise will adversely affect the readings. If the soil resistivity measurement leads are long and in parallel with an overhead line, then an induced voltage may occur in the leads should fault current flow through the overhead line. To avoid this, measurement routes should preferably be at right angles to overhead lines. If they must be in parallel, then a separation of 20 metres or more from the line is preferable and the route oriented such as to be at as near rectangular to the line as possible. Figure B-2 shows the general measurement arrangement. The four earth rods should be driven into the ground in a straight line, at distance “a” metres apart and driven to a depth of “d” metres.
409
410
Substation Design Manual Array Centre X 3a a2
a 2 a
a
a Soil Surface
d Probe
C1
P1
P2
C2
EARTH TESTER
Figure B-2: The Wenner Soil Resistivity Measurement Array
The four earth rods should be connected to the tester, with the outer rods connected to the C-1 and C-2 terminals, and the inner rods to the P-1 and P-2 terminals. When the instrument is switched on, there will be an apparent resistance reading on the meter, which is “R” ohm. The meter should be left on to allow the build in filters to operate and the value after about 30 seconds should be fairly constant. The apparent soil resistivity (ρ) is then given by 2πaR Ω·m. If the value is varying significantly, this may be due to interference, high contact resistance at the test rods, a damaged test lead or the reading being at the lower limit of the instruments measuring capability. If, after investigating the above, the reading is still changing by more than 5%, record a series of ten consecutive readings over an interval of few minutes, calculate the average and then proceed with the rest of the measurements. At least two series of measurements, via traverses perpendicular to one another should be taken, to allow interference and small local variation effects to be balanced out. If any readings were unstable, then additional traverses will be necessary, possibly further away from the site.
Appendix
If the surface soil is very dry, the high contact resistance with the rod will restrict the flow of test current. To overcome this it is recommended that a short steel rod, having a smaller radius than the test rod, is driven into the soil to a depth of 150 mm and removed. A weak solution of saline water is poured into the hole and the test rod driven in. If this does not provide a satisfactory reading, the rod may be driven in a little deeper. A better arrangement is a cluster of three to five rods positioned 250 mm apart and connected together. Rod clusters like this are normally only required at long test (“a”) spacings and would introduce an error if used at small spacings. It is very unusual to require rod depth of more than 0.3 metres and precautions will be required to ensure that third party equipment or cables are not damaged if rods are driven to more than 0.2 metres depth. Their installed depth should never exceed one twentieth of “a”. Software programs are available for carrying out detailed calculations, based upon data from the above readings, to provide a “best-fit”, representative soil model for the area, consisting of a number of vertical and horizontal layers having different resistivity values.
B.2.3
Results
The result of the measurements taken and their corresponding apparent resistivities are shown in Table B-3. Table B-3: Soil resistivity measurement data Spacing (m) 1
R1 (Ω) 21.1
ρ(Ω) 132.59
R2 (m) 20
ρ(Ω·m) 125.68
1.5
14.43
136.02
13.96
131.59
2
10.96
137.75
10.07
126.56
3
6.52
122.92
7.27
137.05
4.5
4.55
128.66
4.59
129.80
6
3.370
127.06
3.4
128.19
9
2.480
140.26
2.3
130.08
13.5
1.609
136.50
1.593
135.14
411
412
Substation Design Manual
The plot of apparent resistivity of each traverse against inter-electrode spacing is shown in Figure B-3.
Figure B-3: Plot of apparent resistivity against measurements spacing A specialist earthing software packaging is used to derive the electrical soil model for the measurements data acquired. The plot of the measurements data and the derived electrical soil model is shown in Figure B-4 and the derived multilayer electrical soil resistivity model and its uniform equivalent are shown in Table B-4.
Appendix
Legend Measured result curve Compared result curve Soil model curve
1 2 3
RESAP<Bukit Gambir>
Figure B-4: Plot of the soil resistivity measurements data and the derived electrical soil model Table B-4: Derived electrical soil model and its uniform equivalent
B.3
Layer
Resistivity (Ω·m)
Thickness (m)
Top
130.6
13.4
Bottom
146.0
∞
Uniform equivalent
132.8
∞
Conductor Sizing
The earth electrodes will have to be able to conduct a current of 25 kA magnitude for 3 seconds. The following routine, from IEEE Std.80-2000, is used to calculate the minimum electrode size for the given requirement.
413
414
Substation Design Manual
B.3.1
Input Parameters
I = 25
RMS Current (kA)
Tm = 450
Maximum Allowable Temperature (Degree Celsius)
Ta = 40
Ambient Temperature (Degree Celsius)
Ko = 242
Ko Factor (Table 1, pg42 IEEE Std.80)
αr = 0.00381
Thermal Coefficient of Resistivity at Reference Temperature (Table 1, pg42 IEEE Std.80)
ρr = 1.7774
The Resistivity of the Earth Conductor at Reference Temperature (Ω·m) (Table 1, pg42 IEEE Std.80)
tc = 3
Time of Current Flow (s)
TCAP = 3.422 Thermal Capacity Factor (Table 1, pg42 IEEE Std.80) Equation (minimum cross-sectional area, Ac) I 𝐴𝐶 ∶= −4 𝑇𝐶𝐴𝑃 ∙ 10 𝐾 + 𝑇𝑚 ∙ ln 𝑜 𝑡𝑐 ∙ 𝛼𝑟 ∙ ρ𝑟 𝐾𝑜 + 𝑇𝑎 B.3.2
Results
The minimum allowable conductor cross-sectional area is calculated to be 2 203.31 mm . In the present work, the dimension of the earth electrode to be 2 used in 50 mm x 6 mm (cross-sectional area of 300 mm )
B.4
Tolerable Touch and Step Voltages
The tolerable touch and step voltages are calculated using the IEEE Std.802000 routines. B.4.1
Input Parameters
ts = 0.5
Duration of shock in seconds
ρ = 132.8
Soil resistivity in Ω·m
ρs = 3000.0 Surface layer resistivity in Ω·m (Crushed rock) hs = 0.15
Surface layer thickness in m (Crushed rock)
Appendix
B.4.2
Results
Surface layer resistivity derating factor, ρ ρ𝑠 𝐶𝑠 ∶= 1 − 2 ∙ 𝑠 + 0.09 0.09 1 −
(Eq 27 pg 23 IEEE Std.80) 𝐶𝑠 = 0.78 Tolerable touch voltage for human with 50 kg body weight in V (no footwear), 𝐸𝑡𝑜𝑢𝑐 50 ∶= 1000 + 1.5𝐶𝑠 ∙ ρ𝑠
0.116 𝑡𝑠 (Eq 32 pg 27 IEEE Std.80)
𝐸𝑡𝑜𝑢𝑐 50 = 739.45 V Tolerable step voltage for human with 50 kg body weight in V (no footwear), 𝐸𝑠𝑡𝑒𝑝 50 ∶= 1000 + 6𝐶𝑠 ∙ ρ𝑠
0.116 𝑡𝑠 (Eq 29 pg27 IEEE Std.80)
𝐸𝑠𝑡𝑒𝑝 50 = 2466.0 V
B.5
Earthing Design
The proposed substation earthing design is shown in the Conclusions and Recommendations (Section B.10). The earthing system is designed to control the touch and step potentials, and to link the earth electrodes to the aboveground metallic equipment and any lighting protection system employed. The fence of the substation is designed to be separately earthed from the main earthing system of the substation. For a separately earthed fence, any equipment earthed to the main substation earth will need to have a minimum of 2 metre separation distance to the fence (and any metallic object connected to the fence earth). Also, to protect against touch and step potential hazards, the entire substation will need to be covered with an insulation layer; the minimum being crushed rock.
415
416
Substation Design Manual
The main parameters of the design are shown on Table B-5 below. Table B-5: Earthing design parameters
B.6
2
Substation earthing area
448.2 m
Size of earth electrode
50 x 6 mm (300 mm )
Diameter of rod
16 mm
Length of earth electrode
209.3 m
Length of each rod
5.4 m (3 x 1.8 m)
2
Number of rods
17
Total lengths of rods
91.8 m
Total buried lengths of rods and electrodes
301.1 m
Depth of buried electrodes
0.3 m
Thickness of crushed rock layer
0.15 m
Earth Resistance Calculations
The earth resistance of the substation is calculated based on the IEEE Std.802000 routine. B.6.1
Input Parameters
ρ = 132.8
Soil resistivity (average value taken from measurement) in Ω·m
Lc = 301.1
Total length of all connected grid conductors in m
d1 = 0.036
Diameter of grid conductor in m
b = 0.016
Diameter of earthing rod in m
nR = 17
Number of earth rods placed in area A
Lr = 5.4
Average length of a earth rod in m
h = 0.3
Depth of grid burial in m
a' = (𝑑1 ∙ ) sqrt(a·2h) for conductors buried at depth h, where a is the conductor radius A = 448.2
Area covered by grid
k1 = 1.10
Constant related to the geometry of the system
k2 = 4.8
Constant related to the geometry of the system
Appendix
B.6.2
Results
Resistance of grid conductors, 𝑅1 ∶=
ρ 2𝐿𝑐 𝑘1 ∙ 𝐿𝑐 In + − 𝑘2 ′ 𝜋𝐿𝑐 𝑎 𝐴 (Eq 54 pg 66 IEEE Std.80)
𝑅1 = 2.739 Ω Resistance of all earth rods, 𝑅2 ∶=
ρ 2𝜋. 𝑛𝑅 . 𝐿𝑟
In
4𝐿𝑟 𝑏
−1+
2𝑘1 ∙ 𝐿𝑟 𝐴
𝑛𝑅 − 1
2
(Eq 55 pg 66 IEEE Std.80) 𝑅2 = 2.689 Ω Mutual resistance between the group of grid conductors and group of earth rods, 𝑅𝑚 ∶=
ρ 2𝐿𝑐 𝑘1 ∙ 𝐿𝑐 In + − 𝑘2 + 1 𝜋𝐿𝑐 𝐿𝑟 𝐴 (Eq 56 pg 66 IEEE Std.80)
𝑅𝑚 = 2.325 Ω Total grid resistance, 𝑅𝑔 ∶=
2 𝑅1 𝑅2 − 𝑅𝑚 𝑅1 + 𝑅2 − 2𝑅𝑚
(Eq 53 pg 66 IEEE Std.80) 𝑅𝑔 = 2.519 Ω
417
418
Substation Design Manual
B.7
Calculated Touch (Mesh) Voltage for the Earthing Design
The touch (mesh) voltage is calculated based on the IEEE Std.80-2000 method. B.7.1
Input Parameters
H = 0.3
Depth of grid burial in m
D=6
Spacing between parallel conductors in m
d = 0.036
Diameter of grid conductor in m
ρ = 132.8
Soil resistivity encountered by grid conductors buried in depth h in Ω·m
n=3
Number of parallel conductors in one direction
Lc = 209.3
Total length of horizontal electrode in m
LR = 91.8
Total length of rods in m
IG = 1600
Net fault current in A
LM = 301.1
Effective buried length, where LM := Lc + LR
B.7.1
Results
Corrective weighting factor that adjust the effect of inner conductors on the corner mesh: 𝐾′𝑖𝑖 ∶=
1 2∙𝑛
2 𝑛
(Eq 82 pg 93 IEEE Std.80) 𝐾′𝑖𝑖 = 0.303 𝐾𝑖𝑖 = 1 Note: For grids with earth rods along the perimeter, or for grids with earth rods in the grid corners, as well as both along the perimeter and throughout the grid area, Kii = 1
Appendix
Corrective factor for grid geometry: 𝐾𝑖 ∶= 0.644 + 0.148 ∙ 𝑛 (Eq 89 pg 94 IEEE Std.80) 𝐾𝑖 = 1.088 Corrective weighing factor that emphasises the effects of the grid depth: 𝐾 ∶= 1 +
𝑜
𝑜 = 1 m (grid reference depth) (Eq 83 pg 93 IEEE Std.80) 𝐾 = 1.14 Spacing factor for mesh voltage: 𝐾𝑚 ∶=
1 𝐷2 𝐷 + 2 · In + 2𝜋 16 ∙ 𝐷 8𝑑 ∙ 𝐷
2
−
𝐾𝑖𝑖 8 + + In 4𝑑 𝐾 𝜋 2𝑛 − 1 (Eq 81 pg 93 IEEE Std.80)
𝐾𝑚 = 0.54 Mesh voltage at the centre of the corner mesh, V: 𝐸𝑚 ∶=
ρ ∙ 𝐾𝑚 ∙ 𝐾𝑖 ∙ 𝐼𝐺 𝐿𝑀 (Eq 80 pg 91 IEEE Std.80)
𝐸𝑚 = 415.0 V The mesh voltage is calculated to be lower than the allowable touch voltage limit calculated in Section B.4.2, which is 739.45 V.
419
420
Substation Design Manual
B.8
Calculated Step Voltage for the Earthing Design
The step voltage is calculated based on the IEEE Std.80-2000 method. B.8.1
Input Parameters
H = 0.3
Depth of grid buried in m
D=6
Spacing between parallel conductors in m
ρ = 132.8
Soil resistivity encountered by grid conductors buried in depth h in Ω·m
n=3
Number of parallel conductors in one direction
IG = 1600
Net fault current in A
Lc = 209.3
Total length of horizontal electrode in m
LR = 91.8
Total length of rod in m
B.8.2
Results
The effective buried length of conductors: 𝐿𝑠 ∶= 0.75 · 𝐿𝑐 + 0.85 · 𝐿𝑅 (Eq 93 pg 94 IEEE Std.80) Spacing factor for step voltage: 𝐾𝑠 ∶=
1 1 1 1 + + 1 − 0.5𝑛−2 𝜋 2· 𝐷+ 𝐷 (Eq 94 pg 94 IEEE Std.80)
𝐾𝑠 = 0.608 Corrective factor for grid geometry: 𝐾𝑖 ∶= 0.644 + 0.148 · 𝑛 (Eq 89 pg 94 IEEE Std.80) 𝐾𝑖 = 1.088
Appendix
Step voltage between a point above the outer corner of the grid and a point 1 metre diagonally outside the grid: 𝐸𝑠 ∶=
ρ · 𝐾𝑠 · 𝐾𝑖 · 𝐼𝐺 𝐿𝑠 (Eq 92 pg 94 IEEE Std.80)
𝐸𝑠 = 597.67 V The step voltage is calculated to be lower than the allowable limit, 2466 V, as calculated in Section B.4.2.
B.9
Computer Simulations
The designed earthing system is simulated in a specialist earthing software package to calculate and verify the design parameters. The layout of the modelled earth grid is shown in Figure B-5.
Figure B-5: Earth grid layout for CPPU Bukit Gambir
421
422
Substation Design Manual
B.9.1
Earth Resistant Calculation
The earth resistance of the modelled earth grid has been calculated by the software to be 2.5126 Ω. This value is close to that calculated using the IEEE Std.80-2000 routine shown in Section B.5. The main reason for the slight difference in the results is that the software takes into account the multilayered electrical soil model, whilst the calculations in Section B.5 only utilise the uniform equivalent soil model. The calculations by the software also show that the earth resistance is lower than 5 Ω, which complies with TNB’s requirement. B.9.2
Touch Potential Calculation
The touch potentials are calculated for the whole substation, assuming a net single-phase-to-earth fault current of 1600 A. The touch potential plot is shown in Figure B-6. The minimum touch potential threshold is set at 739.45 V, which is the calculated allowable touch potential limit.
Figure B-6: Touch potential plot for CPPU Bukit Gambir Figure B-6 shows that the touch potentials in the areas where the equipment will be placed do not exceed the allowable limit.
Appendix
For the purpose of calculating touch potentials for different EPR magnitudes, the touch potential plot with respect to the percentage of EPR is produced and is shown in Figure B-7.
Figure B-7: Touch potential plot for CPPU Bukit Gambir (% of EPR)
423
424
Substation Design Manual
B.9.3
Step Potential Calculations
The step potentials are calculated for the whole substation. The step potential plot is shown in Figure B-8, which shows the step potential in the substation as percentages to the substation’s EPR.
Figure B-8: Step potential plot for CPPU Bukit Gambir (% of EPR) As shown in Figure B-8, the maximum step potential that can be experienced in and around the substation is 16.61% of the substation’s EPR. Assuming a net single-phase-to-earth fault current of 1600 A and an EPR of 4020.16 V, the maximum step voltage which can be experienced in and around the substation is therefore 667.75 V, which is smaller than the calculated allowable limit of 2466 V (Section B.4.2). The substation is therefore safe against step potential hazards. B.9.4
Surface Potential Calculations
The surface potentials in and around the substation are calculated as a percentage of the EPR. The resulting contour plot is shown in Figure B-9.
Appendix SINGLE-ELECTRODE/SCALAR POTENTIALS [ID: BUKIT GAMBIR 3] LEGEND MAXIMUM VALUE: 98.28767 MINIMUM VALUE: 7.980539
150
100
Y AXIS (METERS)
LEVEL 3 (60,000)
50
0 LEVEL 2 (25,000)
-50
LEVEL 1 (15,000)
-100 -50
0
50
100
X AXIS (METERS) Potential Profile (% reference PR)
Figure B-9: Surface potential profile for CPPU Bukit Gambir (% of EPR) Figure B-9 shows that surface potentials of up to 15% of the EPR can be experienced up to a distance of 50 m from the edge of the substation earth grid, as shown by contour Level 1. For an EPR of 4020.16 V, the surface potential at this distance is 603.0 V.
B.10
Conclusions and Recommendations
B.10.1
Conclusions
The earthing design for CPPU Bukit Gambir has been produced. The earthing resistance of the substation is calculated to be lower than 5 Ω and the simulations have shown that the design is adequate for handling touch and step potentials for a net single-phase-to-earth fault current of 1600 A.
425
426
Substation Design Manual
Conservative assumptions have been used in the design, where the calculations have not considered the parallel paths of the fault current. During a single-phase-to-earth fault a significant portion of the fault current will flow back to the source via the cable sheath, thus reducing the fault current flowing to earth. This will result in the substation attaining a lower EPR, touch and step potentials than that calculated.
B.10.2
Recommendations
1.
Install the earthing system as shown in Figure B-10.
2.
Cover the whole substation area with insulating material, e.g. crushed rock.
3.
The fence has been designed to be separately earthed from the substation. It is therefore very important to maintain a minimum separation distance of 2 m between metallic objects connected to main substation earth and the fence. These may be in the form of metallic lamp posts and control panels.
4.
The substation has a large prospective EPR which exceeds the ITU limit of 430 V. Precautions will need to be taken against services coming in and going out of the substation, e.g. water rains, LV supplies and telecommunication lines.
5.
For an EPR of 4020.16 V, sufficient potentials up to 603 V can be expected up to 50 m from the substation earth grid. The impact of this high magnitude surface potential in the surrounding areas of the substation will need to be assessed by TNB.
6.
TNB to investigate the suitability of bonding the earthing of CPPU Bukit Gambir to the earthing system of the adjoining P/E Bukit Gambir 2. This will result in a reduction of the overall earth resistance and EPR, but other issues like the possibility of transferred potentials via distribution cable sheaths will need to be considered.
Appendix
Notes: 1. 2. 3. 4. 5. 6. 7.
Conductor for earth Grid is 50 mm x 6 mm copper tape, to be buried at 300 mm below surface level. Base of structures and equipment to be connected to earth grid using 50 mm x 6 mm copper tapes. Connection between copper tapes is by brazing. Earth rod diameter is 16 mm, 3 x 1.8 m long. Connection between electrodes and rods to be carried out in earth pits. Substation area to be covered with crushed rock, 150 mm thick. Minimum 2 m separation required between fence and any earthed equipment.
Figure B-10: Earth grid layout for CPPU Bukit Gambir
427
428
Substation Design Manual
Appendix C: IP – Ingress Protection Ratings Ingress Protection (IP) ratings are developed by the European Committee for Electro Technical Standardization (CENELEC) (NEMA IEC 60529 Degrees of Protection Provided by Enclosures – IP Code), specifying the environmental protection the enclosure provides. The IP rating normally has two numbers: 1. 2.
Protection from solid objects or materials Protection from liquids (water) IP
3
5
Code Letters First Characteristic numeral Second Characteristic numeral
Example – IP35 With the IP rating IP35:
3 – describes the level of protection from solid objects; in this rating, enclosure protects from solid objects of 2.5 mm diameter – e.g. a tool such as a screwdriver. 5 – describes the level of protection from liquids; in this rating, enclosure protects against low pressure jets of water from all directions.
An "X" can use for one of the digits if there is only one class of protection, i.e. IPX1 which addresses protection against vertically falling drops of water e.g. condensation.
Appendix First characteristic numeral Protection against solid foreign objects I.P
X
Tests Protection unspecified (untested)
0
Non protection
1
Full penetration of 50 mm diameter of sphere not allowed. Contact with hazardous parts not permitted
Back of hand
2
Full penetration of 12.5 mm diameter of sphere not allowed. The jointed test finger shall have adequate clearance from hazardous parts
Finger
3
The access probe of 2.5 mm diameter shall not penetrate
Tool
4
The access probe of 1 mm diameter shall not penetrate
Wire
5
Example
Degree of protection for people against access to hazardous parts with:
Limited ingress of dust permitted (no harmful deposit)
Non-protected
Dust protected Wire
6
No ingress of dust
Dust tight
429
430
Substation Design Manual
I.P
X
Second characteristic numeral Protection against harmful ingress of water Example Tests Protection unspecified (untested)
Degree of protection from water -
0
Non protection
1
Protected against vertically falling drops of water
Vertically dripping
2
Protected against vertically falling drops of water with enclosure tilted 15˚ from the vertical.
Dripping up to 15˚ form the vertical
3
Protected against sprays to 60˚ from the vertical.
Limited spraying
4
Protected against water splashed from all directions – limited ingress permitted
Splashing from all directions
5
Protected against low pressure jets of water from all directions – limited ingress permitted
Hosing jets from all directions
6
Protected against strong jets of water e.g. for use on ship decks – limited ingress permitted
Strong hosing jets from all directions
7
Protected against the effects of immersion between 150 mm and 1 m
Temporary immersion
8
Protected against continuous submersion at a specified depth.
Continuous immersion
Non-protected
Appendix
List of Abbreviations ABC
Aerial bundled cables
AC
Alternating Current
AHJ
Authority Having Jurisdiction
AIS
Air Insulated Switchgear
Al
Aluminium
ALF
Accuracy Limit Factor
ASME
American Society of Mechanical Engineers
ASTM
American Society for Testing and Materials
ATS
Automatic Transfer Switch
AVR
Automatic Voltage Regulator
AWG
American Wire Gauge
BS
British Standards
CB
Circuit Breaker
CDG
Circular Disk Gear
CPPU
Containerised Primary Distribution Substation
CRP
Control & Relay Panels
CSU
Compact Substation Units
CT
Current Transformer
CTC
Continuous Transposed Cable
Cu
Cuprum
DC
Direct Current
DID
Drainage and Irrigation Department
DIN DITCM
German Institute for Standardization /Deutches Institut fur Normung Design-Installation-Testing-Commissioning-Maintenance
DMS
Distribution Management Systems
DNP
Distributed Network Protocol
DOE
Department Of Environment
DPC
Damp-Proof Course
EDO
Expulsion Drop-Out
EFI
Earth Fault Indicator
431
432
Substation Design Manual ELCB
Earth Leakage Circuit Breaker
EMF
Electromagnetic Field
ENGR
Engineering
EPA
Environmental Protection Agency
EPR
Earth Potential Rise
ESAH
Electricity Supply Application Handbook
FHA
Functional Hazard Assessment
FM
Factory Mutual
FOP
Fall-of-Potential
FP
Feeder Pillar
G.I Pipe
Galvanized Iron Pipe
GIS
Gas Insulated Switchgear
GPRS
General Packet Radio Service
GWP
Global Warming Potential
HDPE
High Density Polyethylene
HFU
Housing Fuse Unit
HMI
Human Machine Interface
H-Pole
Pole Mounted Substations
HRC
High Rupture Capacity
HV
High Voltage
HX RTC
HX Remote Terminal Controller
ICCP
Inter-Control Centre Protocol
IEC
International Electrotechnical Commission
IED
Intelligent Electronic Device
IEEE
Institute of Electrical and Electronic Engineers
IOM
Interconnection Operation Manual
IP
Ingress Protection
ISO
International Organization for Standardization
LBS
Load Break Switch
LCP
Local control panel
LFI
Line Fault Indicator
LHS
Left Hand Side
LILO
Loop-in, loop-out
LPDC
Loss Prevention Certification Boards
Appendix LV
Low Voltage
LVAC
Low Voltage AC
M&E MCB MDPE
Management and Engineering Miniature Circuit Breaker Medium Density Polyethylene
MDU
Motor Drive Unit
MSB
Main Switch Board
MTB
Meter Test Box
MV
Medium Voltage
NER
Neutral Earth Resistance
NOAEL
No Observable Adverse Effect Level
NTL
Non-Transferable Load
OCEF
Over Current Earth Fault
OCTC
Off-Circuit Tap Changer
ODP
Ozone depletion potential
OLG
Oil Level Gauge
OLTC
On-Load Tap Changer
PAT
Pencawang Atas Tiang / Pole Mounted Substation
PBPK
Physiologically-based Pharmacokinetic
PE
Pencawang Elektrik / Distribution Substation
PECU
Photoelectric Control Unit
PF
Power Factor
PMU
Pencawang Masuk Utama / Main Intake Substation
PN6
Pressure Nominal 6 – max pressure 6 bar
PPU PRD
Pencawang Pembahagian Utama / Primary Distribution Substation Pressure Relief Device
PSI
Process System Improvement
PT
Potential Transformer
PVC
Polyvinyl Chloride
RC
Reinforced Concrete
RCB
Remote Control Box
RCC REF RHS
Regional Control Centre Restricted Earth Fault Right Hand Side
433
434
Substation Design Manual RMU
Ring Main Unit
RMU CB
Ring Main Unit with Circuit Breaker
RTCC
Remote Transformer Control Cubicle
RTU
Remote Terminal Units
S/S
Stesen Suis / Switching Station
SAIDI
System Average Interruption Duration Index
SAVR
Sesalur Atas Voltan Rendah
SBB
Single Bus-Bar
SBEF
Stand by Earth Fault
SCADA
Supervisory Control And Data Acquisition
SF6
Sulphur hexafluoride
SGP
Sijil Guna Pakai
SILFOS
Silver Copper Phosphorus
SIP
SCADA Interface Panel
SPCC
Spill Prevention Control and Countermeasures
SSU
Stesen Suis Utama / Primary Switching Station
SWA
Steel Wire Armoured
SWG
Standard Wire Gauge
TTB
Test Terminal Block
UL
Underwriter Laboratories
uPVC
Unplasticised Polyvinyl Chloride
VA
Volt-Ampere
VAR
Volt-Ampere Reactive
VCB
Vacuum Circuit Breaker
VDC
Voltage Direct Current
VdS
German fire protection institute/Vertrauen durch Sicherheit
VT
Voltage Transformer
WISP+
Wireless Internet Service Provider
XLPE
Cross-link Polyethylene
Appendix
Glossary Annunciators
An indicator showing remotely whether each of several items is in the required position or state or not, e.g. door signal with automatic doors or lamp indicating any of several abnormal conditions
Bio-degradable
Biodegradation or biotic degradation or biotic decomposition is the chemical dissolution of materials by bacteria or other biological means
Busbar
Low-impedance conductor to which several electric circuits can be connected at separate points
Bushing
Device that enables one or several conductors to pass through a partition such as a wall or a tank, and insulate the conductors from it.
Carcinogenic
Any substance, radionuclide, or radiation that is an agent directly involved in causing cancer
Clearance
Shortest distance in air between two conductive parts
Creepage distance
Shortest distance along the surface of a solid insulating material between two conductive parts
Discrepancy Switch
A switched indicator, with an acknowledgement facility, which shows any discrepancy between the actual and indicated state of the equipment being monitored
Double Busbar Substation
A substation in which the lines and transformers are connected via two busbars by means of selectors
Earth Resistance
The resistance existing between the electrically accessible part of a buried electrode and another point of the earth, which is far away
Heat Shrink
Mechanically expanded extruded plastic tube ordinarily made of nylon or polyolefin, which shrinks when heated in an effort to return to the relaxed diameter it originally had when extruded
Incoming Feeder
In a substation a feeder bay which is normally used to receive power from the system
Interlock
A device used to help prevent a machine from harming its operator or damaging itself by stopping the machine when tripped
Internal Arc
The result of a rapid release of energy due to an arcing fault between phases, neutral or a ground
Magnetostriction
Reversible deformation of a body due to magnetization arising from an applied magnetic field
435
436
Substation Design Manual
Main Busbar
In a double busbar substation, any busbar which is used under normal conditions
Mimic Diagram
An arrangement of symbols representing the current state of switchgear and lines of a substation (network) and which may be updateable and may have control functions
Outgoing Feeder
In a substation a feeder bay which is normally used to transmit power to the system
Photoelectric
Applies to electrical phenomena caused by absorption of photons
Plinth
a usually square block serving as a base; broadly: any of various bases or lower parts
Pole-mounted Substation
An outdoor distribution substation mounted on one or more poles
Premix
Something that is mixed or blended from two or more ingredients or elements before being marketed, used, or mixed further
Relay
Relating to, or having the characteristics of, an auxiliary apparatus put into action by a feeble force but itself capable of exerting greater force, used to control a comparatively powerful machine or appliance
Reserve Busbar
In a double busbar substation, any busbar which is used under abnormal conditions. It is generally less well equipped than a main busbar
Ring Substation
A single busbar substation in which the busbar is formed as a closed loop with only disconnectors in series within the loop
Semaphore
Indication of 'Close' and 'Open' position of circuit breakers, isolators and earth switches shall be incorporated in the mimic diagram
Short Circuit
A low-resistance connection established by accident or intention between two points in an electric circuit. The current tends to flow through the area of low resistance, bypassing the rest of the circuit.
Silmalec
Aluminium alloys containing magnesium and silicon, the two latter ingredients acting as hardeners and can be heat-treated.
Single Busbar Substation
A substation in which the lines and transformers are connected to one busbar only
Soil Resistivity
Function of soil moisture and the concentrations of ionic soluble salts and is considered to be most comprehensive indicator of a soil’s corrosivity
Appendix Spur Connection
Feeder to which subscriber's taps or looped system outlets are connected
Step-down Substation
A transformer substation in which the outgoing power from the transformers is at a lower voltage than the incoming power
Step-up Substation
A transformer substation in which the outgoing power from the transformers is at a higher voltage than the incoming power
Substation
The part of a power system, concentrated in a given place, including mainly the terminations of transmission or distribution lines switchgear and housing and which may also include transformers. It generally includes facilities necessary for system security and control (e.g. the protective devices)
Switching Substation
A substation which includes switchgear and usually busbars, but no power transformers
Switchyard
Typically found in AIS PMU and Outdoor PPU, it contains the air insulated switching installations
Tracking
The progressive degradation of the surface of a solid insulating material by local discharges to form conducting or partially conducting paths
Transducer
A device capable of being actuated by one or more input quantities and of supplying output quantities related to the input quantities, but of different physical nature
Vector Group
Indicates the phase difference between the primary and secondary sides, introduced due to that particular configuration of transformer windings connection
Ventricular Fibrillation
Heart rhythm problem that occurs when the heart beats with rapid, erratic electrical impulses
Viscosity
A measure of the resistance of a fluid which is being deformed by either shear stress or tensile stress.
437
December 2012 Asset Management Department, TNB Distribution Division
1
Chapter 1: Introduction Introduction Background
1 1
i
Objectives Scope of this Manual
3 3
Chapter 2: Substation Design & Configuration
2
Overview Design Philosophy Substation Categories Major Components
6 7 8 10
Electrical Clearance Site Considerations Operation and Maintenance Considerations Safety Considerations
12 13 17 17
Chapter 3: PMU, PPU and 33kV SSU Design
3 4
5
Introduction 18 Pencawang Masuk Utama (PMU) 18 Pencawang Pembahagian Utama (PPU) 26
Mini PPU 34 33kV Primary Switching Station (33kV SSU) 50 Testing and commissioning 54
Chapter 4: P/E, 11kV SSU and S/S Design Introduction 55 Indoor Distribution Substation (Indoor P/E) 60 11kV Primary Switching Station (11kV SSU) 82 Outdoor Distribution Substation (Outdoor P/E) 85
Switching Station (S/S) Compact Substation Unit (CSU) Pole Mounted Substation (PAT) Pole Mounted Substation (PAT) with RMU
93
95 105 125
Chapter 5: Design for Substations with Special Requirements Mobile SSU
6 7
8
130
Flood Prone Areas
153 211 239 252
Feeder Pillar 257 Current Transformer (CT) 264 Potential Transformer (PT) 270
Chapter 7: Secondary Equipment Overview Protection/Protective Relaying Control DC & AC Auxiliary Systems Heater
273 273 284 289 294
DESIGN MANUAL The TNB power distribution network includes medium and low voltage power lines, substations, switching stations and metering system. Proper design and construction of the substations is aimed to ensure a reliable and robust electricity distribution network. This is important in order to achieve optimum system performance, reduce system losses and improve customer satisfaction.
144
Chapter 6: Primary Equipment Transformers Switchgear Neutral Earthing System Medium Voltage Fuse
SUBSTATION
Secondary Wiring
296
Metering
297
Communications
302
Other Secondary Equipment
308
This manual covers the distribution substations and related equipment. The manual is a compilation of various documents, circulars and requirements pertaining to the design and construction of the distribution network.
Chapter 8: SCADA System
9
10
Overview Master System Communication System
320 322 324
Chapter 9: Earthing Overview
330
Earth Connections Above-Ground
334
Earth Connections Below-Ground
353
Chapter 10: Fire Fighting System Overview 363 Fire System Requirements for TNB Substations 364
11
Remote Terminal Unit (RTU) 325 SCADA-ready Substations 329
System Components
372
Chapter 11: New Technology Mobile Equipment 375 Energy Efficient Distribution Transformers 384
Cast Resin and Synthetic Ester RMU CB Containerised PPU
390 395 402
December 2012 Asset Management Department TNB Distribution Division
Substation Design Manual
December 2012
Asset Management Department Distribution Division Tenaga Nasional Berhad Wisma TNB Jalan Timur, Petaling Jaya Selangor
Disclaimer: This Substation Design Manual is a document providing technicians, engineers, and managers of the Distribution Division of Tenaga Nasional Berhad with an understanding of proper substation system design. The information in this document has been prepared in good faith and represents the Asset Management Department’s intentions and opinions at the date of issue. The Asset Management Department may change any information in this document at any time.
ii
Substation Design Manual
Acknowledgement We would like to express our deepest gratitude to the management of the Distribution Division, for giving us the opportunity to develop the TNB Distribution Division’s Substation Design Guide. Special thanks to Hj. Ismail Mohd Din (SGM), Hj. Esmet Sidqie bin A.Muttalib, Young Zaidey bin Yang Ghazali, Sharizal bin Shamuri, Hannah binti Ahmad Rosli and Mohd Khairul Ikram bin Ghazali from Substation Section, Engineering Service Unit, Asset Management Department for their valuable contribution and assistance in developing this manual. Our appreciation goes to Ideris Shamsudin from Pejabat Pengurus Kawasan Petaling Jaya; Tan Siew Hwa from Unit Perancangan dan Pembangunan Sistem; Hj. Muhamad Subian Sukaimy, Dr. Abd Rahman bin Khalid and Zaini Zainal from Protection; Mohd Jaffery Raffles and Sek Yean Ling from SCADA; Noor Adnan Abdul Aziz, Mohd Fatani bin A Rahman, Ahmad Ridhaudin Abdul Razak, Mohd Fauzi bin Mohd Ismail and Ahmad Suhaimi bin Mohamed from Jabatan Perancangan & Pembangunan Aset; Mohd Faris Ariffin from Overhead Section, Engineering Service Unit; Zahari Dollah and Mohammad Khuzairee bin Ibrahim from Unit Perkhidmatan Pengurusan Aset; Mohd Fahami Jaapar and Kamarul Azam Abu Kassim from Unit Perkhidmatan Perjangkaan; and finally Mohd Nazri bin Rahmat and Syamsul Fahrizal bin Samsu from Pengurus Kawasan Kulim. The project team would also like to express our gratitude to Pairolani bin Safari @ Hj Hashim and Govindan Gopal from ILSAS, Bangi. Not forgetting Nurul Azlina Abdul Rahman, Ir. Noradlina Abdullah and Mohd Aizam bin Talib from TNB Research Sdn. Bhd. and Muhamad Faiq Mohd Rozi from MTM Sdn. Bhd. Our appreciation also goes to the Uniten Team, comprising Mohd Zafri Baharuddin, Fareha binti Mohd Zainal, Dr. Noor Miza binti Muhamad Razali, Adzly Anuar, Nadhira binti Mat Nashim, Shahrul Iznan, Nurul Aishah binti Mohd Rosdi, Redia binti Mohd Redzuwan, Kamalambigai A/P Munusamy, Nurulaqilla binti Khamis and Norizzati Shafinaz binti Sabri for their untiring efforts and patience towards the successful completion of this manual. We welcome any feedback and improvement advice that will be useful for future revisions of this manual. Thank you. Ir. Wan Nazmy bin Wan Mahmood General Manager, Engineering Services, Asset Management Department, Distribution Division, TNB.
Substation Design Manual
Foreword VP Distribution Division, Datuk Ir. Baharin Din As Malaysia progresses to achieve Vision 2020, TNB plays a vital role in ensuring sufficient and strategic injection of electricity power is available by the building Transmission Main Intake Substations, Primary Distribution Substations and Distribution stations. With continuous expansion of the distribution network and its ever challenging environment, it is essential that the spirit of “do it right the first time” be instilled among TNB personnel and appointed contractors. Properly designed substations and correct installation of related equipment will ensure reliable and quality power supply, longer equipment lifespan and improved system security as well as safety. From time to time, various technical and engineering circulars and guidelines have been issued to ensure standard practices on substation design, construction and installation are practiced among the states and areas. However, there is a need to compile these guidelines in a form of a practical handbook to be made more available and accessible for easy reference throughout the Distribution Division. TNB Distribution Division through the Distribution Asset Management Department, in collaboration with ILSAS and Universiti Tenaga Nasional, have taken a step forward to develop this manual which incorporates the latest technological changes in substation equipment and design, existing relevant instructions and circulars, as well as approved technical specifications. Therefore, I would like to take this opportunity to congratulate the project team from the Asset Management Department, as well as ILSAS, TNB Research and Universiti Tenaga Nasional, for their impressive effort in developing this useful manual for substation design for the distribution system. Thank you.
iii
iv
Substation Design Manual
Table of Contents Chapter 1:
Introduction ..............................................................................1
1.1.
Background ...................................................................................1
1.2.
Objectives .....................................................................................3
1.3.
Scope of this Manual .....................................................................3
Chapter 2:
Substation Design & Configuration ...........................................6
2.1.
Overview .......................................................................................6
2.2.
Design Philosophy .........................................................................7
2.3.
Substation Categories ....................................................................8
2.4.
Major Components ...................................................................... 10
2.5.
Electrical Clearance ..................................................................... 12
2.6.
Site Considerations ...................................................................... 13
2.7.
Operation and Maintenance Considerations ................................ 17
2.8.
Safety Considerations .................................................................. 17
Chapter 3:
PMU, PPU and 33 kV SSU Design ............................................18
3.1.
Introduction ................................................................................ 18
3.2.
Pencawang Masuk Utama (PMU) ................................................. 18
3.3.
Pencawang Pembahagian Utama (PPU) ....................................... 26
3.4.
Mini PPU ..................................................................................... 34
3.5.
33kV Primary Switching Station (33 kV SSU) ................................. 50
3.6.
Testing and commissioning .......................................................... 54
Chapter 4:
P/E, 11 kV SSU and S/S Design ................................................55
4.1.
Introduction ................................................................................ 55
4.2.
Indoor Distribution Substation (Indoor P/E) ................................. 60
4.3.
11 kV Primary Switching Station (11 kV SSU) ................................ 82
4.4.
Outdoor Distribution Substation (Outdoor P/E) ............................ 85
Substation Design Manual
4.5.
Switching Station / Stesen Suis (S/S) ............................................ 93
4.6.
Compact Substation Unit (CSU) ................................................... 95
4.7.
Pole Mounted Substation (PAT) ................................................. 105
4.8.
Pole Mounted Substation (PAT) with RMU ................................ 125
Chapter 5:
Design for Substations with Special Requirements ............... 130
5.1.
Mobile SSU ............................................................................... 130
5.2.
Flood Prone Areas ..................................................................... 144
Chapter 6:
Primary Equipment .............................................................. 153
6.1.
Transformer .............................................................................. 153
6.2.
Switchgear ................................................................................ 211
6.3.
Neutral Earthing System ............................................................ 239
6.4.
Medium Voltage Fuse ............................................................... 252
6.5.
Feeder Pillar .............................................................................. 257
6.6.
Current Transformer (CT) .......................................................... 264
6.7.
Potential Transformer (PT) ........................................................ 270
Chapter 7:
Secondary Equipment .......................................................... 273
7.1.
Overview .................................................................................. 273
7.2.
Protection/Protective Relaying .................................................. 273
7.3.
Control...................................................................................... 284
7.4.
DC & AC Auxiliary Systems......................................................... 289
7.5.
Heater ...................................................................................... 294
7.6.
Secondary Wiring ...................................................................... 296
7.7.
Metering ................................................................................... 297
7.8.
Communications ....................................................................... 302
7.9.
Other Secondary Equipment ..................................................... 308
v
vi
Substation Design Manual
Chapter 8:
SCADA System ...................................................................... 320
8.1.
Overview ................................................................................... 320
8.2.
Master System .......................................................................... 322
8.3.
Communication System ............................................................. 324
8.4.
Remote Terminal Unit (RTU) ...................................................... 325
8.5.
SCADA-ready Substations .......................................................... 329
Chapter 9:
Earthing ................................................................................ 330
9.1.
Overview ................................................................................... 330
9.2.
Earth Connections Above-Ground .............................................. 334
9.3.
Earth Connections Below-Ground .............................................. 353
Chapter 10: Fire Fighting System .............................................................. 363 10.1.
Overview ................................................................................... 363
10.2.
Fire System Requirements for TNB Substations .......................... 364
10.3.
System Components .................................................................. 372
Chapter 11: New Technology ................................................................... 375 11.1.
Mobile Equipment ..................................................................... 375
11.2.
Energy Efficient Distribution Transformers ................................. 384
11.3.
Cast Resin & Bio-Degradable Oil Immersed Transformers ........... 390
11.4.
RMU CB ..................................................................................... 395
11.5.
Containerised PPU ..................................................................... 402
Appendix ................................................................................................... 406 Appendix A: Metering Calculations ......................................................... 406 Appendix B: CPPU Bukit Gambir Earthing Calculations ............................ 407 Appendix C: IP – Ingress Protection Ratings............................................. 428 List of Abbreviations ................................................................................... 431 Glossary ..................................................................................................... 435
Introduction
Chapter 1: 1.1.
Introduction
Background
Electricity distribution is the delivery of electricity from the transmission network to end users or customers through the distribution network as shown in Figure 1-1. The TNB power distribution network includes medium and low voltage power lines and cables, substations, switching stations and metering system. Typical medium voltage in the network is 11 kV and 33 kV. Some parts of Perak and Johor distribution network consist of 6.6 kV and 22 kV systems; however these are being phased out in stages. Distribution substations consist of equipment such as transformers and circuit breakers, and are interconnected by a network of underground cables and overhead power lines. There are several types of distribution substations which can either be of outdoor or indoor design, and either stand-alone or attached to a building. The functions of a distribution substation may include a combination of the following: (a) To manage the distribution network by switching elements in and out of the system to transmit power from main intake stations or other networks to load centres and in some cases direct to consumers. (b) To change or transform voltage levels within the distribution network, such as 33kV/11kV and/or 11kV/0.4kV (c) To provide data concerning system parameters (voltage, current flow, power flow) for use in operating the utility system. (d) To isolate faulted section from the healthy sections of the distribution network. (e) To allow an element to be isolated from the rest of the distribution network for maintenance or repair.
1
1
GENERATION
Substation Design Manual
132kV
TRANSMISSION
132kV
275kV
132kV/275kV
275kV/132kV
275kV/132kV
PMU 132kV/11kV
PMU 132kV/33kV
PPU
DISTRIBUTION
2
PPU 33kV/11kV 33kV SSU
11kV SSU
S/S
P/E 11kV/0.4kV
CUSTOMER
1
Residential
Commercial
Figure 1-1: Electricity supply network
Industrial
Introduction
1.2.
Objectives
Proper design and construction of the substations is aimed to ensure a reliable and robust electricity distribution network. This is important in order to achieve optimum system performance, reduce system losses and improve customer satisfaction.
1.3.
Scope of this Manual
This manual covers the distribution substations and related equipment. The manual is a compilation of various documents, circulars and requirements pertaining to the design and construction of the distribution network. Topics in this manual are arranged according to the following chapters: Chapter 2: Substation Design & Configuration This chapter provides an overview of the different types of substations, along with their design philosophy and type selection criteria. Chapter 3: PMU, PPU and 33 kV SSU Design This chapter covers main design criteria for Main Intake Substation/Pencawang Masuk Utama (PMU), Primary Distribution Substation/Pencawang Pembahagian Utama (PPU), and 33 kV Primary Switching Station/Stesen Suis Utama (33 kV SSU). Chapter 4: P/E, 11 kV SSU and S/S Design This chapter details out the main design criteria for all distribution substations and switching stations of 11 kV and below. These are the indoor and outdoor substations/pencawang elektrik (P/E), compact substation units (CSU), pole mounted substations (H-pole), 11 kV primary switching station/stesen suis utama (11 kV SSU) and switching stations/stesen suis (S/S). Chapter 5: Design for Substations with Special Requirements This chapter covers substations under special requirements such as Mobile SSU for rapid deployment situations and mitigation construction methods for substations located in flood prone areas.
3
1
1
4
Substation Design Manual
Chapter 6: Primary Equipment This chapter describes the substation primary equipment such as transformers, switchgears, Neutral Earthing Resistors (NER) and feeder pillars. Chapter 7: Secondary Equipment This chapter explains secondary equipment that covers the functions of protection, metering and communication. These include instruments, relays, control panels, DC and LV supply and optical fibres. Chapter 8: SCADA System This chapter briefly explains the structure of the SCADA system for remote monitoring and control of geographically dispersed assets to Regional Control Centres. This chapter also explains the main functions and equipment related to this system. Chapter 9: Earthing The chapter primarily covers the objectives of good earthing design, the earth connections above and below ground levels and the earthing components used. Chapter 10: Fire Fighting System Fire fighting system requirements for TNB substations are discussed in this chapter. The fire fighting system components are also introduced. Chapter 11: New Technology The chapter covers several new technologies which are introduced to the distribution system in order to increase system reliability, security and efficiency. The chapter covers mobile equipment, RMU circuit breaker and containerised PPU.
Introduction
This manual is a mandatory guide for distribution substation design requirements in any Region and Area (kawasan). Additional supporting documents to accompany this manual include: 1.
Electricity Supply Application Handbook (ESAH), where dimensions of the various types of built up P/E design is detailed out.
2.
Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian, for schematic drawings of standard PPU design.
3.
Distribution Planning Guidelines, where basic principles and general policies of distribution system planning are outlined.
4.
Underground Cable System Design Manual, for interconnecting cable specifications.
5.
Penyambungan Pengalir Kabel Bawah Tanah, as a guideline for conductor connection techniques.
6.
Capacitor Bank Guideline, for information on capacitor banks inside substations.
7.
For testing and maintenance methods, please refer to the latest editions of the following documents: o o o
Transformer Maintenance Manual Switchgear Maintenance Manual Cable Maintenance Manual
5
1
6
2
Substation Design Manual
Chapter 2: Substation Design & Configuration 2.1.
Overview
Substation design depends on many factors, either from geographical, technical, regulatory, or demographic requirements which determine the type of substation to be constructed. The main issues in determining the design of a particular substation are reliability and cost. A good design attempts to strike a balance between these two, to achieve sufficient reliability at the optimum cost. Sufficient land area is required for installation of equipment with necessary clearances for electrical safety and sufficient access to perform operation and maintenance of components such as transformers and circuit breakers. In dense urban areas where land is costly, gas insulated switchgear may save money overall. The design should also allow easy expansion of the station, if required. Environmental effects of the substation must be considered, such as drainage, noise, water supply and road traffic. Earthing must be calculated to protect equipment in case of a short circuit in the distribution system. Ideally, the substation site must be reasonably central to the distribution area to be served.
Introduction
2.2.
Design Philosophy
TNB Distribution Division substations are designed with objectives to ensure: (a) Correct engineering practice (b) Compliance with acts and regulations (c) Availability, reliability and security of supply (d) Optimisation of cost – Using TNB Engineering economics model (Financial Evaluation Template from MV Planning Guideline) (e) Ease of construction, operation and maintenance of substations (f) Safety of public, personnel and equipment (g) Customer requirements are fulfilled (h) Flexibility to meet changing demand (i)
Adoption of green initiatives
(j) Consideration of climate and environmental change (k) Positive corporate image (l)
7
Prolonged equipment life through life cycle and risk assessment
2
8
Substation Design Manual
2.3. 2
Substation Categories
Substations are categorised according to the voltages they handle and whether the substation performs voltage transformations or only switching functions.
2.3.1.
Transmission Main Intake / Pencawang Masuk Utama (PMU)
Transmission Main Intake Substation / Pencawang Masuk Utama (PMU) is the interconnection point of 132 kV or 275 kV to the distribution network. The typical transmission capacity and voltage transformation provided at the PMU are as follows:
132/33kV, 2 x 90 MVA 132/11kV, 2 x 30 MVA
Other voltage transformations are also catered for based on special site requirements.
2.3.2.
Primary Distribution Substation / Pencawang Pembahagian Utama (PPU)
Primary Distribution Substation is normally applicable to 33 kV and 22 kV interconnecting networks with 11 kV networks. It provides capacity injection into 11 kV network through a standardized transformation of 33/11 kV or 22/11 kV. Typical transformer capacities used in PPU are 7.5 MVA, 15 MVA and 30 MVA.
2.3.3.
Primary Switching Stations / Stesen Suis Utama (SSU)
Primary Switching Stations / Stesen Suis Utama (SSU) are stations with circuit breakers, established to serve the following function:-.
To supply a dedicated bulk consumer at 33 kV, 22 kV or 11 kV. To provide bulk capacity injection or transfer from a PMU/PPU to a load centre for further localized distribution.
This manual will detail out the 33 kV SSU and 11 kV SSU.
Introduction
2.3.4.
Distribution Substation / Pencawang Elektrik (P/E)
A distribution substation / Pencawang Elektrik (P/E) is a combination of switching, controlling, and voltage step-down equipment arranged to reduce medium voltage (MV) of 33 kV, 22 kV and 11 kV to low voltage (LV) for residential, commercial, and industrial loads. Typical capacity ratings are 1000 kVA, 750 kVA, 500 kVA, 300 kVA and 100 kVA. The design of these substations varies widely according to network requirement. Some distribution substations would include a dedicated customer substation with a metering room. This substation would be similar to the typical distribution substation except that all of its capacity would be reserved for the service of one customer. Coordination with the customer is of primary importance in determining the technical requirements. Standardized M & E designs of 11/0.4 kV substations are available in the latest version of the Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian, TNB.
2.3.5.
9
Switching Stations / Stesen Suis (S/S)
Switching Stations / Stesen Suis (S/S) are stations with RMU or VCB which normally do not contain transformers and operates only at a single voltage level to distribute to feeders.
2
10
Substation Design Manual
2.4. 2
Major Components
The specifications for major components are determined by the parameters of the power system and their expected functionality when in operation. The following are some functional descriptions of major components in a substation. Selection of equipment requires the utmost consideration. Cost, schedule, and performance penalties may be incurred as a result of improper selection. Other associated subsystems in the electrical installation of substations include protection, metering, control and communication systems, earthing system, fire fighting system, lighting system and security system.
2.4.1.
Transformers step up or step down voltages and transfer power to different voltage levels. Power transformers work at the MV level and above. Distribution transformers function to step down to low voltage distribution voltages. Local transformers are distribution transformers that provide supply locally to the substation only.
2.4.2.
Transformer
Switchgear
Switchgear is a switching device used to control, protect and isolate electrical network. It may comprise of disconnectors, switches, fuses or circuit breakers. Typically, for MV switchgears, they are compartmentalised and metalenclosed. Configuration may be of single or double busbar system. o A busbar is a strip or bar of copper, brass or aluminium that conducts electricity within a substation. o Busbars connect incoming and outgoing circuits.
Introduction
2.4.3.
Potential Transformers
Potential Transformers (PT) function to step down voltage for measurements, protection and control. They are located on the feeder side of the circuit breaker. There are also known as Voltage Transformers (VT).
2.4.7.
Lightning Arrestors
In overhead installations, lightning arrestors function to discharge overvoltage surges to earth and protect the equipment insulation from lightning surges. They are connected between phase conductor and earth. Located at the end of an incoming line and also near transformer terminals, they form the first line of defence against surges into the substation.
2.4.6.
Disconnector/Isolator
Disconnector/isolators function to provide isolation from live parts for the purpose of maintenance. They can only be operated in off-load condition. They are located inside the switchgear. Separate isolators are used for pole-mounted installations.
2.4.5.
Circuit Breaker
The circuit breaker is a component inside the switchgear. A circuit breaker is an automatically operated electrical switch designed to protect an electrical circuit from damage caused by overload or short circuit. Its basic function is to detect a fault condition and, by interrupting continuity, to immediately discontinue electrical flow. They are located at designated switching points or both ends of protected zones.
2.4.4.
11
Current Transformers
Current Transformers (CT) steps down current for load measurement, protection and control.
2
12
2
Substation Design Manual
2.5.
Electrical Clearance
2.5.1.
Safety Clearance
Safety clearance is the minimum distance to place partitions of safety barriers from normally exposed live parts while working in a substation. The minimum safety clearance is shown in Table 2-1.
2.5.2.
Working Clearance
Working clearance is the minimum safe distance to be observed between normally exposed live parts and any person or tools while working in a substation. The minimum working clearance is shown in Table 2-1.
2.5.3.
Phase Clearance
Phase-to-earth and phase-to-phase clearances should be coordinated to ensure that possible flashovers occur from phase to earth rather than from phase to phase. The minimum phase clearance is shown in Table 2-1. Table 2-1: Minimum phase clearance in millimetres Description
275 kV
132 kV
33 kV
22 kV
11 kV
Safety clearance between earth and the nearest point not at earth potential of an insulator
2440
2440
2440
2440
2440
Safety clearance between earth and the nearest live unscreened conductor
4570
3500
2740
2740
2590
Working clearance between any person or person with tools to earth
3050
2440
1220
1220
914
Phase/Live metal to earth
2082
1270
381
279
203
Phase/Live metal to different phase
2388
1473
432
330
254
Introduction
2.6.
Site Considerations
2.6.1.
General
It is becoming increasingly important to perform initial site investigations prior to the procurement of substation site. The following factors should be evaluated when selecting a substation site: (a) Location of present and future load centre (b) Location of existing and future sources of power (c) Availability of suitable right-of-way and access to site by overhead or underground transmission and distribution circuits (d) Location of existing distribution lines (e) Access roads into the site for heavy equipment under all weather conditions (f) Possible objections regarding appearance or noise (g) Soil resistivity (h) Drainage and soil conditions (i) Cost of earth removal, earth addition, and earthmoving (j) Atmospheric conditions: salt and industrial contamination (k) Cost of cleanup for contaminated soils or buried materials (l) Space for future as well as present use (m) General topographical features of site and immediate neighbouring areas; avoidance of floodplains or wetlands (n) Public safety and public concern; avoidance of schools and playgrounds (o) Security from theft, vandalism, damage and sabotage (p) Total cost including transmission and distribution lines with due consideration of environmental factors (q) Possible adverse effects on neighbouring communications facilities
2.6.2.
Appearance
Appearance is becoming increasingly important to the public. In some areas, zoning regulations and suggestions by local authorities often mean screening, painting, or other measures to improve appearance. The general trend is to locate substations in a way that they are not strikingly visible to the public.
13
2
14
Substation Design Manual
A substation set back from a heavily travelled road may be acceptable with little or no architectural treatment.
2
Substations strategically located facing main roads can be used to place 1 company contact information . Generally, it is better to use complementary rather than contrasting colours. 2 Colouring can be used to blend substation equipment into the background . Lighting in the compound is typically a means to deter vandalism and theft. It also provides safety for crews who may be performing maintenance at night.
2.6.3.
Public Safety
Substations should be safe for people who may have occasion to be near them. The primary means of ensuring public safety at substations is by the erection of a suitable barrier such as a fence. Appropriate warning signs should be posted on the substation’s barrier fence or walls. For each substation site, assess whether standard signs are sufficient. Special bilingual signs or additional signs, such as “No Trespassing” / “Dilarang Masuk”, may be advisable for some areas.
2.6.4.
Effluent
Effluent is water pollution, such as liquid waste or sewage from industrial facilities discharged into surface waters. Upon the failure of a container filled with a pollutant, such as oil in a transformer or oil circuit breaker, no harmful quantity of such pollutant (oil) may be allowed to enter a navigable waterway. For PPU, it is necessary to have a Spill Prevention Control and Countermeasures (SPCC) plan of action for disposing of effluent, should spills or leaks occur. 1
Arahan Naib Presiden (Pembahagian) TNB (Dasar Perkhidmatan dan Amalan Kejuruteraan), Bil. A08/2012, Penceriaan Pencawang Pembahagian Utama dan Pencawang Elektrik Jenis Bangunan TNB. 2 Arahan Naib Presiden (Dasar Perkhidmatan dan Amalan Kejuruteraan), Bil. A02/2010, Penggunaan Warna Cat yang Dibenarkan untuk Dinding Luar Semua Bangunan Pencawang Baru TNB.
Introduction
2.6.5.
Weather
As dependence on the use of electricity grows, it is increasingly important that substations operate more reliably in extremes of weather than in the past. 2.6.5.1.
Rain
Malaysia’s climate experiences an average of 250 centimetres of rain per year. As such, a substation should be designed to be operable under predictable conditions of rainfall. Flood prone areas are to be avoided. Mitigation methods for substations in flood prone areas are explained in Chapter 5.2. Rain can also lead to soil erosion. Areas prone to soil erosion such as steep slopes are to be avoided. 2.6.5.2.
Lightning
Malaysia has among the highest number of lightning strikes per year in the world. Typically, for a tropical country, the keraunic level ranges between 100 to 180 Thunderstorm days per year (based upon the Malaysian Meteorological Office). Lightning can cause transient conditions which can trip circuit breakers and/or damage equipment. Lightning surge arresters are the measure normally employed for pole-mounted substation lightning protection. For substation buildings, shielding is provided by lightning rods. 2.6.5.3.
Humidity
Being in a tropical climate, the equipment must also operate under high humidity conditions. Consideration should be given to install differential thermostat-controlled heating in cabinets such as circuit breaker enclosures where condensation could be a problem. 2.6.5.4.
15
Altitude
Equipment that depends on air for its insulating and cooling medium will have a higher temperature rise and a lower dielectric strength when operated at higher altitudes. Dielectric strength of air, current ratings of conductors
2
16
2
Substation Design Manual
operated in air, and ambient temperatures should be corrected for altitude variation. Applications above normal specified elevation limits are considered special, and the manufacturer should be consulted for a recommendation.
2.6.6.
Other Considerations
2.6.6.1.
Wildlife and Livestock
A substation should be protected from wildlife and livestock. The primary means of protection is the perimeter barrier. This is generally a chain link fence that keeps out larger animals. It may also be necessary to have rodent and/or reptile barriers. Insect screening should be applied where local experience indicates it is beneficial. Avoiding attractive nesting and perching sites usually minimizes damage by birds. Adequate clearances and insulation should be provided to prevent electrocution of wildlife. 2.6.6.2.
Airborne Foreign Material
Airborne seeds, leaves, debris, dust, and salts that are local phenomena could be a problem. Build-up could occur that would compromise electrical insulation or interfere with cooling. Appropriate prevention measures should be included in the design of a substation expected to be exposed to such contamination. 2.6.6.3.
Reactive Gasses
If a substation is to be situated next to a sewage treatment plant, landfill or waste disposal facility, the developer must take preventive measures to avoid reactive gasses from entering the substation area. These measures must be proven before approval can be considered. If reactive gasses from nearby sources cannot be contained, it is a priority to relocate the substation to another location. If relocation is infeasible due to prior planning approval or etc., the developer must provide all undertaking related to the substation.
Introduction
2.7.
Operation and Maintenance Considerations
The substation site must have infrastructure facilities such as roads, drains, water pipes, and sewage system, whichever is required. Substation sites should also consider land setback requirements, road widening reserves, rivers, routes in and out of street corners and reserve buildings or space for future expansion. For simplicity and ease of maintenance, substation equipment arrangements, electrical connections, signs, and nameplates should be as clear and concise as possible. A substation may occasionally experience emergency operating conditions. The provision of additional load of some equipment or connections should always be considered and appropriately accounted for in the design. Substation design needs to allow maintenance to be accomplished with a minimum impact on a substation’s operation. Allocation of adequate working space is necessary. In selecting equipment, consider the service intervals recommended by the manufacturers and past experience in using a particular manufacturer’s equipment.
2.8.
17
Safety Considerations
It is paramount that substations are safe for the general public and for operation and maintenance personnel. Practical approaches include the employment and training of qualified personnel, appropriate working rules and procedures, proper design such as on earthing systems, and correct construction. The safeguarding of equipment also needs to be considered in substation design.
2
18
Substation Design Manual
Chapter 3: Design 3
3.1.
PMU, PPU and 33 kV SSU
Introduction
This chapter presents general information concerning the design of the physical arrangement of PMU, PPU and 33 kV SSU. It describes various types of substations, illustrates typical layouts, and presents technical criteria of these substations.
3.2.
Pencawang Masuk Utama (PMU)
3.2.1.
Overview
Main Intake Substation / Pencawang Masuk Utama (PMU) is the interconnection point between Transmission’s HV network to the Distribution’s 33 kV, 22 kV and 11 kV MV network. Distribution Division is responsible for the MV primary and related secondary equipment within the PMU. Main Intake Substations / Pencawang Masuk Utama (PMU) are managed by Transmission Division. However, Distribution Division is responsible for the operation and maintenance of MV circuit breakers, panels and MV cable panel inside the PMU. Figure 3-1 is a PMU line diagram showing the responsibility boundary over the assets, operations and maintenance work between Transmission and Distribution.
PMU, PPU and 33kV SSU Design
19
M HV Busbar R
TNBT
TNBD
M R OG NER
Bus Coupler
HV Incomer (CB) Y
Y
Δ
Δ Y
NER
Main Reserve Outgoing Neutral earth resistor Asset Boundary Operation & Maintenance Boundary
Y
MV Incomer (CB) M
MV Busbar
R
O/G Feeder
Bus Coupler
O/G Feeder
Figure 3-1: Line diagram and boundary of responsibility of a TNB PMU
Figure 3-2: PMU with outdoor Air Insulated Switchgear (AIS) switchyard
3
20
Substation Design Manual
3
Figure 3-3: PMU with indoor Gas Insulated Switchgear (GIS)
Figure 3-4: 132 kV Gas Insulated Switchgear (GIS)
PMU, PPU and 33kV SSU Design
3.2.2.
21
PMU Layout
Total land area required for a PMU depends mainly on the type of the primary equipment selected to be used. The equipment is usually classified by the switchgear; being either Air Insulated Switchgears (AIS) or Gas Insulated Switchgears (GIS). AIS equipment has to be installed in a switchyard and thus require much more space than GIS equipment. Additionally if a capacitor bank is required in the PMU, the land requirement will further increase. Minimum land requirements for PMU are summarised in Table 3-1 below. Table 3-1: PMU minimum land requirements Minimum Land Size
Equipment Insulation
(NOT inclusive of Land Setback)
Air Insulated Switchgear (AIS)
(a) 130 m x 130 m (b) 160 m x 150 m (with capacitor bank)
Gas Insulated Switchgear (GIS)
(a) 60 m x 80 m (b) 140 m x 75 m (with capacitor bank)
AIS PMU consists of a large switchyard with equipments that are controlled from a nearby substation building. Typical arrangement of the AIS PMU substation building is shown in Figure 3-5 and switchyard arrangement in Figure 3-6. An example GIS PMU layout is shown in Figure 3-7.
AC Room
Toilet
Control Room
Telecontrol
Battery Room
Relay Room
LV Switchgear
Figure 3-5: Major equipment in the AIS substation building
3
22
Substation Design Manual
(2)
(1)
(3)
(4)
3
(5)
1. 2. 3.
4. 5. 6.
7.
8.
9.
(6)
(7)
(8) (9)
Fly bus Lightning shield conductor Busbar Aluminium Tubular Supported on post insulators Circuit breaker Open and close operations Power transformer Isolators/disconnects Isolation duty Located on both sides of circuit breaker No current make or break rating Current transformer Step down current measurement Protection and control Potential transformer Step down voltage measurement Protection and control Surge arrestor Discharge over-voltage surges to earth
Figure 3-6: Major equipment in the AIS PMU switchyard
PMU, PPU and 33kV SSU Design
23
3
Figure 3-7: Layout of a GIS PMU and typical locations of major components
24
Substation Design Manual
3.2.3.
Electrical Criteria
The electrical design guideline is prepared based on the following system configuration: Table 3-2: Typical ratings in a PMU Components
3 Transformers
132 kV AIS Switchgear
132 kV GIS Switchgear
System Configuration
275/132/33 kV at 240, 180 MVA 132/33 kV at 90, 45, 30, 15 MVA 132/22 kV at 60, 30 MVA 132/11 kV at 30, 15, 7.5 MVA Local/earthing transformers
2 incomer feeders 1 bus-section 1 bus-coupler 2 transformer feeders 1 spare bay 2 incomer feeders 4 cable feeders 1 bus-section 1 bus-coupler 2 x 90 MVA transformer feeders
33 kV Switchgear
2 incomer feeders 4 cable feeders 1 bus-section and 1 bus-coupler for double bus in existing systems; or 2 bus-tie panels for GIS (single bus) for new installations
11 kV Switchgear
2 incomer feeders 14 outgoing cable feeders 1 bus-section; or 1 bus-coupler for double busbar TX Capacity
Neutral earth resistor (NER) in ohms
90 MVA 60 MVA 45 MVA 30 MVA 15 MVA 7.5 MVA
Rated Secondary Voltage 33 kV 22 kV 11 kV 12 8 24 36 16 4 73 8 Solid Grounding
PMU, PPU and 33kV SSU Design
3.2.4.
25
Civil Criteria
Transmission Division is responsible for the design, construction and installation of the PMU. Distribution Division would witness the commissioning of the MV side and is responsible for constructing and installing outgoing feeders in the PMU compound. For civil requirement details, please refer to the “Design Guideline for Built-In GIS Substation” and “Transmission Design Philosophy & Guidelines for Substations” by the TNB Transmission Division.
3
26
3
Substation Design Manual
3.3.
Pencawang Pembahagian Utama (PPU)
3.3.1.
Overview
Primary Distribution Substation / Pencawang Pembahagian Utama (PPU) in the TNB Distribution network manages primary voltages of 33/11 kV. The PPU is normally to step-down the voltage from 33 kV to 11 kV for distribution to pencawang elektrik (P/E) and customers. Figure 3-8 is a sample single-line diagram for a basic PPU.
To other PPUs
3L5
NOP 2L5
1L5
4L5
R
1W0
Double bus 33kV
M
1H0
1S0
T1 30MVA 33/11kV
2H0
T2 30MVA 33/11kV
32
31 30 13K5
11K5
9K5
7K5
5K5
3K5
1K5
Single bus 11kV 2K5
4K5
6K5
8K5
10K5
12K5
Local
Figure 3-8: Typical single line diagram of a PPU
14K5
PMU, PPU and 33kV SSU Design
27
In Figure 3-8, the breakers are numbered systematically with codes as listed in Table 3-3. Table 3-3: Typical numbering/coding for circuit breaker in a PPU Installation
33 kV code
11 kV code
Outgoing Feeder (left side)
5L5, 3L5, 1L5 or 5P5, 3P5, 1P5 or 5S5, 3S5, 1S5
5, 3, 1 or 5K5, 3K5, 1K5
Incomer 1
1HO (from 33 kV) or 1TO (from 132 kV)
31
Bus Coupler
1WO
34*
Bus Section
1SO
30
Incomer 2
2HO (from 33 kV) or 2TO (from 132 kV)
32
6L5, 4L5, 2L5 or 6P5, 4P5, 2P5 or 6S5, 4S5, 2S5 *Notes: only applies for 11 kV double busbars Outgoing Feeder (right side)
6, 4, 2 or 6K5, 4K5, 2K5
The PPU would typically contain 33/11 kV transformers, AIS or GIS switchgears and their control panels, a local transformer for the building supply, auxiliary battery supply, capacitor banks for power factor correction, and Neutral Earth Resistance (NER). The NER is connected to the star point of the transformer to limit the earth fault current. At present there are two types of PPUs which are the conventional PPU (7.5 MVA, 15 MVA and 30 MVA) and Mini PPU (5 MVA). Mini PPU are installed for low load areas such as outskirt/rural areas. The following highlight some typical PPUs found in the distribution network.
3
28
Substation Design Manual
3.3.1.1.
3
One and a Half Storey PPU
The PPU should be ideally constructed as One and a Half Storey buildings. The bottom half of the building houses the cable cellar where the underground cable entry point is. These cables are channelled up to the first floor to connect to the switching and control rooms. Transformer and NER/NEI bays are located outside the building.
Figure 3-9: One and a Half Storey Primary Distribution Substation (PPU) – Front view
Figure 3-10: One and a Half Storey Primary Distribution Substation (PPU) – Rear view
PMU, PPU and 33kV SSU Design
3.3.1.2.
29
Single Storey PPU
Underground cables in single storey PPUs are placed in trenches instead of in cable cellars. This results in less flexibility for cable installation or reconfiguration.
3
Figure 3-11: Single Storey PPU 3.3.1.3.
Special Type (Three/Four Storey) PPU
In certain locations where space is limited, the PPU may be constructed vertically. This option is not recommended as the design needs to be specifically customised to the requirements of each location. This in turn will result in slower project implementation and commissioning.
Figure 3-12: Three-storey PPU
30
Substation Design Manual
3
Figure 3-13: Four-storey PPU
3.3.1.4.
Outdoor PPU
Outdoor PPUs were the early form of the PPU. Plans are in place to refurbish/upgrade existing outdoor PPU to become indoor PPU.
Figure 3-14: Outdoor PPU
PMU, PPU and 33kV SSU Design
3.3.2.
31
PPU Layout
The site for PPU should be at least 46 m x 46 m in size, not including land setback requirements. Major components of a typical PPU are listed in Table 3-4. Figure 3-15 and Figure 3-16 shows the location of these components in a PPU. Generally the lowest floor is the cable cellar and the top floor holds all other primary and secondary equipment located in the switch room, control room and battery room. Transformer and NER bays are located outside the building structure. Table 3-4: Major components in a PPU Primary Equipment
Transformer (Power & Local Transformer) Switchgear NER/NEI (Neutral Earthing System) Power Cables
Secondary Equipment
Battery / Battery Charger Control and Relay Panel (Protection Relays, Unit Protection, OCEF) Marshalling cubicle Remote Terminal Unit (RTU) Control Cables (Pilot or Fibre)
3
32
Substation Design Manual
Cable cellar
3 Spare bay
Underground cable trench
Distribution transformer bays NER bay Local transformer bay Capacitor bank bay
Figure 3-15: Typical ground floor layout of a PPU
Control room 11 kV switch room with cable entry slots
Battery room
33 kV switch room with cable entry slots Roller shutter door
Loading bay
Figure 3-16: Typical first floor layout of a PPU
PMU, PPU and 33kV SSU Design
3.3.3.
33
Electrical Criteria
Table 3-5 summarises the standard electrical ratings for equipment in a PPU. Table 3-5: Electrical ratings for the PPU Parameters Voltage rating
Transformer installed capacity
2 x 30 MVA 2 x 15 MVA 2 x 7.5 MVA
Local transformer
300 kVA
Switchgear
33 kV GIS-Single Bus bar 11 kV AIS-Single Bus bar
Battery charger
Charger – 110 VDC 35 A Battery – 150Ah
Neutral Earthing Resistor (NER)
3.3.4.
System Configuration 33/11 kV 22/11 kV 11/33 kV(step-up) 33/(22 or 11 kV) – dual ratio transformer
33/11 kV NER Transformer 30 MVA – 4 ohm Transformer 15 MVA – 8 ohm 22/11 kV NER Transformer 30 MVA – 4 ohm Transformer 12.5 MVA – 8 ohm
Solid earthing
Transformers 7.5 MVA and below
Earthing
Less than or equal to 1 ohm
Civil Criteria
For detailed civil criteria, refer to the PPU Handbook (Panduan Asas Rekabentuk dan Pembinaan Bangunan Pencawang Pembahagian Utama (PPU) 33/11 kV Bahagian Pembahagian, TNB).
3
34
3
Substation Design Manual
3.4.
Mini PPU
3.4.1.
Overview
Mini Primary Distribution Substation or Mini PPU is a 33/11 kV 5 MVA PPU introduced as an initiative to improve the system performance at suburban and rural areas normally located far from any existing PMU/PPU with load 3 density less than 5 MVA fed through long distance 11 kV distribution lines . The Mini PPU can also contribute in losses reduction in the suburban and rural area by means of:
Shortening the 11 kV feeder length Reducing the 11 kV load per feeder
Figure 3-17: 33/11 kV, 5 MVA Mini PPU
3
Surat Pekeliling Pengurus Besar Kanan (Pengurusan Aset) (Perkhidmatan dan Amalan Kejuruteraan) Bil. A25/2012 Panduan Perancangan Dan Pemasangan Mini PPU 33/11kV 5MVA untuk Pertingkatkan Prestasi Sistem Pembahagian
PMU, PPU and 33kV SSU Design
35
Limitations on the use of the Mini PPU should also be considered: (a) Mini PPU are not suitable for cities or densely populated areas which are typically connected by underground cables. These underground cables are typically rated at 30 MVA; however the jumper (288A/16.4 MVA) and 33 kV isolator (400A/22.8 MVA) are rated below 30 MVA, which will introduce bottleneck to the network. (b) The pole-top circuit breaker short circuit rating is 12.5 kA; therefore it can only be used with systems having short circuit levels not exceeding 90% of the rating, which is 11.25 kA.
3.4.2.
Basic Design Configuration
3.4.2.1.
Major Components
The basic configuration of a Mini PPU consists of the main components listed in Table 3-6. Table 3-6: Primary components and secondary equipment in a Mini PPU Primary Components
Secondary Equipment
5 MVA Transformer, with maximum dimensions of 3.3 m(L) x 3.5 m(W) x 3.4 m(H) 33 kV Switchgear – Pole Top Circuit Breaker 11 kV Switchgear – VCB Type A1 / RMU Outdoor Lightning Arrester o 36 kV, 10 kA o 12 kV, 10 kA 30 VDC Remote Control Box o Battery/Charger 30 VDC
The single line diagram of the Mini PPU is shown in Figure 3-18. Figure 3-19 and Figure 3-20 provides further illustration of the basic Mini PPU 4 configuration .
4
A16/2010 - Panduan Perancangan dan Pemasangan Mini PPU 5MVA 33/11kV
3
36
Substation Design Manual
33 kV bare overhead line/ABC 2
150 mm Silmalec
3 3-pole switch 36 kV, 400 A
3 x 36 kV, 10 kA MOV Lighting Arrestor (LA)
3 x 12 kV, 10 kA MOV LA
Pole top circuit breaker 36 kV, 630 A
3 x 12 kV, 10 kA MOV LA 3 x 12 kV, 10 kA MOV LA 5 MVA 33/11 kV Transformer
3 x 12 kV, 10 kA MOV LA 2
240 mm 3C XLPE Al B2
11 kV VCB Indoor
Figure 3-18: Basic configuration of a Mini PPU 5 MVA
PMU, PPU and 33kV SSU Design
21
37
1
2
20
3
3
4
3
3
19 2
3
7 5 8 16
6
5 MVA 33/11 kV Transformer
6000
18
17
9 11
10 3420 18 1740
1600
R
1000
13 2000
No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21
7
12 1615
15
14
15
R
13
1850
Description Tubular steel pole 15 m or Spun pole 10 m, 5 kN Lightning arrester 36 kV, 10 kA Bare aluminium conductor 150 mm sq. (Silmalec) with insulating cover 3-pole switch 36 kV, 400 Amps Pole top circuit breaker 36 kV, 630 Amps (Auto-recloser) 3-pole switch operating rod ABC, 33 kV, 3 x 150 mm sq. + 50 mm sq. aluminium Wooden peg 6” x 6” PVC pipe 150 mm class B with UV protection Pole top circuit breaker control box Pole top circuit breaker control wire 3-core XLPE insulated aluminium cable with MDPE outer sheath 11 kV, 240 mm sq. Single wall HDPE corrugated pipe 150 mm Transformer plinth 2700 x 1850 mm (length x width) Angle iron bracket 50 x 50 x 5 mm HV cable box, air type, 33 kV LV cable box, air type 11 kV Angle iron bracket 50 x 50 x 5 mm Bimetal lugs 150 mm sq. (See Detail A) Copper strip 25 x 3 mm with black coating Parallel grooved clamp 150 mm sq.
Figure 3-19: Mini PPU 5 MVA 33/11kV design configuration
38
Substation Design Manual
28
22
3
25 22
26
8 23
22
24 18
22
27 29
No 8 18 22 23 24 25 26 27 28 29
22
Description Wooden peg 6” x 6” Angle iron bracket 50 x 50 x 5 mm C-channel iron cross arm min. dimensions 50 x 50 x 100 mm with 5 mm thickness Flexible steel strap Half stay clip Stay insulator (big) Stay wire 7/8 swg Stay bow and thimble Universal band Aluminium cleats
Figure 3-20: Mini PPU 5 MVA 33/11 kV design configuration (isometric view)
PMU, PPU and 33kV SSU Design
3.4.2.2.
39
Electrical Criteria
The Mini PPU is suitable for 33 kV overhead lines with spur or T-off feeder configuration. Table 3-7 summarises the standard electrical ratings and configuration for equipment in a Mini PPU. Table 3-7: Typical electrical ratings and configuration of Mini PPU Item Incoming 33 kV system Pole-top circuit breaker
Typical Electrical Ratings and Configuration
The incoming 33 kV system must be from an overhead system, either bare conductors or Aerial Bundle Cable (ABC).
A 3-pole switch and auto-recloser is installed to function as a 33 kV pole-top circuit breaker (with auto-recloser function turned OFF). Pole-top circuit breaker must be installed correctly to prevent it from falling off the H-pole structure.
Cable
VCB
Lightning Arrester
2
33 kV ABC (3x150 mm ) is used to connect from the pole-top circuit breaker to the primary side of the 5 MVA 33/11 kV transformer. 2 11 kV XLPE Al 3-core (240 mm ) cable is used to connect from the secondary site of the 5 MVA 33/11 kV transformers to the VCB (B2 type) in the switchgear room. Both sides of the messenger wire for the 33 kV incoming cables must be tied to the H-Pole structures and to the transformer body. The 33 kV incoming cable must be bonded to the H-Pole structure, by single point earth bonding using copper braids. The cable bending radius (R in Figure 3-19), shall be minimally: o Single core – 20 x cable diameter o Three core – 15 x cable diameter o ABC – 7 x cable diameter (overall diameter of the ABC) Suitable bimetal lugs sizes must be used for the transformer tail connections. All cable terminations must use types/brands approved by TNB. Three VCB (A1 type) panels are used for 11 kV system reticulation. One VCB (A1 type) panel is used for the local transformer supply. Surge arresters are installed on both MV and LV terminals of the transformer.
3
40
Substation Design Manual
3.4.2.3.
Civil Criteria
In general the construction of building structures should follow the civil requirements of indoor substations as stated in Subchapter 4.2.4 and requirements of pole-mounted structures as stated in Subchapter 4.7.4.
3
Additionally, requirements specific to this substation are listed here. Table 3-8: Mini PPU civil design requirements Item
Dimension of Mini PPU
Switchgear Room
Minimum Requirements The dimension for the 5 MVA 33/11 kV Mini PPU depends on the poles, transformer and 11 kV switchgear building layout. 11100 x 21000 mm (Layout A – Figure 3-21), or 19000 x 13000 mm (Layout B – Figure 3-22), or 14620 x 14620 mm (Modified P/E – Figure 3-23)
Room size: 5000 x 5100 mm The room design (which includes the civil and structure design, earthing system and drain outlet) is according to Pekeliling Pengurus Besar Kanan (Kejuruteraan) Bil A49/2009 (Design standard of SSU 11 kV substation).
Plinth
The plinth for Mini PPU components must be able to withstand the weight of 1.4 times the dead load. The weight for the 5 MVA transformer is 15 tonnes (15,000 kg).
Fence
The fence for the Mini PPU must be installed for the safety purpose and also to indicate the area of the substation. The fence must be 3.05 metres tall.
3.4.3.
Mini PPU Layout
3.4.3.1.
New Installations
Land size for a Mini PPU depends on the arrangement of electrical poles, transformer and 11 kV switching room. Figure 3-21 and Figure 3-22 show two possible layouts for the Mini PPU.
PMU, PPU and 33kV SSU Design
41
Ultimately, arrangement of these components must comply with the minimum clearance between each component and substation building:
Cable chute for outgoing cables
760 5000
760
1000
B2 A1 A1 A1 A1 900
VCB
Local Tx 300 kVA
900
5 MVA 33/11 kV Transformer
1000
11000
4000
2000
2000
17000
5100
5. 6.
760
800
Battery Charger
2 000
4.
2 000
2 000
3.
Distance between the H-pole and the 5 MVA transformer is 2 metres. Distance between the 5 MVA transformer and the 11 kV switchgear building is 2 metres. Distance between the 11 kV switchgear building and the 300 kVA local transformer is 2 metres. Distance between the substation fence and any Mini PPU component or building is 2 metres. Distance between the gate and the switching room building is 3 metres. The 33 kV incoming cables must be installed at least 600 mm away from the H-Pole structure.
4000
1. 2.
1000
2000
Feeder Pillar 800 A
1500
1200
Cable chute for outgoing cables
Pole Top CB
1000 4000
Note
900 mm trench depth sand filled with cement rendered
1. A1 configuration VCB shall be used with approved type relays. 2. Battery charger shall be 30 Vdc 10A/40Ah
Figure 3-21: Layout of the Mini PPU – Layout A
3
42
Substation Design Manual
10100
1200
2000
800
Feeder Pillar 800 A
900
1000
3
2000
1000
Cable chute for outgoing cables
Local Tx 300 kVA
1500
VCB
A1
17000
760
2000
760
900
19000
B2
5100
20004000
760
Battery Charger
3 000 Cable chute for outgoing cables
5000
760
1000
5100
B2 A1 A1 A1 A1 900
VCB
900
5 MVA 33/11 kV 5 MVA 33/11 kV Transformer
4000
4000
Local Tx 300 kVA
1000
Transformer
760
11000
A1
2000
5000
A1
4000 4000
Cable chute for outgoing cables
760
2000
A1
800
1000
1000
2000
Feeder1000 Pillar 800 A
1500
2 000
4000
Pole Top CB
Cable chute for outgoing cables
1200 Note
1. A1 configuration VCB approved type relays 2. Battery charger shall
2 000
2 000
2 000
Pole Top CB
4000
1000
2 000
Battery Charger
900 mm trench d with cement ren
Note
900 mm trench depth sand filled with cement rendered
1. A1 configuration VCB shall be used with approved type relays. 2. Battery charger shall be 30 Vdc 10A/40Ah
Figure 3-22: Layout of the Mini PPU – Layout B
PMU, PPU and 33kV SSU Design
3.4.3.2.
43
Modification of Existing P/E
Depending on site requirements, existing indoor standalone single chamber P/E buildings (14.6 m x 14.6 m) can be modified and transformed into Mini PPU. Transformation from existing P/E into Mini PPU is encouraged so that new Mini PPU can be established in a shorter timeframe and procurement for new land can be avoided. The following criteria should be considered for new Mini PPU located at the sites of existing P/E distribution substation: 1.
The 33/11 kV 5MVA transformer to be placed in front of the P/E building.
2.
The existing 11/0.4 kV transformer to be relocated outdoor.
3.
The existing P/E building is modified to become an 11 kV VCB switching room.
4.
Replace chain link with brick wall of 2.13 meters in height, with extra height of 3.05 meter high for walls adjacent to the transformer to provide for safety measures and pleasant view to the neighbouring households.
5.
The minimum safety and working clearances must be complied.
The suggested modified P/E layout for a Mini PPU is shown in Figure 3-23.
3
44
Substation Design Manual
14620 – (48’-0’)
3480
4620
3050
3480
3165
7670
Local Tx
New 2130 high brick wall to replace existing chain link fence
600 900
4600
3
2500
14620 – (48’-0’)
Existing P/E
New 3050 high brick wall to replace existing chain link fence
3.3m
1865
Plinth 5 MVA Tx
3.5m
6865
1.5m
3995
H-pole with pole-top CB
4Nos, 160mm CHDPE Pipe
4 meter wide gate
Figure 3-23: Mini PPU layout for modification of existing standalone single chamber substation
3.4.4.
Connection Guidelines
Connection schemes for the Mini PPU are as follows: (a) Spur with 33 kV ABC or bare overhead line directly from 132/33 kV PMU source or 33/ 11kV PPU; (b) Ring with 33kV ABC between two or more Mini PPU fed by feeders from the same or different 132/33 kV PMU or 33/11 kV PPU. Table 3-9 shows a summary of Mini PPU connection scenarios and guides on planning schemes with accompanying diagrams.
PMU, PPU and 33kV SSU Design
45
Table 3-9: 33kV Network Connection Scheme to Mini PPU Scenario Erection of new Mini PPU 33/11 kV 5 MVA
Erection of 2nd/3rd Mini PPU to existing Mini PPU network
33kV Network Connection Scheme (a) Connection of 2 33 kV ABC, 3 x 150 mm , Al., from 33 kV bare overhead lines (Figure 3-24) (b) Spur connection of 2 33 kV, ABC 3 x 150 mm , Al., from an existing PPU. (Figure 3-25) (c) Connection of 33 kV 2 ABC, 3x150 mm , Al., from 132/33 kV PMU. (Figure 3-26) Connection of 33 kV ABC, 2 3x150 mm , Al., from existing Mini PPU (Figure 3-27)
33kV Connection Criteria / Requirement Auto-recloser must be installed at the T-off point between the ABC and bare overhead lines to control operation and isolation. Total load of the 33 kV main feeder to the PPU must comply with the n–1 contingency.
i.
Spur connection if feedback is 100% through 11 kV ii. Ring connection if 11 kV network could not support 100% feedback Add H-pole and Auto-recloser at Mini PPU for operational control and feedback 33 kV network. (Number of Mini PPU depends on protection coordination ability)
In principle, a spur connection is suitable to be set up at the early stage of Mini PPU establishment at rural areas with the condition that the connected 11 kV network is free from any non-transferable load (NTL) problem if the 33 kV network experiences supply disruptions. If NTL is possible or when the same 33 kV network needs to be connected to additional Mini PPU, a ring connection should be established as the next stage of the 33 kV network expansion. It should be noted that any loop in – loop out (LILO) connection from Mini PPU to the existing main feeders between PMU to PPU, between PPUs or between SSUs with fully switched equipment is prohibited. This is to ensure the stability of the unit protection scheme and the operation of the main feeders.
3
46
Substation Design Manual
33 kV bare overhead lines
3
33 kV ABC 3 x 150 mm2
Mini PPU
Figure 3-24: T-off connection from 33 kV bare overhead lines to Mini PPU
PMU, PPU and 33kV SSU Design
47
33 kV Incoming Feeder 1 33 kV Incoming Feeder 2 PPU
3 33 kV Interconnector to another PMU/PPU 33 kV ABC 2 3 x 150 mm Mini PPU
Figure 3-25: Spur connection from an existing PPU to a Mini PPU
48
Substation Design Manual
PMU 132/33 kV
3
ABC 3 x 150 mm 33 kV
2
Mini PPU
Figure 3-26: Spur connection from an existing PMU to a Mini PPU
PMU, PPU and 33kV SSU Design
49
A typical connection from a PMU to two Mini PPUs is shown in the single line diagram of Figure 3-27 below. Legend: Lightning arrestor
PMU 132/33 kV
Pole-top circuit breaker 3-Pole Switch
Connection from another PMU or same PMU (different bus) ABC 3 x 150 mm 33 kV
2
ABC 3 x 150 mm 33 kV
ABC 3 x 150 mm 33 kV
Mini PPU No.1
2
2
Mini PPU No.2
Figure 3-27: Connection between PMU and multiple Mini PPUs
3
50
3
Substation Design Manual
3.5.
33kV Primary Switching Station (33 kV SSU)
3.5.1.
Overview
33kV Primary Switching Station / Stesen Suis Utama (33 kV SSU) refers to a station that supplies power via circuit breakers to ‘bulk supply customers’ and other distribution circuits at the 33 kV voltage level. The 33 kV SSU bus-tie is designed using single-bus switchgears with bus-tie system to avoid total shutdown to customers for maintenance works. This configuration is illustrated in Figure 3-28. 33 kV incomer
7S5
33 kV incomer
3S5
5S5
4S5
1S5
2S5
8S5
6S5
Bus-tie
33 kV Consumer Service Feeder
2nd 33 kV Consumer Service Feeder
Figure 3-28: The design of bus-tie for 33kV SSU
PMU, PPU and 33kV SSU Design
51
The main advantages of SSU 33 kV using Bus-Tie are: Electrical supply for 33 kV bulk consumers will not be interrupted whenever the switching station is under maintenance. Therefore, the system reliability is not affected. In the event of component failure such as switchgear flashover, only half the bus will be affected and supply to customer can be restored immediately through the other bus. This configuration provides a safe and convenient way to perform maintenance work.
33 kV incomer
7S5
33 kV incomer
3S5
4S5
8S5
Section A
Section B 5S5
1S5
2S5
6S5
Bus-tie 100% Load 33 kV Consumer Service Feeder
nd
2 33 kV Consumer Service Feeder
Section under Shutdown
Figure 3-29: Supply feedback to SSU A From the above diagram, the maintenance unit can perform half bus shutdown for Section A without causing supply disruption to consumers because the consumers’ load can be transferred to the second service cable.
3
52
Substation Design Manual
3.5.2.
33 kV SSU Layout
The site for 33 kV SSU should be at least 30 m x 30 m in size, not including land setback requirements.
3
Figure 3-30 shows the typical layout of 33 kV SSU and locations of major components. Generally the SSU contains a switchgear room, control room, battery room and metering room. Incoming and outgoing cable connections would be installed in underground cable trenches or a half-storey cable cellar. However, the actual design may vary according to the availability of land and suitability to the site. Table 3-10: Major components in an SSU Primary Equipment
Switchgear Power cables
Secondary Equipment
Battery / Battery Charger Control Relay Panel (Protection Relays, Unit Protection, OCEF) Marshalling cubicle Remote Terminal Unit (RTU)
Cable entry via cable cellar
Switchgear room
Control room Store Metering room
Battery room
Figure 3-30: Typical layout of 33kV SSU and locations of major components
PMU, PPU and 33kV SSU Design
3.5.3.
53
Electrical Criteria
Table 3-11 below summarises the typical electrical ratings in a 33 kV SSU. Table 3-11: Typical ratings in a 33 kV SSU Item Voltage rating
Typical ratings
33 kV
Switchgear
33 kV GIS – Single busbar with bus-tie (for new areas) 33 kV GIS or AIS – Double busbar (existing areas) Incomers as required 2 Outgoing feeders to consumer 2 Breakers for Bus-tie (where applicable)
Interconnecting Cables between Bus-Ties (where applicable)
3 x 33 kV XLPE 630 mm Al Single Core (single bonding practice shall be strictly followed for single core cable as stipulated in Arahan Naib Presiden Bil A06/2010 Amalan Single Point Bonding pada Transformer Tail di dalam PMU/PPU)
Protection for bus-tie (where applicable)
Battery charger and battery Earthing
3.5.4.
2
OCEF and Current Differential protection scheme on both bus-ties At least one of the switchgears on the bus-tie must be normally off (on soak) OCEF setting for both switchgears must follow the settings supplied by the manufacturer Switch configuration and position during normal operation, shut-down, contingency, as well as during operation and equipment ownership must follow the Interconnection Operation Manual (IOM) that exists between the RCC and consumer. Charger – 110 VDC 35 A Battery – 150 Ah Less than or equal to 1 ohm
Civil Criteria
In general the construction of building structures should follow the civil requirements of indoor substations as stated in Subchapter 4.2.4.
3
54
Substation Design Manual
3.6.
Testing and Commissioning
Before commissioning the PMU, PPU or 33 kV SSU, specific tests are to be carried out on substation equipment to ensure safe and reliable operation. The following are some tests that are to be performed, wherever applicable:
3
Pre-commissioning tests: (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n)
Current transformer test Instrumentation transformer test Power transformer test Secondary equipment test Instrumentation verification tools test Validation test major component Testing the stability of the protection scheme Switchgears operation test Power transformers operation test Substation battery system test Test indication to the SCADA system Transducer test Grounding system test Heating test
Commissioning tests: (a) Live phasing test (b) Phasing voltage test instrumentation
P/E, 11 kV SSU and S/S Design
Chapter 4: Design 4.1.
P/E, 11 kV SSU and S/S
Introduction
This chapter covers general design, illustrates typical layouts, and presents technical criteria of various types of stations for the MV/LV distribution network. The types of substations that will be covered in this chapter are: 4.2 4.3 4.4 4.5 4.6 4.7 4.8
Indoor Distribution Substation / Pencawang Elektrik (P/E) 11 kV Primary Switching Station / Stesen Suis Utama 11 kV (11 kV SSU) Outdoor Distribution Substation / Pencawang Elektrik (P/E) Switching Station / Stesen Suis (S/S) Compact Substation Unit (CSU) / Pencawang Elektrik Padat Pole Mounted (H-Pole) Substation / Pencawang Atas Tiang (PAT) Pole Mounted (H-Pole) Substation (PAT) with RMU
Subchapter 4.2 introduces construction guides applicable for all substation building structures. Standardised distribution substation buildings and their schematic drawings are made available in the latest versions of the following documents:
55
Electricity Supply Application Handbook (ESAH) Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian
Subchapter 4.4 provides guides on outdoor substation structures. Construction guides and schematic details of pole-mounted substations are introduced in Subchapter 4.7.
4
56
Substation Design Manual
4.1.1.
Characteristics of Distribution Substations
Typical distribution substations will have several MV feeder circuit connections: one or more incoming feeders; and one or more outgoing feeders. Spur substations will only have one MV incoming feeder connection.
4
MV circuits connect to the substation through switchgears which are used principally to isolate the substation from the MV network for maintenance, fault sectionalizing, or when replacement of substation equipment is required. The switchgear used can be either vacuum circuit breakers (VCB) or ring main units (RMU). The MV circuit can then be stepped down to LV via a transformer to supply LV customers. MV customers can also receive directly from the substation. Figure 4-1 and Figure 4-2 show sample single-line diagrams for distribution substations. MV Incoming feeder
MV Outgoing feeder
VCB Transformer
LV customer
MV customer
Figure 4-1: Basic VCB Distribution Substation (P/E) with 1 incoming feeder, 1 outgoing feeder, 1 LV transformer feeder, 1 MV customer
P/E, 11 kV SSU and S/S Design
MV Incoming feeder
MV Outgoing feeder
Transformer 1
Transformer 2
LV customer 1
LV customer 2
Figure 4-2: Basic RMU Distribution Substation (P/E) with 1 incoming feeder, 1 outgoing feeder, and 2 LV transformer feeders
4.1.2.
57
Characteristics of Switching Stations
A switching station is a combination of switching and controlling equipment arranged to provide circuit protection and system switching flexibility. Incoming connections are typically from PPU and outgoing connections are usually to P/E or MV customers.
Incoming
VCB
Incoming
VCB Busbar
Outgoing
Figure 4-3: Typical switching station single line diagram
4
58
Substation Design Manual
4.1.3.
Comparison of Substations
It is useful to note the differences between substations and switching stations for operational purposes.
4
P/E will have switchgears that are either VCB or RMU. For Indoor P/E these switchgears will be installed in a switching room.
P/E will also have a distribution transformer installed inside a transformer room/chamber. Additional transformers require separate chambers.
11 kV SSU are characterised by a bus section. SSU connect to multiple feeders at 11 kV that can go to other substations, distribution transformers or direct to bulk consumers.
S/S are stations without transformers and function only as switching or T-off points using an RMU with three switches (3S) or VCBs.
PAT are distribution substations with components and equipment that are mounted on poles.
Figure 4-4: Indoor – standalone, single chamber without metering room
P/E, 11 kV SSU and S/S Design
59
Table 4-1 highlights the characteristics and main differences between indoor distribution substations and 11 kV switching stations. Table 4-1: Comparison of distribution substations and 11 kV switching stations Pencawang Elektrik (P/E) RMU Single chamber
VCB Double chamber
Single chamber
Double chamber
4
no transformer
11 kV SSU (VCB) 1 Transformer
Substation (No transformer) VCB RMU
2 Transformers
PAT (Pole-mounted)
60
Substation Design Manual
4.2.
Indoor Distribution Substation (Indoor P/E)
4.2.1.
Overview
The indoor distribution substation or pencawang elektrik (indoor P/E) is a substation with all primary equipment installed within a building structure. Indoor P/E can be built either standalone or attached to a building. Both can be of single or double chamber type, with or without a metering room.
4
4.2.1.1.
Indoor – Standalone
Possible configurations are single chamber or double chamber, with or without metering room. This is the ideal choice with the principal advantages as follows: (a) It facilitates installation of fully switched facilities, or power factor improvement capacitors, if and when required. (b) It facilitates the installation of automation equipment, such as SCADA, remote switching facilities, etc. (c) It provides easy access, and space separating it from adjacent buildings, thus minimize the risk to the adjacent building (due to safety reasons). (d) For substation with extra land area, it can accommodate additional extension of switchgear or compact substation to meet the increasing customer demand. (e) Removes the need for any special fire fighting facilities. The use of portable dry type powder fire extinguishers is sufficient. 4.2.1.2.
Indoor – Attached to a Building
Possible configurations are single chamber or double chamber, with or without metering room and with or without SCADA facilities. This alternative has similar advantages to that of a separate building, except: (a) Little or no land space, as developers usually provide the minimum space. (b) The need to install fully automatic fire fighting equipment to meet fire safety requirements. (c) Design of the building must be in line with developers’ layout plan with emphasis on aesthetics and landscaping. (d) Building owners may need to incorporate fire fighting facilities for their premises.
P/E, 11 kV SSU and S/S Design
61
In practice, the real estate developer will construct and provide the substation building based on the requirements specified by TNB during project planning. Substation architectural designs and colour schemes need to be in harmony with the surrounding, as required by Arahan Naib Presiden Bil. A2/2010. The following figures show sample indoor substations.
4 Attached P/E
Figure 4-5: Indoor – attached, double chamber P/E designed to blend with surrounding structures
Figure 4-6: Indoor – standalone, double chamber P/E designed to blend with surrounding structures
62
Substation Design Manual
4.2.2.
Indoor P/E Layout
Typical indoor substation building sizes are shown in Table 4-2 and Table 4-3 taken from ESAH version 3.
The sizes below can also cater for SCADA equipment installation. Total land area required will need to take into account of land setback requirements. Please refer to the latest version of ESAH for updates or changes in layout design.
4
Table 4-2: Standard sizes of 11/0.4 kV indoor substations (without Metering Room) Building Type
S/Gear
Overall (mm)
S/Gear Room (mm)
Tx Room (mm)
Length (mm)
1
Single chamber
Standalone
VCB
7600 x 5100
4600
3000
5100
2
Double chamber Standalone
VCB
10600 x 5100
4600
3000
5100
3
Single chamber
VCB
8600 x 5700
5600
3000
5700
4
Double chamber Attached
VCB
13000 x 5700
7000
3000
5700
5
Single chamber
Standalone
RMU
7000 x 4000
4000
3000
4000
6
Double chamber Standalone
RMU
10000 x 4000
4000
3000
4000
7
Single chamber
Attached
RMU
8000 x 5700
5000
3000
5700
8
Double chamber Attached
RMU
13000 x 5700
7000
3000
5700
Attached
Table 4-3: Standard sizes of 11/0.4 kV indoor substations (with Metering Room) Building Type
S/Gear
Overall (mm)
S/Gear Room (mm)
Tx Room (mm)
Length (mm)
1
Single chamber
Standalone
VCB
7600 x 5700
4600
3000
5700
2
Double chamber Standalone
VCB
10600 x 5700
4600
3000
5700
3
Single chamber
Attached
VCB
7600 x 5700
4600
3000
5700
4
Double chamber Attached
VCB
12000 x 5700
6000
3000
5700
5
Single chamber
Standalone
RMU
7000 x 5700
4000
3000
5700
6
Double chamber Standalone
RMU
10000 x 5700
4000
3000
5700
7
Single chamber
Attached
RMU
7000 x 5700
4000
3000
5700
8
Double chamber Attached
RMU
11000 x 5700
5000
3000
5700
P/E, 11 kV SSU and S/S Design
63
Major components of a typical indoor P/E are listed in Table 4-4. Figure 4-8 and Figure 4-9 shows the location of these components in indoor P/Es.
Switchgears are installed in switching rooms. Distribution transformers are placed inside transformer rooms/chambers. Each transformer requires a separate chamber. Feeders for P/E are all connected by underground cables which enter and exit the substation via PVC ducts. Feeder pillars are located outside the building structure. Attached substation rooms are larger in size to accommodate the feeder pillars, and the additional ventilation fans and fire fighting equipment. Table 4-4: Major components in an indoor distribution substation Primary Equipment
Switchgear (VCB / RMU) Transformer Feeder pillar
Secondary Equipment (For VCB only)
Battery Charger with Battery Control Relay Panel (Protection Relays, Unit Protection, OCEF) Remote Control Box (RCB) Remote Terminal Unit (RTU)
Customer LV room
Fire-fighting control panel
Transformer rooms
RCB panels
Switching room
Figure 4-7: Indoor – attached, double chamber with RCB and RTU panels (SCADA ready)
4
64
Substation Design Manual Transformer with guards in a chamber
VCB in the switching room
Underground cable trench
Ventilation blocks
Feeder pillar
4 LV feeder underground ducts
RCB Manhole
11 kV feeder underground ducts
Figure 4-8: Layout of Standalone Indoor Substation – Double Chamber Metering room
Transformer in a chamber
VCB in the switching room
Ventilation blocks (where possible)
Insulating mat Ventilation fans
11 kV feeder cables RCB Feeder pillar LV feeder underground cables
Figure 4-9: Layout of Attached Indoor Substation – Double Chamber with Metering Room
P/E, 11 kV SSU and S/S Design
4.2.2.1.
65
Switching Rooms
Indoor substations will always have switchgears which are either vacuum circuit breakers (VCB) or ring main units (RMU) which are installed in a switching room. Rooms installed with VCB will be slightly larger due to the VCB’s larger size compared to the RMU. 4.2.2.2.
Transformer Room/Chamber
Indoor P/E will also have a distribution transformer installed inside a transformer room/chamber. Additional transformers require separate chambers to ensure containment during any emergency. 4.2.2.3.
Metering Room
Certain indoor substations that are supplying to LV and 11 kV bulk customers will have a metering room, connected either to the transformer tail or feeder pillar for LV bulk customer or to the switchgear for MV/HV customer. Suggested locations for the metering room with respect to the customer are shown in the following Subchapters (4.2.2.4 and 4.2.2.5). For 33 kV bulk customers, the metering room shall be located at the customers’ premise. General design requirements of the metering room are as follows:
The metering room is an enclosed looked room for the purpose of installing metering cubicles, and must have its own dedicated entrance, separated from the transformer/switchgear rooms by walls. The metering room is separated so that the meter may be accessed without having to enter the high voltage zone. The minimum size for the room is 2.0 m(W) x 2.0 m(L) x 2.5 m(H) and located inside the substation/switching station for LV and 11 kV bulk customers. Location of the metering cubicle inside the metering room shall be as represented in Figure 4-10.
4
66
Substation Design Manual
2000
550
Metering Cubicle
2000
1100
4 Entrance
Figure 4-10: Layout for installing metering cubicle in the metering room
4.2.2.4.
P/E Location for LV Bulk Customer
For LV bulk customer, the preferred type of building is the standalone indoor substation. Suggested location of the substation with respect to the customers’ facility and main switch board (MSB) is shown in Figure 4-11 and Figure 4-12. Substations for LV bulk customers must be located at the front area of the gated factory with a separate access from the main factory access. This is required because of the following objectives:
TNB personnel can enter the substation easily without getting permission from the customer. TNB personnel can perform cable and substation upgrading work without disturbing roads/facilities inside the customers’ compound.
P/E, 11 kV SSU and S/S Design
67
Criteria of new substation location for LV bulk customer: (a) Size of the substation must comply with setback and frontage requirement of the local authority (b) Customers’ MSB room are recommended to be place next to the substation (Figure 4-11) (c) If customers’ MSB room cannot be located next to the substation due to unavoidable technical issues, customers’ MSB room can be located at the factory’s building (Figure 4-12) with these conditions: i. The LV service cable cannot have any straight through joints and the length of the cable must be less than 250 meters; ii. Voltage drop from the substation to the customers’ MSB is less than 5% as suggested in the LV Planning Guideline; iii. If LV service cable is of single core type, it must be laid in a concrete trench with earthing copper tape (extended from transformer starpoint connection) at the bottom for the physical protection of the cable and for ease of maintenance. The concrete trench needs to be filled with sand and cement rendered.
Factory Fence
TNB metering room
Customers’ MSB P/E
Road
Figure 4-11: Location of P/E with attached MSB room for LV bulk customers
4
68
Substation Design Manual
Customers’ MSB Factory Fence LV service cable inside concrete trench
4
TNB metering room P/E
Road
Figure 4-12: Location of P/E with detached MSB room for LV bulk customers
4.2.2.5.
P/E Location for MV Bulk Customer
The substation location for MV bulk customers is dependent on the land area of the factory:
If the land area is big, an indoor standalone P/E located at the front area of the gated factory is preferred. If the land area is small, an attached substation is allowable provided 24 hour accessibility to the substation is possible.
P/E, 11 kV SSU and S/S Design
4.2.3.
69
Electrical Criteria
Table 4-5 summarises the standard electrical ratings for equipment in the indoor substation. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-5: Typical ratings in a conventional P/E Equipment/component
Rating and size
Voltage rating
11/0.433 kV
Transformer installed capacity
500 kVA, 750 kVA, 1000 kVA
Switchgear Feeder pillar
4.2.4.
12 kV Ring Main Unit (RMU); or 12 kV Vacuum Circuit Breaker (VCB) 800 A, 1600 A
Civil Criteria
The following are guidelines for typical substation civil requirements to provide proper working environment for the equipment and personnel working within the indoor substation. Guidelines provided here are also applicable to all other distribution substations with building structures. 4.2.4.1.
Compound area
A flat surface ideally desired for the layout and operational function of a substation. It permits uniformity in foundation elevations and structure heights. Unless there are property restrictions, severe topographical features, subterranean rock, or other considerations dictate otherwise, the substation surface should be graded nominally flat.
4
70
Substation Design Manual
4.2.4.1.1.
Land Requirement
The required land size must consider the size of the substation as shown in Table 4-2 and Table 4-3 previously. Additional setback and frontage requirement of local authorities must also be considered. Under normal circumstances the following land size is sufficient for Standalone Indoor P/E: (a) Single chamber – 13.6 m x 14.8 m (b) Double chamber – 16.6 m x 14.8 m
4
4.2.4.1.2.
Foundation
Piling requirements need to be decided based on evaluation of the soil condition which should have been evaluated during initial site investigations. 4.2.4.1.3.
Surfacing Material
For standalone substations, the compound area outside the building structure should be paved with tarmac or cement of 50 mm (2 inches) thickness with 150 mm (6 inches) of crusher run underneath. 4.2.4.1.4.
Substation gate and fence should ideally be 2.1 metres or 7 feet tall. Decorative gate and fence designs are encouraged to harmonize with the surrounding. Fence for standalone substations can be substituted with concrete kerbs (minimum 150 mm in height) or bollards to mark the substation area. For attached substations, whenever possible, removable barriers have to be installed 3 metres in front of the switchgear room and transformer room doors such that the entrance to the substation is not blocked.
4.2.4.1.5.
Gate and Fence
Drainage
Drainage should be built surrounding the substation around 750 mm from the outside wall to the centre of the drain. The drainage must be connected to the nearest existing draining system in the vicinity.
P/E, 11 kV SSU and S/S Design
4.2.4.2. 4.2.4.2.1.
Structures Floor
The substation floor should be made of Reinforced Concrete (RC). Surface finishing of the outdoor area should be at one level. Floors are to be painted with epoxy green paint. Minimum safety clearance should be marked with yellow paint. The substation RC floors need to cater for the weights of equipment to be installed on it. The minimum floor loadings are shown below: Table 4-6: Minimum floor loadings for indoor P/E
4.2.4.2.2.
71
Equipment
Floor load
Transformer
Nominally 7000 kg 1.4 x transformer weight
Indoor Switchgear (VCB/RMU)
Nominally 8000 kg 1000 kg x VCB panel number (8 panels in switching room)
Feeder Pillar
1000 kg
Walls
All walls for building structures should be constructed using red clay bricks laid with 1:3 cement sand mortar. All walls should be 230 mm thick. All walls should be reinforced with expanded metal (exmet) at every fourth course in order to strengthen the wall structure. Partition walls between switching room and transformer room should be 230 mm thick and 2100 mm tall.
4
72
Substation Design Manual
Expanded metal layer
4
Figure 4-13: Expanded metal (exmet) layer at every fourth course
4.2.4.2.3.
Damp-Proof Course (DPC)
Damp-proof course (DPC) is necessary to prevent moisture ingress into the ground beam as well as termite infestation prevention. The DPC consists of 25.4 mm or 1 inch thick 1:1 cement sand-screed bedding laid on the ground beam. Upon drying, a bituminous felt is laid with liquefied bitumen.
Wall drying out above DPC
New plaster
Skirting
New chemical DPC
DPC membrane in solid floor
Ground level Rising damp
Figure 4-14: Damp-proof course (DPC)
P/E, 11 kV SSU and S/S Design
4.2.4.2.4.
Ventilation
Ventilation blocks (batu angin) can be used to provide sufficient aeration for the substation equipment. To prevent entry of pests into the substation building, anti-vermin plastic or stainless steel mesh netting mounted on aluminium frames must be installed on the outside of the ventilation blocks. The ventilation blocks for the switch room shall be covered with awnings to prevent rain water from entering the switch room which would affect the switchgears.
Figure 4-15: Ventilation blocks with anti-vermin plastic mesh
73
Attached indoor substations require additional ventilation in the form of an exhaust fan. The exhaust fan must be at least 12 inches in size and installed with thermostat control. The fan should be pulling air out of the substation.
4
74
Substation Design Manual
4.2.4.2.5.
4
Doors
All louvered doors shall be made of Composite-Fibre Reinforce Plastic. All louvered doors shall be installed with plastic anti vermin netting or stainless steel mesh netting mounted on Aluminium frame fixed on the inside of the door. Doors should be sized to fit the equipment to be installed inside the room. Transformer rooms require large double leaf doors to accommodate the size of the transformer. Suggested door dimensions are as follows: (a) Transformer room: 2400 mm(W) x 3000 mm(H) double leaves (b) Switchgear room: 1500 mm(W) x 3000 mm(H) double leaves
4.2.4.2.6.
Roofing
For all standalone substation buildings, the roofing style should match the styles of the surrounding building and area. If no specific roofing style is required, the roof should be of reinforced concrete (RC) flat type constructed with proper water proofing treatment.
RC flat roof designs shall cater for a waterproof slab, cast with waterproof concrete, cement screed with waterproofing agent, and provide for minimal shrinkage with anti cracking reinforcement. A layer of bituminous material must be applied to waterproof the concrete slab roof. For the attached P/E substation-type, if there are pipes across the top of the substation, two layers of water proof concrete roof slabs should be built. The first layer (closer to the substation) must contain a bituminous layer.
P/E, 11 kV SSU and S/S Design
4.2.4.2.7.
4.2.4.3.1.
Cable Trenches
All trenches in the substation are to be filled with washed river sand. Washed river sand has the following advantages: (a) Avoid moisture from entering into the switchgear via the cable entry. (b) Better heat dissipation and minimisation of impact due to fire hazards. (c) Has arc quenching property which can protect neighbouring cables from a cable that is at fault. (d) From a safety aspect – closed trenches can eliminate the risk of staff falling into the trench. A 50 mm (2 inch) thick cement render (1:2, cement:sand) is required to cover the trench. This is to minimize condensation of water from inside the trench and to prevent entry of vermin through the trench. The spacing from the trench floor to any beam or structure that may protrude into the trench should be 600 mm minimum. This is to ensure sufficient space to install the cable in the trench.
4.2.4.3.
75
Installations Pipes/Ducts for Feeder Cables
All incoming and outgoing MV and LV feeder cables to the substation need to be installed via pipes/ducts for added mechanical protection. The type of pipe to be used is PVC Class B with different diameters depending on its use as follows: a) 150 mm diameter – for 11 kV MV multi-core cables b) 200 mm diameter – for 11 kV MV single core cables laid in trefoil formation. A suitable number of pipes/ducts need to be prepared for current and future use. A draw wire shall be provided for each duct to facilitate cable laying. All cable pipes/ducts should be sealed to prevent water from entering the substation.
4
76
Substation Design Manual
4
For 11/0.433 kV substations, two layers of three PVC Class B 150 mm diameter pipes need to be laid from the trenches until they reach beyond the drain and/or road kerb. For 11 kV SSU, 1 layer of three PVC 200 mm diameter pipes and 1 layer of four PVC 150 mm diameter pipes are needed. For drainage crossings, G.I. pipes need to be used as a protective sleeve. However, only multi-core cables and single-core cables laid in trefoil are allowed in G.I. pipes. It cannot be used with single core cables laid singularly (alone) due to induced and circulating eddy currents in the G.I. pipes.
4.2.4.3.2.
Transformer Guard and Bushing Cover
All transformer bushings should be shrouded with transformer bushing covers. Additionally, transformer guard needs to be installed at all transformers in substations because: No live parts should be exposed without a barricade There is still voltage potential on the bushing covers To protect the metering CT which is connected at the LV cable support bracket
Transformer guard
Figure 4-16: Transformer guard
P/E, 11 kV SSU and S/S Design
4.2.4.3.3.
77
Feeder Pillar
The feeder pillar must be installed outside the substation building to facilitate access by fault finders and the LV maintenance team during breakdown or shutdown. 4.2.4.3.4.
Metering CT for LV Bulk Customer
For LV bulk customer, the metering current transformer (CT) is installed on the LV service cable connected to the secondary side of the transformer. Metering CT provides current readings to an energy meter through 2 2.5 mm 12-core copper multi-core cables. LV cable support brackets are used to support the LV Cable and the metering CT as shown in Figure 4-17. 2 Connections between meter and CT will use 2.5 mm , PVC/SWA/PVC, 12-core, copper multi-core armoured cables. Table 4-7: The maximum allowable distance between metering CTs and metering cubicle for LV consumer CT Burden (VA)
Secondary Rated Current (A)
7.5 7.5
5 5
Cross Connection of Conductor 2 (mm ) 2.5 4.0
Figure 4-17: CT on the cable support bracket
Maximum Distance Allowable (m) 12.0 20.0
4
78
Substation Design Manual
4.2.4.3.5.
4
For metering installations up to 33 kV, current (CT) and potential transformers (PT) shall be provided and installed by TNB at TNB's outgoing switchgear feeder. 2 2 Connections between meter and CT will use 2.5 mm or 4.0 mm , PVC/SWA/PVC, 12-core, copper multi-core armoured cables, depending on maximum allowable distance as in Table 4-8. The armoured cable shall not be buried or enclosed, and preferably laid on cable trays.
4.2.4.3.6.
Metering CT for MV Consumer
Metering CT for HV Consumer
A ‘marshalling box’ with independent sealing facility shall be provided by the consumer for the purpose of terminating the secondary circuit cabling of the CT and PT. 2 Connections between meter and CT will use 2.5 or 4.0 mm , PVC/SWA/PVC, 12-core, copper multi-core armoured cables, depending on maximum allowable distance between CT and meter as in Table 4-8. For metering installations of 132 kV and above, CTs and PTs shall be provided and installed by the consumer at consumer’s incoming switchgear in accordance with TNB’s specifications. TNB shall witness the commissioning tests of both CTs and PTs. Table 4-8: The maximum allowable distance between metering CTs and metering cubicle for MV and HV consumer CT burden (VA) 15 15 30 30 30 30
Secondary rated current (Amps) 5 5 5 5 1 1
Cross-sectional area 2 of conductor (mm ) 2.5 4.0 2.5 4.0 2.5 4.0
Maximum allowable distance (m) 30 47 65 100 1,647 2,545
Where meter burden for current circuit = 0.5 VA/ph
Calculations of the maximum allowable distance between metering CT and metering cubicle can be found in Appendix A.
P/E, 11 kV SSU and S/S Design
4.2.4.3.7.
79
Earthing System
Copper tape/strip of 25 mm wide x 3 mm thick (1” x 1/8”) is used as the earthing conductor. The copper strip should be installed on the side wall of the concrete trench wall, 60 mm from the top of the trench to prevent theft. Earthing layouts for different substations are shown in Subchapter 9.2.3.
60mm
4 Copper strip
Figure 4-18: Copper strip for earthing in a concrete trench 4.2.4.3.8.
Operating Equipment
The substation should be provided with its own respective operating equipment such as the operating gear and earthing gear. The equipment should either be stored on racks or placed in a cabinet. 4.2.4.3.9.
Fire Fighting System
Fire extinguishing equipment should be located near the entrance of the building. If automatic equipment is used, there should be means of switching off the equipment when work is being carried out in the substation. This is typically done through a fire-fighting control panel. For attached substations, fire-fighting equipment is installed inside the substation building structure. Detailed guidelines are presented in Chapter 10: Fire Fighting System and Pekeliling A08/2011.
80
Substation Design Manual
4.2.4.3.10.
4
Single phase wiring is required to be done with G.I. conduit complete with main-switch, ELCB, MCB Distribution Board and separate earthing. The source of supply is from the feeder pillar. Wiring in conduits for the Earth Fault Indicator (EFI) should be provided inside the switchgear room. Adequate lighting points should be provided and power socket outlets should be installed at convenient locations for the use of hand lamps, hand tools, etc. Emergency lighting is also required inside the substation with its own battery capable of supplying three hour of backup power to the emergency light. External lighting should utilise weather proof light fittings and operated via a photoelectric control unit (PECU).
4.2.4.4. 4.2.4.4.1.
Finishes Colour
Selection of colours should be harmonized with the surrounding environment such that they blend/match the neighbouring structures.
4.2.4.4.2.
Lighting, Fittings and Wiring
Signboard/Signage
A signboard containing the name of the substation must be installed at the front of the substation, facing the nearest road. The signboard should be installed at eye level for easy identification (around 1800 mm from floor level). Appropriate warning signs should be posted on the substation’s barrier fence. Substations, no matter how small, should have one sign per side, as a minimum. For each substation site, assess whether standard signs are sufficient. Special bilingual signs may be advisable for some areas.
P/E, 11 kV SSU and S/S Design
Head protection
No smoking
Body protection
Hand protection
Foot protection
Eye protection
Figure 4-19: Standardised signboard containing substation details 1245 20
20
505
20
330
330
20 20 155 20 155 20 210
1005
20 210 20 155 20 155 155 155 155 20 155 20 155 20 155 20 20 20 20 20
Figure 4-20: Standardised signboard dimensions
240
81
200
200
150
150
240
Figure 4-21: Standardised warning and electrical hazard signs
4
82
Substation Design Manual
4.3.
11 kV Primary Switching Station (11 kV SSU)
4.3.1.
Overview
Essentially, the 11 kV Primary Switching Station or Stesen Suis Utama (11 kV SSU) is a switching station which is installed with 12 kV, 630 A, 30 VDC VCB panels, with or without distribution transformers. Additionally, it must also be installed with a bus-section panel.
4
11 kV SSU is built for the following functions: As a switching station To give bulk supply to 11 kV customers To give LV supply via 11/0.433 kV distribution transformer Incoming VCB
Incoming
VCB
Outgoing
Figure 4-22: Example single line diagram for primary switching station (11 kV SSU) without transformer
Incoming
VCB
Incoming
VCB
Outgoing
Figure 4-23: Example single line diagram for primary switching station (11 kV SSU) with transformer
P/E, 11 kV SSU and S/S Design
83
4
Figure 4-24: Primary switching station (11 kV SSU)
4.3.2.
11 kV SSU Layout
The building features and civil criteria are similar as those for the indoor distribution substation in Subchapter 4.2.4. The difference is in the dimension of the building and rooms. Please refer to ESAH for details on the dimension and layout arrangement. The 11 kV SSU consists of: Switchgear room with bus-section Transformer room (as required) Battery room Metering room (as required) The number of VCB panels that can be erected in an SSU is subjected to the maximum load duty of the DC charger and battery. Typically one unit of a 30 VDC, 10 A charger with 40 Ah battery can cater for a maximum number of 5 VCB panels. However, the actual allowable number of panels can be determined by calculating the DC load profile duty cycle using IEEE 1118.
84
Substation Design Manual
Switchgears with bus-section
Underground cable trench
Ventilation blocks
Insulating mat
4
RCB LV feeder underground cables
Figure 4-25: Layout of 11 kV SSU
4.3.3.
Electrical Criteria
Table 4-9 summarises the standard electrical ratings for equipment in the indoor substation. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-9: Major components in an 11 kV SSU Primary Equipment
-
Secondary Equipment
- Battery / Battery Charger - Remote Terminal Unit (RTU)
Switchgear (VCB only) Transformer (if required) Feeder pillar (for SSU with transformer only) Power cables
P/E, 11 kV SSU and S/S Design
4.4.
Outdoor Distribution Substation (Outdoor P/E)
4.4.1.
Overview
85
Outdoor substations (Outdoor P/E) are similar in function to their indoor counterparts. Outdoor P/E are favoured for their cost advantages, and used mainly for rural electrification and system improvement. They are also used for industries that have very large land areas such as farms. The advantages of outdoor and semi-outdoor type substation are: Low cost Require smaller land area Easy and fast to install
incoming
outgoing
RMU 11 kV, 630 A Transformer 11/0.433 kV
Feeder Pillar 1600A/800A
Figure 4-26: Single line diagram for outdoor distribution substation
4
86
Substation Design Manual
4.4.2.
Outdoor P/E Layout
Outdoor substation layout is similar to the indoor substation layout except that the equipment is in the open air.
Barbed wire
Roof
Ventilation blocks for walls
Switchgear Transformer guard
4
Transformer
Feeder pillar
Stone chips
Doors
Figure 4-27: Layout of outdoor substation and locations of major components The typical existing fencing is the chain link fence. However, for new and future installations, ventilation blocks are preferred for fencing because they partially conceal the outdoor substation from public view as well as contain splashes of oil and/or arcing resulting from any possible flashover. Additionally the solid structure helps to deter unauthorized entry more effectively A roof is erected for the switchgear to cover the RMU as a protection from direct sunlight and heavy rain as well as providing a comfortable area for working personnel.
P/E, 11 kV SSU and S/S Design
87
4
Figure 4-28: Typical outdoor substation with ventilation block fencing
Transformer
Switchgear
Feeder Pillar
Figure 4-29: Typical outdoor substation with chain link fencing
88
Substation Design Manual
4.4.3.
Electrical Criteria
Table 4-10 summarises the standard electrical ratings for equipment in the outdoor substation. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-10: Typical ratings in an Outdoor P/E
4
Equipment/component
Rating and size
Voltage rating
11/0.433 kV
Transformer installed capacity
300 kVA, 500 kVA, 750 kVA, 1000 kVA
Switchgear
12 kV Ring Main Unit (RMU)
4.4.4.
Civil Criteria
In general the construction of outdoor substations should follow the civil requirements stated here. 4.4.4.1. 4.4.4.1.1.
Land Requirement
Under normal circumstances the minimum land size required for an Outdoor P/E is 7620 mm x 7620 mm (25 ft x 25 ft). Total land size including drainage is 8400 mm x 8400 mm (27.5ft x 27.5ft). The land area of the substation shall be raised by 100mm above the road level to prevent water flow into the substation and for ease of transportation.
4.4.4.1.2.
Compound Area
Plinth
Plinths shall be designed to cater for the loads as described below: Equipment
Plinth load
Transformer
1.4 x transformer weight Nominally 7000 kg
Outdoor Switchgear (RMU)
5000 kg
Feeder Pillar
1000 kg
P/E, 11 kV SSU and S/S Design
89
All plinths should have at least 150 mm above ground level. Plinth may need to be taller depending on special site requirements such as flooding.
4
Figure 4-30: Suggested switchgear plinth dimensions
Figure 4-31: Suggested feeder pillar plinth dimensions
90
Substation Design Manual
4.4.4.1.3.
4
The substation floor surrounding the plinths must be covered with 150 mm of stone chips in order to limit the step and touch voltage levels to a safe value as the crushed stone layer provides an insulation in series with the body. Optionally, a layer of tarmac is allowable as long as it matches the required insulation level of the stone chips. Both stone chips and tarmac have similar function to the insulating mat in the indoor P/E. The additional benefit of using stone chips or tarmac is to reduce grass/vegetation growth.
4.4.4.2. 4.4.4.2.1.
Structures Roof
RMU used in outdoor substations are designed with IP54 ingress protection which means they are suitable for outdoor applications. However a roof should still be provided to cover the RMU for additional protection from direct sunlight and heavy rain as well as providing a comfortable working area for personnel. Ardex corrugated sheets can be used as the roof material because they are cheap, easy to install and durable.
4.4.4.2.2.
Floor
Fence/Wall
Ventilation blocks are to be used as walls for new installations and upgrading of the Outdoor P/E. The height of the walls needs to be at least 1800 mm to keep the substation equipment hidden from outside view. Installation of barbed wire on top of the wall can help to prevent unauthorised entry. Chain link fences can be used if the outdoor substation is located in an extremely low traffic area.
P/E, 11 kV SSU and S/S Design
4.4.4.2.3.
o
4.4.4.3.1.
Signboard/Signage
Suitable and sufficient signage as mentioned in Subchapter 4.2.4.4.2 must be installed.
4.4.4.3.
Doors
The door shall be erected preferably at 90 angle from the RMU location to enable quick exit in emergency situation during switching. Double leaf composite doors are to be used with the dimensions 1300 mm(W) x 1800 mm(H) each door.
4.4.4.2.5.
Drainage
Water drainage shall be provided at the corners of the walls at floor level to enable water to flow from within substation to the outside drainage.
4.4.4.2.4.
Installations Transformer Guard and Bushing Cover
Outdoor substations are more prone to entry by animals compared to indoor substations. As such, all transformer bushings are to be shrouded with transformer bushing covers to prevent interruption/tripping due to shorting by animals. Additionally, transformer guards also need to be installed as justified in Subchapter 4.2.4.3.2.
4.4.4.3.2.
Feeder Pillar
The feeder pillar is installed in a recessed part of the outdoor substation wall as in Figure 4-27. 4.4.4.3.3.
91
Earthing System
Copper tape/strip of 25 mm(W) x 3 mm thick (1”x1/8”) is used as the earthing conductor. The copper strip shall be direct buried in the ground. The earthing layout is shown in 9.2.3.3.
4
92
Substation Design Manual
4.4.5.
Safety Clearances
Outdoor P/E design should comply with the minimum working clearances presented in Subchapter 2.5. The proposed designs here have the following working clearances:
4
Clearance between transformer and wall/fence is 1500 mm. Clearance between switchgear and wall/fence is 495 mm.
P/E, 11 kV SSU and S/S Design
4.5.
93
Switching Station / Stesen Suis (S/S)
Switching stations or stesen suis (S/S) are built as part of system improvement to introduce switching or T-off points. They consist of RMU with three-switch (3S) configuration. The typical features of switching station are as follow:
Dimension : 3000 (L) x 3000 (W) mm Plinth able to support up to 5000 kg. Roof type: Ardex corrugated sheets. Civil criteria for outdoor substation for floor, plinth and roof can be applied to the switching station construction. Chain link fencing shall be built around the RMU to provide sufficient safety clearance.
Figure 4-32: Switching station / stesen suis (S/S)
4
94
Substation Design Manual
Figure 4-33 shows the location of a switching station in a single line diagram. When required, switches A and C can be turned on to provide feedback supply in the event of network failure.
4
S/S
NOP
NOP
A
B
C
Figure 4-33: Single line diagram of switching station
P/E, 11 kV SSU and S/S Design
4.6.
Compact Substation Unit (CSU)
4.6.1.
Overview
95
The Compact Substation Unit (CSU or Compact Sub) is a substation with type tested equipment comprising of a distribution transformer, medium voltage switchgear, low voltage feeder pillar, connections and associated equipment, all in a compact enclosed unit. A CSU is shown in Figure 4-34 and a basic line diagram is shown in Figure 4-35. Advantages of the CSU include: Require only a small site (7000 mm x 4000 mm); Physically small and therefore unobtrusive, and can be erected quickly; Available in 500 kVA and 1000 kVA capacities; Can be installed in a shorter time compared to a conventional substation. However, a disadvantage of the CSU is that if faults affect any individual component inside the unit, the whole unit may need to be replaced completely. Its capacity is also fixed and cannot be expanded. The CSU is also considerably more expensive than conventional substations. As such, the compact substation can only be considered as a last resort after all options have been exhausted on a case by case basis. It is considered as a special feature design in which special features cost is charged to the customer as per Clause 8.0 of Statement of Connection Charges 1994/1995. Circulars related to the compact substation unit are: 1. 2.
3.
A7-2004 Pekeliling Kejuruteraan & Logistik – Use Of Package or Compact Type 11 or 415 kV Substation In TNB Distribution Network A30-2009 Arahan Naib Presiden (Pembahagian) – Garis Panduan Penggunaan PE Padat Bersaiz 500 kVA Untuk Bekalan Elektrik Skim Pembangunan Perumahan A02-2011 Arahan Naib Presiden (Pembahagian) – Garis Panduan Penggunaan Pencawang Elektrik Padat Untuk Bekalan Elektrik Ke Kawasan Komersial
4
96
Substation Design Manual
4 Figure 4-34: A typical CSU
MV incoming
MV outgoing
RMU 11 kV, 630 A Transformer 11/0.433 kV
Feeder Pillar 800 A or 1600 A
Figure 4-35: Single line diagram of a CSU
P/E, 11 kV SSU and S/S Design
97
The technical and economic considerations in selecting CSU against standalone indoor type substations (P/E) can be summarised as follows: i. Demand estimates and demand growth to determine transformer size to be used ii. Space requirements, if any, notably by the developer iii. Aesthetic requirements, if any, notably by the developer and or local authority iv. Maintainability of components v. Life cycle costs comprising of capital cost, O&M cost, replacement and upgrading costs Other considerations may be satisfied during the design and planning stage. 4.6.1.1.
Application of CSU
Upon request from developer, CSU are allowed to be utilised for new housing and commercial developments, taking into consideration of appropriate distribution network design to ensure security and restoration time to consumers will not be affected. Additionally for all other situations, prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah) to deploy the CSU. Detailed explanations on the use of the CSU are as below. 4.6.1.2.
Development with Limited Land
In development areas that have limited land/space and cannot meet the minimum requirements of conventional standalone indoor substations, a compact substation can be considered. Examples would include instances of a temporary supply scheme, supply to street lighting along major roads, supply to major billboards or even supply to existing factories/outlets with limited available space. In these cases, the compact substation can normally be considered. Prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah)
4
98
Substation Design Manual
4.6.1.3.
Low Voltage Reinforcement of Existing Developed Area
Low voltage reinforcement of existing developed areas typically involves substation sites to be acquired by TNB. In case of this situation, the use of CSU is preferred subject to satisfying the following:
4
Insufficient space to construct a conventional indoor substation Cost of constructing a conventional indoor substation is more expensive compared to a CSU. A shorter duration of time is required to complete the low voltage reinforcement works.
Prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah) 4.6.1.4.
Temporary Use of the CSU
There are cases whereby CSU are used on a temporary basis for supply projects. These would include cases due to unavailability of certain materials or even due to demand/request from the customer/authorities to meet certain deadlines which may be ceremonial in nature etc. Prior approval must be obtained from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah). 4.6.1.5.
CSU for New Domestic Developments
CSU 500 kVA is encouraged to be installed for new domestic development with the following guideline:
CSU 500 kVA to be placed close to the load centre. CSU 500 kVA not to be placed at the corners of one development. CSU 500 kVA cannot be placed close to each other to ensure efficient load distribution to the consumers. CSU 500 kVA is considered as ‘special feature design schemes’ in which special features cost is charged to the consumer.
CSU with sizes bigger than 500 kVA for domestic development requires prior approval from the respective Regional Chief Engineer (Ketua Jurutera Operasi Wilayah).
P/E, 11 kV SSU and S/S Design
4.6.1.6.
99
CSU for New Commercial Developments
Both 500 kVA and 1000 kVA CSU are allowed (upon request by developer) to be used in commercial areas depending on the load requirements. However, application of CSU in commercial development is considered as special feature design schemes in which a special features cost is charged to the consumer.
4.6.2.
CSU Layout
The dimension and weight of CSU are dependent on the transformer size and manufacturer. Table 4-11 shows typical dimensions and weight of a compact substation. Figure 4-36 is a layout view of the CSU. Table 4-11: CSU dimensions and weight Height Overall length Overall width
Weight
LV Feeder Pillar
2000 mm 2500 mm 2000 mm Without transformer: 1300 kg With 500 kVA transformer: 3310 kg With 1000 kVA transformer: 4500 kg Nominally: 5000 kg
Transformer
RMU
2000
Doors
2500
Figure 4-36: Top view of a CSU
4
100
Substation Design Manual
RMU
MV transformer tail
4
Figure 4-37: RMU compartment in a CSU
Incoming disconnector unit
Outgoing fuse-switch disconnectors
Figure 4-38: LV feeder pillar compartment in a CSU
P/E, 11 kV SSU and S/S Design
101
RMU Compartment 630A 11 kV 3-phase 50 Hz
HRC fuse
11 kV in
4
11 kV out
Transformer Compartment 11 kV/433 V Transformer 1000 kVA
LV Feeder Pillar Compartment
1 x 1600 A Incoming Disconnector A
3 x CT 1600/5 A
PF
kWh
x3
(0-1600 A)
F 10 x 400 A Outgoing Fuse-switch Disconnector
Figure 4-39: Detailed single line diagram of 1000 kVA CSU
102
Substation Design Manual
4.6.3.
Electrical Criteria
The voltage rating for the CSU is 11kV/433V and is currently only available in 500 kVA and 1000 kVA capacities. A summary of compact substation specifications and dimensions are given in the table below. Table 4-12: CSU technical specifications, measurement and dimension Power Rating Input Unit Output Unit
4
LV Feeder Pillar Metering
Transformer
Switchgear
Type Voltage Type Insulation Rated Voltage Rated Current
Kiosk/Enclosure Dimensions
4.6.4.
Cover Base
500 kVA 1000 kVA 1 x 800 A 1 x 1600 A 6 x 400 A 10 x 400 A CT, class 1.0, 7.5 VA Ammeter Power factor meter kWh meter Hermetically Sealed/Oil 11kV/433V Ring Main Unit (RMU) SF6 gas 12 kV Ring feeder – 630 A Transformer feeder – 200 A Mild steel Channel Steel
The overall maximum dimension for the enclosure should not 2 exceed 2.0 m height and 2.5 m x 2.0 m or 5.0 m sitting area
Civil Criteria
The following are guidelines to provide proper working environment for the equipment and personnel working around the CSU. The criteria mentioned here is applicable to both the 500 kVA and 1000 kVA CSU. 4.6.4.1.
Land Requirement
The required land area for a compact substation is 7000 x 4000 mm. This consists of the plinth and working clearance around the CSU.
P/E, 11 kV SSU and S/S Design
4.6.4.2.
103
Plinth
Minimum size of the CSU plinth is 4600 x 2200 mm. The CSU sits in the middle of the plinth and it must be able to support the weight of the CSU which is approximately calculated as 1.4 x 5000 kg = 7000 kg. The specification of the plinth shall be as in Figure 4-40 and Figure 4-41 below. Proper plinth design is important to ease cable laying and termination to the CSU. earth strip embedded in concrete plinth with earthing rod in earthing chamber 200x200mm
100
1000
100 150 100
150
460
150
400
A
Removable Concrete Removable Slab Concrete Slab
400
1600 1600
400
700
460
Trench Opening LVTrench cable Opening Termination
400
400
100
1000 900
100
150 150
300
A
150
770
1230
400
Trench Opening Trench 11kV cable Opening Termination 11kV cable
LV cable Termination
Termination
Removable Concrete
Removable Slab Concrete Slab
300
A 400
400
980
2200 2200
400
400
400
A
700
980
400
400
460
460
700
700
150150
300
150150
Foundation/RC structure to structural engineer’s details
Figure 4-40: Compact substation plinth (top view) Compact Sub
Compact Sub
900
900
100
Angle Iron Angle 50mm x 50mm
800 300
800
300
150
Iron 50mm x 50mm
2 layers 4 nos 150mmp 2 layerscable chute
600
600
900
900
100
4 nos 150mmp cable chute
150
100 50
100 50
800
800
Trench diisi dengan pasir
50 100
400
400
1230
1230
100mm thick concrete slab
800
800
Trench diisi dengan pasir
100 50
770
770
100mm thick concrete slab 1000
Trench diisi dengan pasir
Foundation/RC structure to structural engineer’s details
Trench diisi dengan pasir
50 100
Cement Ready-Mix Grade 25
100 50
4
Opening
100
1000 900
100
4600
1000 900
770
1230
400
900 100
300
Opening
Earth strip embedded in concrete plinth with earth strip embedded4600 in concrete plinth earthing rod earthing chamber 200 x 200 mm with in earthing rod in earthing chamber 200x200mm
2 layer 2 nos 150mmp cable chute
2 layer 2 nos 150mmp cable chute
150mm 1000 thick trench base on 50mm thick 150mm screed thick trench
base on 50mm thick screed
50 100
800
800
50 100
Figure 4-41: Compact substation plinth (side view – Section A-A)
104
Substation Design Manual
The area around substation plinth can be filled with crusher run and a thin layer of premix to ease maintenance work in a future and prevent unwanted vegetation growth.
4.6.4.3.
4
Compound Area
CSU do not require fencing because it complies with the Internal Arc Classification Class B requirement which is safe for the public in the event of fault occurring in the RMU. Developers/consumers are allowed to plant trees outside of the CSU site to help it blend into the surrounding area. However it should be provided that the 2 meters wide access road to the substation site is not blocked. Suitable and sufficient signage as mentioned in Subchapter 4.2.4.4.2 must be installed.
Figure 4-42: CSU with decorative plants
P/E, 11 kV SSU and S/S Design
4.7.
Pole Mounted Substation (PAT)
4.7.1.
Overview
105
Pole-mounted substations or Pencawang Atas Tiang (PAT), also known as H-pole substations, contain substation components and equipment that are safely and securely mounted on pre-stressed spun concrete poles. Polemounted substation designs can be used for both 33 kV and 11 kV systems to be stepped down to LV. It is the most economical substation because it does not require any high voltage switchgear and utilises only a small piece of land. These substations can also be erected in a very short amount of time due to its simple design and construction requirements. PATs are suitable for rural areas where the load density is low. At the same time, a larger number of these small capacity substations may be required to satisfy customer demand. Pole-mounted substations can be considered for the following conditions:
Flood prone areas Rural area with low load consumption (below 300 kVA) Limited land area
The disadvantages of PAT are that they are not encouraged as a permanent solution and not more than 3 such substations may be erected in series.
4
106
Substation Design Manual
As can be seen in the single line diagram in Figure 4-43, the PAT is connected to 11 kV or 33 kV MV feeders, preferably isolated by 3-pole switches, protected by external drop-out fuses, feeding to a transformer which steps down voltage to be distributed via an LV feeder pillar. Optionally, LV may be distributed through a fuse-switch disconnector (black-box) as shown in Figure 4-44.
4
MV incoming
Isolator link
MV outgoing
Isolator link
Lightning arrester
EDO Fuse
Distribution transformer Feeder Pillar Link switch
Fuse-switch disconnector
Figure 4-43: Single line diagram for pole-mounted substation connected to feeder pillar with MV isolator link
P/E, 11 kV SSU and S/S Design
MV incoming
Isolator link
107
MV outgoing
Isolator link
4
EDO fuse
Lightning arrester
Distribution transformer
Fuse-switch disconnector
Figure 4-44: Single line diagram for pole-mounted substation connected to fuse-switch disconnector (Black box) with MV isolator link
108
Substation Design Manual
4.7.2.
PAT Layout
4.7.2.1.
Major Components
Major components on the pole-mounted substation and their functions are listed in Table 4-13 and each component is shown on the poles in Figure 4-45 through Figure 4-49. Table 4-13: Pole-mounted substation major components and their functions No
4
Component/Equipment
Function
1
MV underground and MV ABC cables
As the incoming and outgoing of the substations
2
Covered jumper conductors
As a T-off Interconnector between equipment /component
3a
Isolator link
To provide isolation Must only be operated during off-load condition
3b
SF6 Load Break Switch (LBS)
Alternative to isolator link to provide isolation Can be operated in on-load conditions Some have the facility to earth the circuit
4
Lightning arrester
To discharge lightning strikes and protect transformer
5
Expulsion Drop-Out (EDO) fuse
Provides fused protection of the transformer The fuse will operate and provide isolation when there is a fault on the HV and LV side of the transformer
6
Insulating covers
Covers exposed parts of live components to prevent interruption of supply due to shorting caused by animals.
7
Distribution transformer
Transforms the MV voltage 33/0.433 kV or 11/0.433 kV
8
Fuse-switch disconnector 400 A (black box)
To provide isolation Provides fused protection of the downstream circuit by disconnecting immediately upon fault
9
Feeder pillar (FP)
To provide isolation Provides fused protection of outgoing circuits Electricity distribution point for LV system
P/E, 11 kV SSU and S/S Design
(3a) Isolator link
(2) Covered jumper conductors
(4) Lightning arrester (1) Underground MV cable
109
(5) EDO fuse
(6) Insulating covers
(7) Distribution transformer
Figure 4-45: Major components on the pole-mounted substation
4
110
Substation Design Manual
4
Figure 4-46: Fuse-switch disconnector on the pole-mounted substation
Feeder pillar LV feeders
Figure 4-47: Feeder pillar used with the pole-mounted substation
P/E, 11 kV SSU and S/S Design
111
Pin Isolator
Lightning arrestor Jumper Conductor EDO Fuse Isolator Link with animal guard Anti climbing device EFI
Figure 4-48: Typical 11 kV pole-mounted substation layout
4
112
Substation Design Manual
4
Figure 4-49: Typical 33 kV pole-mounted substation layout
P/E, 11 kV SSU and S/S Design
4.7.2.2.
113
Types of PAT
Generally, PAT can be classified into two types, 2-pole and 4-pole structures. The number of poles used in an H-pole structure is determined by the weight of the distribution transformer to be installed on it.
The type of pole used is 10 meter spun concrete pole (5 kN cantilever strength). Typically, 2-pole structures are sufficient to support 100 kVA transformers for both 33/0.433 kV and 11/0.433 kV. For 300 kVA and larger transformers for both 33/0.433 kV and 11/0.433 kV, the 4-pole structure is needed to cater for the additional weight. An example is shown in Figure 4-50. 33 kV link unit / isolator links are heavy and thus require a 4-pole structure.
Figure 4-50: 4-pole structure 11 kV PAT
4
114
Substation Design Manual
U-shaped channel irons are used to support the transformer, lightning arrester, EDO fuse and pin insulators on the pole. Channel iron dimensions and distance between the poles depend on the system voltage level as per Table 4-14. Equipment for 33 kV are larger and thus longer channel irons are required. Table 4-14: Sizes of channel Iron Pole-mounted System voltage level
Dimension of channel iron Length x Width x Height (mm)
Distance between the poles (centre-to-centre)
11 kV system
2500 x 100 x 50
1800mm
33 kV system
2800 x 100 x 50
2200mm
4
The number of channel irons required to support the transformer on the pole differs for each type of pole-mounted substation as follows:
2-pole structure requires minimum 2 pieces of channel irons. 4-pole structure requires minimum 7 pieces of channel irons.
Wooden cross arms, as shown in Figure 4-51, are forbidden to be used to substitute channel irons as an effort to reduce tripping of the system due to animals. This is because wooden cross arm is susceptible to decay especially when inferior wood is used.
P/E, 11 kV SSU and S/S Design
115
Wooden cross arms
4
Figure 4-51: Wooden cross arms shall not be used to replace channel irons
4.7.2.3.
Insulating Covers
All pole-mounted substations must be installed with insulating covers. These covers are used to cover the exposed parts of live components to prevent interruption of supply due to shorting between live parts or between live parts to earth by animals. The insulating covers are designed to be UV resistant and anti tracking since they will be used outdoors. There are 5 types of insulating covers to be used on PATs listed here and shown in Figure 4-52: 1. 2. 3. 4. 5.
Animal guard Conductor cover Lightning arrester cover Drop out fuse cover Transformer bushing cover
116
Substation Design Manual
(1) Animal guard
4 (2) Conductor cover
(3) Lightning arrester cover
6
(4) Drop out fuse cover
(5) Transformer bushing cover 7
Figure 4-52: Insulating covers for equipment on the PAT
P/E, 11 kV SSU and S/S Design
4.7.3.
117
Electrical Criteria
Table 4-15 summarises the standard electrical ratings for equipment on the 33 kV and 11 kV PAT. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-15: Pole-mounted substation ratings Equipment/component Transformer rating Tx installed capacity Isolator link
Rating 33/0.433 kV
11/0.433 kV
Expulsion Drop-Out (EDO) fuse
100 or 300 kVA Rated voltage: 36 kV Rated voltage: 12 kV Rated continuous current: 400 A Rated voltage: 36 kV Rated voltage: 12 kV Fault making capability: Fault making capability: 25 kA, 3s 20 kA, 3s Rated continuous current: 400 A Rated voltage: 36 kV Rated voltage: 12 kV Maximum Continuous Maximum Continuous Operating Voltage, Operating Voltage, MCOV = 29 kV MCOV = 9.6 kV Standard Nominal Discharge Current = 10 kA Line Discharge Class = Class 1 Rated voltage: 36 kV Rated voltage: 12 kV Rated continuous current = 100 A
Fuse-switch disconnector
Rated continuous current = 400 A
Feeder pillar (FP) MV underground cable
Rated continuous current = 400 A, 800 A, 1600 A Incoming and outgoing: Incoming and outgoing: 2 150 mm Silmalec bare 11kV XLPE 3C Al cable conductor or 33 kV ABC encased in 150 mm G.I. pipe or PVC Class B pipe 2 2 ABC, 33 kV 3 x 150 mm Al ABC, 11 kV 3 x 150 mm Al Connection to feeder pillar: LV XLPE, 4-core, 185 mm2, Al (for 100 kVA transformer) PVC/PVC, 1-core, 300 mm2, Al encased in 150 mm G.I. Pipe or PVC Class B pipe (for 300 kVA transformer) Connection to fuse switch disconnector: ABC LV 3x95 mm2 + 1x70 mm2 (for 100 kVA transformer) ABC LV 3x185mm2 + 1x120mm2 (for 300 kVA transformer) The outgoing cable from the fuse switch disconnector that connects to the first pole is typically LV XLPE, 4-core, 2 185 mm , Al underground cable
SF6 Load Break Switch (LBS)
Lightning arrester
Jumper conductor LV underground cable
4
118
Substation Design Manual
4.7.4.
Civil Criteria
The following are guidelines of typical civil requirements to provide proper working environment for the equipment and personnel working around the pole-mounted substation. Guidelines provided here are also applicable to all other substations with pole structures. 4.7.4.1.
4
4.7.4.1.1.
Structures Concrete Footing
The pole should be planted 1800 mm deep in the ground. Underground concrete footing is required as a support base for each pole. The dimension of the concrete footing is 760 (L) x 760 (W) x 760 (H) mm. 4.7.4.1.2.
Stay Wires
Usually, 4 numbers of stay wires are used to support the 2-pole structure. For 2 33 kV PAT where the primary incoming cable uses bare conductor 150 mm , Silmalec, the pole structure is to be supported by 4 numbers of stay wires (45 tonne, SWG 7/8).
Legend: Pole Transformer Stay wire
Main Road Figure 4-53: Stay wire (top view)
P/E, 11 kV SSU and S/S Design
4.7.4.1.3.
119
Concrete Base
For area that has limited space for stay wires, a concrete base (concrete grade 25) is used to support the structure. The dimension of the base depends on the system voltage level as shown in the following table. Table 4-16: PAT concrete base dimensions PAT system voltage
Dimension of concrete base
11 kV system
300 (H) x 760 (W) x 2600 (L) mm
33 kV system
300 (H) x 760 (W) x 3400 (L) mm
Concrete base
Concrete footing
Figure 4-54: Concrete base and footing for 11 kV PAT
4
120
Substation Design Manual
4.7.4.2. 4.7.4.2.1.
Installations Isolator for Incoming and Outgoing
Typically, direct connection from incoming cable to the jumper is widely practiced. However the use of isolator link or SF6 Load Break Switch (LBS) is preferred at both incoming and outgoing cables for ease of isolation as it can be operated in on-load condition.
4
SF6 load break switch
Figure 4-55: H-pole using SF6 Load Break Switch (LBS)
P/E, 11 kV SSU and S/S Design
4.7.4.2.2.
121
Lightning Arrester
Lightning arresters must be installed at HV jumper and at the first pole of LV overhead system. 4.7.4.2.3.
MV Feeder Cables
Buried underground cables are preferably used for feeder cables instead of overhead cables to connect to the first pole. This practice is to prevent animals like squirrels and monkeys from reaching the pole-mounted substation via any overhead line. All underground cables entering and leaving the PAT should be encased in 150 mm G.I. pipe or PVC class B pipe (3 m long, with 2.7 m above ground and 0.3 m underground) and attached to the pole for cable protection. All cable terminations must be of a type/brand pre-approved by TNB for use in the distribution system. For 11 kV connections the incoming and outgoing feeders use XLPE, 3-core, 2 150 mm , aluminium underground cables. Sometimes, the incoming cables consist of 11 kV ABC. For 33 kV connections, the incoming and outgoing feeders typically use 2 150 mm Silmalec or 33 kV ABC overhead cables, as the 33 kV PAT’s usually tap off from existing 33 kV overhead system to give LV supply to nearby areas. 4.7.4.2.4.
LV Feeder Cables
For LV system, typical connection from the secondary side of the transformer to the fuse switch disconnector or feeder pillar is shown below: Table 4-17: LV feeder cables specifications LV distribution equipment used
Typical cable connection from secondary side of transformer 100 kVA transformer
300 kVA transformer
Fuse switch disconnector 400 A
LV ABC, 2 2 3x95 mm + 1x70 mm
LV ABC, 2 2 3x185 mm + 1x120 mm
Feeder pillar
LV XLPE, 2 4-core, 185 mm , Al underground cable
LV PVC/PVC, 2 1-core, 300 mm , Al underground cable
4
122
Substation Design Manual
To achieve buried connection to the first pole of the low voltage overhead system for prevention of animal encroachment, the outgoing cable from the fuse switch disconnector that connects to the first pole is typically LV XLPE, 42 core, 185 mm , Aluminium underground cable. Underground cables should be mechanically protected from external factors by encasing them in:
4
Type of pipe: 150 mm G.I. pipe or 150 mm PVC class B pipe Recommended length: 3 m with 2.7 m above ground and 0.3 m underground
The single core cables must be laid in trefoil and must not be laid singularly (alone) in a G.I. pipe. This is to avoid induced and circulation currents in the G.I. pipe. Due to the height of the transformer on the PAT, the stressing effect of the weight of the connected cables to the LV transformer bushings, especially when LV underground cables are used, can be damaging to the bushings. Hence, proper and sufficient cable clamping must be provided to support the weight of the LV transformer tail. All cable terminations must be of a type/brand pre-approved by TNB for use in the distribution system.
P/E, 11 kV SSU and S/S Design
4.7.4.2.5.
123
Jumper Conductors
Jumper conductors connect the incoming cable to the lightning arrester, down to the EDO fuse and then to the HV bushing of the transformer. The conductors used are typically:
2
For 33 kV PAT – ABC, 33 kV 3x150 mm , Aluminium 2 For 11 kV PAT – ABC, 11 kV 3x150 mm , Aluminium
Jumper conductors are essentially covered conductors as they are unscreened and therefore have potential on them. As such, sufficient clearance must be ensured from the jumper conductors to any earthed metallic/conductive bodies on the pole.
4.7.4.2.6.
Feeder Pillars and Fuse-Switch Disconnectors
Fuse-switch disconnectors (black box) are widely used for connection to LV feeders. However, the use of a feeder pillar is also allowable to provide more outgoing LV feeders for better load distribution. Using several fuse-switch disconnectors to achieve this has the disadvantage of being prone to lose contact issue as several LV cables will be connected to a transformer bushing.
4.7.4.3.
Safety and Signage
Anti-climbing devices should be fitted at the pole section below the transformer channel iron base. This is to prevent excess to the high voltage zone. Substation signage with danger notices must be prominently displayed below the transformer channel iron base.
4
124
4
Substation Design Manual
Anti-climbing device
Substation signage
Figure 4-56: Substation signage
4.7.5.
Safety Clearances
(a) Ensure that under all possible conditions, the clearance from the ground level or any adjacent object which a member of the public can stand upon to the lowest live terminal is at least 3 meters. (b) Any un-insulated wires running down the pole for earthing purposes must be insulated or guarded in some way for at least 3 meters above the ground level. (c) Stay wires fitted to the pole should have insulators installed at least 3 meters above the ground level.
P/E, 11 kV SSU and S/S Design
4.8.
Pole Mounted Substation (PAT) with RMU
4.8.1.
Overview
125
Pole mounted substations (PAT) with insulating cover and ring main units (RMU) is a combination of insulated pole-mounted with outdoor substation for the 11 kV system. The advantages of the PAT and RMU are ease of operation, suitable to limited land area and cheaper construction costs compared to outdoor P/E. However, it is important to ensure that permission to use the appropriate land area is obtained from the local authorities. RMU 11 kV, 630 A 11 kV incoming
11 kV outgoing
Distribution transformer Fuse-switch disconnector
Figure 4-57: Single line diagram for PAT with RMU connected to fuse-switch disconnector
4
126
Substation Design Manual
RMU 11 kV, 630 A 11 kV incoming
11 kV outgoing
4
Transformer 11/0.433 kV
Feeder Pillar 1600A/800A
Figure 4-58: Single line diagram for PAT with RMU connected to feeder pillar
P/E, 11 kV SSU and S/S Design
4.8.2.
127
Layout of PAT with RMU
Main components on the PAT with RMU are similar to the standard polemounted substation. However a Ring Main Unit (RMU) functions as the isolating component.
Transformer bushing covers Transformer
RMU
Feeder pillar
Figure 4-59: Layout of PAT with RMU and fuse-switch disconnector
4
128
Substation Design Manual
4.8.3.
Electrical Criteria
Table 4-18 summarises the standard electrical ratings for equipment on the PAT with RMU. All electrical clearances presented in Subchapter 2.5 must be adhered to. Table 4-18: Major components in a PAT with RMU Equipment/component
4
Typical rating and size
Transformer
11kV/433V, 100, 300, kVA
RMU
12 kV, 630 A Configuration 2L + 1T
MV underground cable
Incoming and outgoing: 11 kV 3C cable encased in 2
150 mm G.I. Pipe (1.8m long)
Transformer T-off: 11 kV, XLPE, 3C, 70 mm2, Al, 2
encased in 150 mm G.I. Pipe (1.8 m long) as riser going up the pole LV underground cable
Connection to feeder pillar
LV XLPE, 4-core, 185 mm2, Al (for 100 kVA transformer)
PVC/PVC, 1-core, 300 mm2, Al encased in 150 2
mm GI pipe or PVC Class B pipe (for 300 kVA transformer) Connection to fuse switch disconnector
LV ABC 3 x 95 mm2 + 1 x 70 mm2 (for 100 kVA transformer)
LV ABC 3 x 185 mm2 + 1 x 120 mm2 (for 300 kVA transformer)
The outgoing cable from the fuse switch disconnector that connects to the first pole is 2 typically LV XLPE, 4-core, 185 mm , Al underground cable Fuse-switch disconnector
400 A
Feeder pillar (FP)
400 A 800 A 1600 A
P/E, 11 kV SSU and S/S Design
4.8.4.
129
Civil Criteria
The following are guidelines of typical civil requirements to provide proper working environment for the equipment and personnel working around the pole-mounted substation with RMU. In general, the construction of this substation should follow the guides presented in Subchapter 4.4 on outdoor substation structures and Subchapter 4.7 on pole-mounted substations. Table 4-19: Civil requirements of PAT with RMU Item
Minimum requirement
Size/dimension
Land size : 4000 (L) x 3000 (W) mm
Support structure
Switchgear area
Dimension : 3000 (L) x 3000 (W) mm Plinth able to support up to 5000 kg Roof type: Ardex corrugated sheets will be used Chain link fencing shall be built around the RMU and H-pole structure
LV system connection
Buried LV underground cables are used as the outgoing cables instead of LV overhead cable from the fuse-switch disconnector to the first pole. This practice is to prevent animals like squirrels and monkeys from reaching the pole-mounted substation via the LV overhead cable.
2-pole structure: To support up to 100 kVA transformer 2 spun pole 10 m (5 kN cantilever strength) The transformer is mounted on 2 channel irons/Uchannel** 4-pole structure: To support 300 kVA transformer 4 spun poles 10 m (5 kN cantilever strength) The transformer is mounted on 7 channel irons/ Uchannel** Pole to pole distance is 1800 mm **size for channel iron: - 11 kV : 2500 mm(L) x 100 mm (W) x 50 mm(H)
Compound area
Safety signage
Suitable and sufficient signage as mentioned in Subchapter
Civil criteria for outdoor substation for floor, plinth and roof can be applied to the PAT with RMU construction as in Subchapter 4.4.4.1. 4.2.4.4.2 must be mounted on the PAT (below the transformer channel iron base) or on the fencing of the switchgear area.
4
130
Substation Design Manual
Chapter 5: Design for Substations with Special Requirements This chapter presents general information concerning the design of the Mobile Switching Station / Stesen Suis Utama Bergerak (Mobile SSU) and mitigation methods for substations located in flood prone areas. It describes configurations, illustrates typical layouts, and presents technical criteria of these stations.
5
5.1.
Mobile SSU
5.1.1.
Overview
A mobile unit substation or mobile transformer is one in which all the components are mounted on a highway trailer. These units may be readily moved from one location to another by a prime mover. The Mobile SSU provides a preconfigured, plug‐and‐play package that minimizes installation time, effort and risk. It consists of a metal enclosure, containing all the substation‐related elements, including the Medium Voltage cubicles, low voltage distribution board, battery charger and other auxiliary devices. The Mobile SSU was introduced to perform the main functions as below: (a) To provide temporary supply for new projects while a permanent substation is being constructed. (b) To assist in improving SAIDI as it is an alternative for quick supply restoration by: i. Diverting the network through the Mobile SSU to ensure continuity of supply while a PPU undergoes rehabilitation/renovation works. ii. Providing temporary supply by replacing whole or part of a PPU which may be affected by any breakdown of the PPU equipment.
Design for Substations with Special Requirements
131
The Mobile SSU enables TNB to fulfil its commitment for high network reliability which in turn would enhance TNB’s service level. The advantages of the Mobile SSU are:
High mobility and fast connectivity to the distribution network. Minimises civil engineering work; fully assembled and tested in the factory, ensuring an optimum level of quality and reliability. Requires a small area of 13 m x 3 m to station the container.
5
Figure 5-1: Two Mobile SSU units
33kV S/G
3
2
11kV S/G
1
1
2
3
4
5
6
7
8
Mobile SSU
On-Site Transformer
Figure 5-2: Mobile SSU connected to an on-site transformer
132
Substation Design Manual
5.1.2.
Layout
All equipment for the Mobile SSU is contained inside a standard intermodal ISO container sized compartment, which is pulled on a trailer. Figure 5-3 below shows the dimension of the container. 12500 (41ft) Trailer Length
Landing Gear
Prime mover
5
2590 (8.5ft)
3940 (12.9ft) General height
1350 (4.4ft)
1820 (6ft) Track 2500 (8.2ft) Max width
Figure 5-3: Dimension of the container
Design for Substations with Special Requirements
133
Figure 5-4 below shows the locations of major components inside the Mobile SSU. A Mobile SSU typically consists of: 1.
2. 3.
4. 5. 6. 7. 8.
(1)
3 units of 33 kV GIS switching panels: (a) 1 incoming feeder (b) 1 outgoing feeder (c) 1 feeder to transformer 2 units of air-conditioning 7 units of 11 kV GIS switching panels: (a) 1 incoming feeder (from 33/11 kV transformer); and (b) 6 outgoing feeders 1 unit of marshalling cubicle for 33/11 kV transformer LVAC panel 10 Control and Relay Panels (CRP) for 33 kV and 11 kV switching panels Battery and battery charger compartment – the battery is either of sealed lead acid or compact dry and maintenance-free type. Fire fighting equipment
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Figure 5-4: Plan layout of the Mobile SSU All of the above components are installed in a standard 40 foot container sized 12.192 L x 2.438 W x 2.591 H meters (40’ 0” L x 8’ 0” W x 8’ 6” H feet). The container is also equipped with two air-conditioning units to ensure that the equipment is at optimal operating temperature. Each air-conditioning unit is operated alternately via auto-changeover switch to prolong their lifespan.
5
134
Substation Design Manual
The following figures show some of the equipment inside the Mobile SSU.
5
Figure 5-5: 11 kV GIS switching panels
Figure 5-6: 33 kV and 11 kV Control Relay Panels (CRP)
Design for Substations with Special Requirements
135
5
Figure 5-7: Low Voltage AC (LVAC) panel
Figure 5-8: Dry type battery cells in the battery compartment
136
Substation Design Manual
5
(a)
(b)
(c) Figure 5-9: Cable entry point into the GIS switchgears underneath the 2 2 2 Mobile SSU, (a) 3C x 240 mm , (b) 3 x 1C x 500 mm , (c) 3 x 1C x 630 mm
Design for Substations with Special Requirements
137
The Mobile SSU requires an external LV power source to provide supply to all LV instruments including battery charger and air conditioning. LV supply to the container is drawn from an external source and connected to the plug point located at the bottom of the container as shown in Figure 5-10.
5
Figure 5-10: LV supply plug point
Four earthing points are available on a Mobile SSU.
1 for 33 kV switchgears 1 for 11 kV switchgears 1 for CRP 1 for other equipment such as battery charger and LVAC
138
Substation Design Manual
These points shall be interconnected and then connected to a substation earth rod using proper earthing cables. Earthing connection methods are presented in Chapter 9.
5
Figure 5-11: Earthing Point
5.1.3.
Electrical Criteria
Table 5-1 summarises the standard electrical ratings for equipment in a Mobile SSU. PPUs typically have 10 to 14 feeders. The Mobile SSU is designed to supply for half-bus loads which is 7 feeders. Table 5-1: Ratings of Mobile SSU Item Voltage Busbar rating
Rating 33 kV & 11 kV single busbar 2000 A
33 kV Circuit Breaker rating
1250 A (for the transformer and feeders)
11 kV Circuit Breaker rating
2000 A for the transformer and 1250 A for the feeders
Short Time Withstand Rating
25 kA, 3 seconds
Internal Arc Rating
25 kA, 1 second
Design for Substations with Special Requirements
5.1.4.
139
Operating Specifications
The Mobile SSU conforms to the following standards and operating conditions: IEC 62271‐100, IEC 62271‐200 and IEC 62271‐102. 5.1.4.1.
Normal Service Condition
Operating temperature range The ambient temperature shall be in the range of –5°C to +40°C and the average value measured over a period of 24 hours must not exceed 35°C.
Installation altitude High‐voltage switchgear can be installed up to an altitude of 1000 meters. At higher installation altitudes, the reduced voltage endurance must be taken into account.
Air pollution The ambient air must be free of dust, smoke, corrosive or combustible gases, steam and salts.
5.1.4.2.
Prime Mover Type/Connection
Use of prime movers can be arranged through: Pengurus Besar Jabatan Perkhidmatan Logistik Bahagian Perkhidmatan Korporat Tenaga Nasional Berhad 129 Jalan Bangsar 50732 Kuala Lumpur The container is suitable for prime mover class 4 x 2 for loads less than 35 tonnes. The prime mover should also have fifth wheel coupler. The prime mover should have a 50.8 mm (2 inch) kingpin connection.
5
140
Substation Design Manual
5.1.4.3.
Equipment
The special tools/ test plug supplied with the Mobile SSU are:
5
MMLB07 Multi Finger Test Plug 2 Pfisterer Socket Size 3, 36 kV Termination Kit, 630 mm XLPE Aluminium Conductor 2 Pfisterer Socket Size 3, 36 kV Termination Kit, 500 mm XLPE Aluminium Conductor Conductor Current Test Plug Size 2 with Dummy Plug Manual Charging Handle for Circuit Breaker Operating Mechanism Manual Operating Handle for Isolator Tif‐Xp‐1a SF6 Leak Detector Dummy Plug Size 3
Special tools for plugging in power cable termination and SF6 filling are not supplied in the container. This service would be rendered by the site testing and commissioning contractor. 5.1.4.4. 5.1.4.4.1.
Logistics and Operation Ingress Protection
The IP class for the mobile SSU is IP55. 5.1.4.4.2.
Level of Parking Area o
The inclination of parking area should not exceed 10 while the mobile substation is in operation. 5.1.4.4.3.
Landing Gear
Two sets of landing gear supports are provided at the front and back side of the container. The container will stand on these landing gears while in operation. 5.1.4.4.4.
Wedge for Tyres
During parking, the mobile SSU will be supported by the landing gears and tyres. If wedges are to be used, the wedges suitable for 41 ft trailer are recommended.
Design for Substations with Special Requirements
141
5 Figure 5-12: Landing gears placed on solid and flat surface
5.1.4.4.5.
Vehicle Insurance
The mobile container requires its own comprehensive first party vehicle insurance, separate from the prime mover insurance. 5.1.4.4.6.
Road Tax
The container requires a separate road tax from the prime mover. For road tax renewal, the container should undergo road worthiness inspection annually at PUSPAKOM. 5.1.4.4.7.
Inspection Prior to Moving Vehicles
Prior to towing the container the followings inspection and actions should be taken:
Air brake is released Landing gear is raised Air conditioner cover for the condenser unit is securely installed. Tyre pressure is within 120 psi. All indicating and signal lights function properly.
142
Substation Design Manual
5.1.4.4.8.
Mobile SSU Transportation
The mobile container is subjected to road transport regulations with a maximum speed of 90 km/hour. 5.1.4.4.9.
Security
For the purpose of prevention of theft and unauthorized entry, pad locking options are provided at each door.
5
Figure 5-13: Provision for padlocks at each door
5.1.5.
Maintenance Specifications
5.1.5.1.
Vehicle
Landing Gear – The landing gear is suitable for weight of up to 30 tonnes. Axles – The container uses 2 axles with 60 tonnes combined capacity. Tyre – The container is equipped with 8 tyres installed on the axle with one spare tyre. The typical tyre size is 11 R x 22.5 x 16. The recommended tyre pressure is 120 psi.
Design for Substations with Special Requirements
5.1.5.2.
143
Equipment
The electrical installation shall be tested at each re‐location prior to start‐up, or at intervals not exceeding 6 months, whichever comes first. The result of all tests shall be recorded and retained. The general tests required are listed as follows: 5.1.5.2.1.
Visual Inspection
The Mobile SSU should be visually inspected for: Loose bolts and nuts Dust and foreign particles Dislocated parts Filing and chips Deformation, damage and wear Dislocated connectors and pins Loose switch terminals Rust Abnormal noise or smell Non working indicators 5.1.5.2.2.
Impedance to Earth of the Common Earth Grid
It is essential that the common earth grid is tested in order to ensure that the impedance to earth is not greater than the value required as calculated using IEEE Std 80 as in Subchapter 9.3. 5.1.5.2.3.
Insulation Resistance
The cable insulation resistance tests shall be carried out between phases and earth, between phases, and between phases and neutral.
5
144
Substation Design Manual
5.2.
Flood Prone Areas
5.2.1.
Overview
Generally, new substation sites should not be placed in flood prone areas. Meanwhile for existing substations in flood prone areas, mitigation steps need to be taken to prevent damage of substation equipment. The objectives of substation equipment for this process are: 1. 2.
5
3.
To minimize the risk of damage to TNB electrical installations during flooding. To ensure that the supply to the flooded area can be restored immediately once the water recedes. To maintain electricity supply to any unaffected area downstream even though there is a flood at the upstream of the electrical network.
The following flood mitigation techniques are summarized from Pekeliling PBK (Pengurusan Aset) Bil. A22/2012 – Kaedah Mitigasi Pencawang 11kV dan 22kV di Kawasan yang Dilanda Banjir.
5.2.2.
Methodology
The standard methodology for electrical installations flood mitigation is outlined below: 1.
2.
Maximum Flood Level – Get historical and expected worst flood level information from Jabatan Pengairan dan Saliran / Drainage and Irrigation Department (DID). This information will be used to construct the substation floor to a higher level than the worst flood level. Mitigation Technique – Select the appropriate mitigation initiatives. In general, the most suitable mitigation method shall comply to the following: (a) Safety issues when operating the equipment shall not be compromised. (b) The minimum clearance between tools/workers and the live parts should be met.
Design for Substations with Special Requirements
145
Initiatives for new and existing substations to reduce the effect of flooding upon the distribution network are explained as follows: 5.2.2.2.
New Substations
For new substations, the following should be implemented: (a) Site selection – avoid flood plains altogether. (b) Equipment selection – choose more flood resilient equipment. 5.2.2.3.
Existing Substations
In the case of existing substations, the aim is to elevate the substations above known flood levels and block water entry. Several mitigation options are suggested below: (a) Protection of individual equipment – raise plinth level for the equipment or the floor of the substation. (b) Protection of buildings – build a flood wall at the substation door (indoor), block water entry through cable trench or install submersible pump to pump out water from the substation. (c) Convert to pole mounted substation. (d) If the above mitigation options cannot be implemented, relocate the substation. Selection of mitigation techniques are based on the height of flood level and type of substation involved. The mitigation techniques for the following types of substations are further discussed in this chapter: 1. 2. 3. 4. 5.
Pole mounted substation (PAT) with feeder pillar Pole mounted substation (PAT) with RMU Outdoor substation Indoor substation Compact substation
5
146
Substation Design Manual
5.2.3.
Mitigation for PAT with Feeder Pillar
For flood level of less than 3 feet:
Raise feeder pillar plinth level to one foot above the flood level.
For flood level more than 3 feet:
If the water level reaches the transformer, the substation must be relocated.
This configuration will ensure that the MV feeder can still supply to other unaffected areas.
5
Figure 5-14: Raised feeder pillar plinth
5.2.4.
Mitigation for PAT with RMU
For flood level less than 3 feet:
Raise RMU plinth level to one foot above the flood level; or Replace the RMU with load break switch (LBS).
For flood level more than 3 feet:
If the water level does not reach the transformer, replace the RMU with load break switch. If the water level reaches the transformer, PAT must be relocated.
Design for Substations with Special Requirements
5.2.5.
147
Mitigation for Outdoor Substation
For flood level less than 3 feet:
Raise the RMU, transformer and feeder pillar plinths to one foot above the flood level; or Raise the substation floor to one foot above the flood level.
For flood level more than 3 feet:
Raise the substation floor to one foot above the flood level. If raising the floor is not possible, change the substation to pole-mounted substation (PAT). If both are not practical, the substation has to be relocated.
5
Figure 5-15: RMU, transformer and feeder pillar plinths are raised higher than the flood level
Figure 5-16: Pole-mounted substation (PAT) in a flooded area
148
Substation Design Manual
5 Figure 5-17: Raised substation floor level under 3 feet
Figure 5-18: Raised substation floor for flood level of more than 3 feet
Design for Substations with Special Requirements
5.2.6.
149
Mitigation for Indoor Substation
For flood level less than 3 feet:
Raise the RMU, transformer and feeder pillar plinths to one foot above the flood level; or Raise substation floor to one foot above the flood level; or Construct a water barrier / flood wall at the substation door and install a submersible water pump. Water entry through cable trenches should be blocked to minimise the amount of water entering the substation.
For flood level more than 3 feet:
Install flood walls and water pumps as above. If it is not practical to install flood walls at such height, the substation has to be relocated.
Figure 5-19: Raised RMU, transformer and feeder pillar plinths to above the flood level
5
150
Substation Design Manual
5
Figure 5-20: Water barrier / flood wall constructed at the substation door
Figure 5-21: Higher flood walls may require staircase access to be built
Design for Substations with Special Requirements
5.2.7.
151
Mitigation for Compact Substation
For flood level less than 3 feet:
Raise compact substation plinth to one foot above the flood level.
For flood level more than 3 feet:
Raise compact substation plinth one foot above the flood level. If this is not practical, change to PAT or relocate the substation.
5
Figure 5-22: Raised compact substation plinth one foot above the flood level
152
Substation Design Manual
5.2.8.
Guideline for New Substations
For new substations, the planner should consider the following:
All new substations should not be constructed in flood-prone areas. If this is unavoidable, the substation need to be built using the mitigation techniques suggested previously in this chapter. TNB may also request the developer to build a custom-designed substation building. An example is shown in the figure below.
5
Figure 5-23: Custom-designed substation building for flood-prone areas
Primary Equipment
Chapter 6:
153
Primary Equipment
6.1.
Transformer
6.1.1.
Overview
In “IEC Standard 60076 – Part 1: Power Transformers”, a transformer is defined as a static piece of apparatus with two or more windings which, by electromagnetic induction transforms a system of alternating voltage and current in one winding into another system of alternating voltage and current in one or more other windings, usually of different values and at the same frequency for the purpose of transmitting electrical power. An alternating voltage applied to one of the winding produces, by electromagnetic induction, a corresponding electromotive force (EMF) in the other windings. Thus energy can be transferred from the primary circuit to the other circuits by means of the common magnetic flux. Thus, a transformer is a device which transfers electric power from one circuit to another without electric connection while maintaining the frequency of the power source as a result of the transfer of energy. Laminated Core
primary
secondary
Figure 6-1: Magnetic circuit and windings of a transformer
6
154
Substation Design Manual
6.1.2.
Transformer Category
According to IEC 60076-1, windings in transformer can be classified into high voltage (HV) or low voltage (LV) windings. HV winding is defined as the winding having the highest voltage whilst LV winding is defined as the winding having the lowest voltage. Referring to this definition, transformers in TNB distribution system can be categorized into four categories:
6
Category 1 – Free breathing power transformers with On-Load Tap Changer (OLTC). This category of transformer has capacity above 5 MVA up to 30 MVA. Category 2 – Free breathing power transformers with Off-Circuit Tap Changer (OCTC). This category transformer has capacity of 3 MVA up to 5 MVA. Category 3 – Small power transformers with Off-Circuit Tap Changer (OCTC). However, this category of transformers has capacity above 1 MVA but not larger than 3 MVA and can be either free breathing or hermetically sealed transformers. Category 4 – Distribution transformer. It has primary and secondary windings designed to operate at high and low voltage or vice versa depending whether it is a step down or a step up transformer. This category of transformer has capacity not larger than 1 MVA and can either be a free breathing or hermetically sealed transformers.
Primary Equipment
6.1.3.
Transformer General Arrangement
6.1.3.1.
Distribution Transformer (9)
155
(8)
(10)
(7)
(11) (12)
(6) (1)
(5)
(2)
1. 2. 3. 4. 5. 6.
HV bushing Sampling/drain valve Jacking pad Corrugated fin wall Off circuit tap changer HV bimetal lug
(4) (3)
7. 8. 9. 10. 11. 12.
Pressure relief device (PRD) Oil level gauge LV bushing flag LV bimetal lug LV bushing Top-mounted thermometer
Figure 6-2: Distribution transformer (external view)
6
156
Substation Design Manual
(8) (9)
(7)
(10) (11)
(6)
(1)
(2)
(3) (5) (4)
6 1. 2. 3. 4. 5. 6.
HV winding LV winding Core (limb) Insulation (press board) Bottom clamping LV connection bar
7. 8. 9. 10. 11.
Top clamping Neutral bar LV bar (red phase) LV bar (yellow phase) LV bar (blue phase)
Figure 6-3: Distribution transformer (internal view)
Primary Equipment
157
6 Figure 6-4: A mock up construction of a distribution transformer showing the internal parts
158
Substation Design Manual
6.1.3.2.
Power Transformer (13)
(12)
(11)
(14) (15) (16) (18)
(17)
(10)
(19) (20)
(9)
(21)
(8) (7)
6 (6)
(1) (2)
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.
(3)
(4) (5)
Cooling radiator Main tank Motor drive unit (MDU) Lifting lug for complete unit HV cable box Oil level indicator Cable box breather Buchholz relay Cooling fan Core earth box Air leak detector
12. 13. 14. 15. 16. 17. 18. 19. 20. 21.
Main conservator OLTC conservator Pressure relief device (PRD) CT terminal box Local control panel (LCP) Inspection vent LV cable box Lifting lug for cover On load tap changer (OLTC) Top cover
Figure 6-5: Power transformer (external view)
Primary Equipment
159
(9) (10)
(8) (1)
(7)
(2)
(3)
(6) (4)
1. 2. 3. 4. 5.
Regulating winding HV winding LV winding Core (limb) Foot
(5)
6. 7. 8. 9. 10.
Support for winding Bottom clamping OLTC Top clamping CT (for winding temperature)
Figure 6-6: Power transformer (internal view)
6.1.4.
Transformer Design Characteristics
The transformers used in TNB distribution system are designed with specific characteristics to suit the system requirement for safe operation under normal service condition. By definition according to IEC 60076-1, normal service conditions are at an altitude of not greater than 1000 m above sea level, within an ambient temperature range of -25:C to +40:C, subjected to a wave shape which is approximately sinusoidal, a three phase supply which is approximately symmetrical and within an environment which does not require special provision on account for pollution and is not exposed to seismic disturbance. The basic design characteristics of distribution as well as power transformers in TNB distribution system are briefly explained in the following sub-chapters.
6
160
Substation Design Manual
6.1.4.1.
Rated Voltage
Rated voltage is the voltage in kV between line terminals at no-load of untapped winding i.e. LV winding or of a tapped winding i.e. HV winding connected on the principal (nominal) tap position.
6.1.4.2.
Voltage Ratio
Voltage ratio is the ratio of the rated voltage of HV winding to the rated voltage of LV winding. On the other hand, the voltage ratio notation for identification is indicated as HV/LV e.g. 33/11 kV for a step down transformer or LV/HV e.g. 11/33 kV for a step up transformer.
6.1.4.3.
6
Rated Power
Rated power is a conventional value of apparent power indicating the capacity of the transformer in kVA or MVA.
6.1.4.4.
Rated Current
Rated current is the current flowing through a line terminal of a winding (line current) which is derived from the rated power and rated voltage for the winding. For a three phase transformer, the rated current iR in the winding under consideration is given by: 𝑖𝑅 =
6.1.4.5.
Transformer Rated Power 3 × Rated Voltage of the Winding
Rated Frequency
The rated frequency corresponds to the network frequency i.e. 50 Hz at which the transformer is designed to operate.
Primary Equipment
6.1.4.6.
161
Short Circuit Impedance (Percentage Impedance)
Short circuit impedance of a transformer is the percentage voltage drop of the no-load voltage at full load current due to the winding resistance and leakage reactance. The impedance of a transformer has a major effect on system fault levels. It determines the maximum value of current that will flow under fault conditions. Thus, the percentage impedance of a transformer is designed to balance between the effect of limiting the short circuit current and at the same time maintaining the voltage drop within a permissible range. By using the percentage impedance of the transformer, a symmetrical three phase short circuit on the LV terminals will produce current if in Amps equal to: 𝑖𝑓 = 6.1.4.7.
Transformer rated power kVA × 100 3 × Rated voltage of LV winding kV × Percentage impedance Winding Connection and Vector Group
The information on winding connection and vector group of a transformer is very important to enable satisfactory operation of transformers in parallel. The interphase connections of the HV and LV windings are indicated by the capital and small letters respectively as shown in Table 6-1 . The winding connection letter is immediately followed by its phase displacement clock number. The letter symbols for the different windings are noted in descending order. Figure 6-7 and Figure 6-8 shows some examples on the phasor diagrams and clock number notations for typical transformer winding connections. Table 6-1: Winding connection designation Winding HV winding
LV winding
Winding Connection Delta Star Interconnected star (zigzag) Neutral Delta Star Interconnected star (zigzag) Neutral
Designation D Y Z N d y z n
6
162
Substation Design Manual
HV Winding
LV Winding
(a) 3-phase Delta-Star connection Dyn11
6
HV Winding
LV Winding
(b) 3-phase Star-Delta connection YNd11 Figure 6-7: Phasor diagrams and clock number notation showing phase displacement of +30⁰ for 3-phase transformers with connection symbols Dyn11 and YNd11
Primary Equipment
HV Winding
163
LV Winding
(a) 3-phase Delta-Star connection Dyn1 HV Winding
LV Winding
(b) 3-phase Star-Delta connection YNd1 Figure 6-8: Phasor diagrams and clock number notation showing phase displacement of -30⁰ for 3-phase transformers with connection symbols Dyn1 and YNd1
6
164
Substation Design Manual
6.1.4.8.
Losses and Efficiency
Losses of a transformer can be expressed in terms of no-load loss and load loss. These quantities are determined by means of tests at rated voltage for no-load test and at rated current for load loss. When a transformer is energised, a magnetising current is required to excite the core through the alternating cycles of a flux at a rate determined by the system frequency. The energy dissipated in doing so is known as the no-load loss, core loss or iron loss and it is present whenever the transformer is energised. Hysteresis and eddy currents losses contribute to over 99% of the no-load loss. The load loss, also known as winding loss, copper loss or short circuit loss of a transformer is generated by the flow of load current which varies as the square of the load current. Load loss can be divided into three categories:
6
2
Resistive loss (I R) within the winding conductors and leads. This type of loss dominates load loss. Eddy current loss in the winding conductors Stray loss due to leakage flux that intercepts the tanks and structural steelwork which give rise to the eddy current flow
Other losses are due to effect known as magnetostriction where magnetic flux in the core, causes it to physically expand and contract slightly with each cycle of the magnetic field, produces the humming sound commonly associated with transformers. This can cause losses due to frictional heating. In addition to magnetostriction, mechanical loss due to fluctuating forces between the primary and secondary windings as the result of the alternating magnetic field. These incite vibrations within nearby metalwork, adding to the humming noise and consuming a small amount of power. The guaranteed no-load loss and load loss in kW of distribution and power transformers are as shown in the tables that follow.
Primary Equipment
165
Table 6-2: No-load loss and load loss in kW of a distribution transformer kVA 100 300 500 625* 750 1000 1250* kVA 100
Load loss (kW) 1.5 2.8 4.1 1.2 1.4
6.6/0.433 kV No-load Total loss loss (kW) (kW) 0.3 1.8 0.6 3.4 1.0 5.1 1.2 1.4
7.2 8.4
22/0.433 kV No-load Load loss Total loss loss 1.6 0.24 1.84
11/0.433 kV No-load Total loss loss (kW) (kW) 0.3 1.8 0.6 3.4 1.0 5.1 1.3 6.0 1.2 7.2 1.4 8.4 1.8 9.7 33/0.433 kV No-load Load loss Total loss loss 1.5 0.3 1.8 Load loss (kW) 1.5 2.8 4.1 4.7 6.0 7.0 7.9
300
4.4
0.7
5.1
4.5
0.73
5.23
500 750
7.3 9.2
0.9 1.2
8.2 10.4
7.18 9.2
1.02 1.385
8.2 6.0
1000
11.7
1.5
13.2
11.85
1.665
7.0
*Note: Step up 0.415/11kV transformers
Table 6-3: No-load loss and load loss in kW of a power transformer
1.5
16.5
33/11 kV No-load loss 1.6
5
3.9
9
48
12.5
80
12
92
15
82
12
94
30
120
15
135
Load loss
22/11 kV No-load loss 2.5
Total loss
MVA
MVA
Load loss
2
19.5
Total loss
14.5
11/33 KV No-load loss 2.4
80
12
92
Total loss
Load loss
18.1
Load loss
22/6.6 kV No-load loss
16.9
Total loss
22
7.5
47
5
52
42
6
48
12.5
80
12
92
75
10
85
30
120
15
135
6
166
Substation Design Manual
The energy efficiency of a transformer is given by the following formula: %Efficiency =
=
Output Output + Losses
P × kVA × p. f × 1000 × 100 P × kVA × p. f × 1000 + NL + LL × P 2 × T
Where, P = per unit loading NL = no-load loss in watts LL = load loss in watts at full load, at 75˚C T = temperature correction factor (T at 75˚C is 1.0) p.f = power factor
6
Example of energy efficiencies at 0.9 lagging power factor for TNB distribution transformers of various sizes calculated using the above formula are as plotted in the graph of Figure 6-9. The graph shows that distribution transformers are most efficient between 0.4 to 0.5 per unit loading. It also shows that bigger capacity transformers by design, for example 1000 kVA, are more efficient as compared to the lower capacity, for example 100 kVA. Despite these facts, loading of a transformer and selection of transformer capacity should not be based merely on losses or efficiency of the transformer but should also consider for asset optimization. This is because the transformer loaded at between 0.5 and 1.0 per unit loading has relatively small difference in efficiency as compared to loading between 0.4 and 0.5 per unit loading.
Primary Equipment
167
Currently, energy efficiency of TNB distribution transformers are at par with the current class 1 energy efficient transformers in the U.S. (NEMA TP-1) and Europe (HD 428 C-C’), and they are comparable with future minimum energy efficient standards in the U.S. (TSL2) and Europe (EN-50464-1:2007 Ao-Ak).
6
Figure 6-9: Energy efficiency of distribution transformers of different capacities at various per unit loading
168
Substation Design Manual
6.1.4.9.
Noise Pressure Level
The average noise pressure level of a transformer is measured at 0.3 m from the radiating surface, where the measurement should be performed according to IEC 60076-10. The maximum permissible sound level by receiving land as recommended by the Department of Environment in its planning guideline for environmental noise limits and controls are as follows: Table 6-4: The Maximum Permissible Sound Level by Receiving Land Receiving Land Use Category
6
Day Time 7.00 am - 10.00 pm
Night Time 10.00 pm - 7.00 am
50 dBA
40 dBA
55 dBA
45 dBA
60 dBA
50 dBA
Commercial Business Zones
65 dBA
55 dBA
Designated Industrial
70 dBA
60 dBA
Noise Sensitive Areas, Low Density Residential, Institutional (School, Hospital), Worship Areas. Suburban Residential (Medium Density) Areas, Public Spaces, Parks, Recreational Areas. Urban Residential (High Density) Areas, Designated Mixed Development Areas (Residential - Commercial).
As such, the design and construction of all types of substations should strictly follow the requirement underlined by the latest revision of ESAH in order to ensure the noise generated by a transformer is contained within the substation so that the noise radiated outwards from the substation will not exceed the specified limits above.
Primary Equipment
169
6.1.4.10. Rated Insulation Level Rated insulation level is a set of standard withstand voltages which characterize the dielectric strength of the insulation used. The level is identified by the highest voltage (rms) for equipment U m, associated with the winding. The rules for coordination of transformer insulation with respect to transient overvoltages are formulated differently depending on the value of Um. The rated insulation levels for standard dielectric insulation requirement, i.e. lightning impulse withstand voltage, LI (peak) for the line terminals and separate source AC withstand voltage (rms) for transformers in TNB distribution network in accordance with IEC 60076-3 are as tabulated in Table 6-5. Table 6-5: Rated withstand voltages for transformer windings Highest Voltage Um of HV & LV Windings
Insulation Level AC
LI
Winding with Um = 36 kV
70 kV
170 kV
Winding with Um = 24 kV
50 kV
125 kV
Winding with Um = 12 kV
28 kV
75 kV
Winding with Um 1.1 kV
3 kV
-
6.1.4.11. Temperature Rise Temperature rise is the difference between the temperature of the part under consideration i.e. top oil or winding temperature and the ambient (surrounding) temperature, when the transformer is loaded up to its nameplate rating. A transformer with a lower temperature rise is more efficient since it consumes less energy and generates less waste heat and contributes to a longer life expectancy. On the other hand, lower temperature rise will incur additional cost since more cooling medium or improved cooling system is required.
6
170
Substation Design Manual
6.1.4.12. Overloading The normal design life expectancy of a transformer is based on continuous duty under design ambient temperature and normal service or rated operating conditions. However, the application of a load in excess of nameplate rating and an ambient temperature higher than design ambient temperature involves a degree of risk and accelerated ageing that reduces the expected design life of the transformer. Although the maximum loading capability of the transformer can be safely set to 100% under normal condition of its capacity for a design ambient temperature of 40:C, it is technically possible to overload the transformer under the following conditions:
6
Normal cyclic loading – loading of a transformer at higher ambient temperature or a higher than rated load current during some part of the 24 hour cycle where the average loading is equivalent to the rated load at normal ambient temperature. Long time emergency loading – loading of a transformer at higher ambient temperature or a higher than rated load current for a prolonged part of the 24 hour cycle due to system outage that will not be normalized before the transformer reaches a new and higher steady state temperature. Short time emergency loading – unusually heavy loading of a transformer of transient nature of less than 30 minutes due to the occurrence of one or more unlikely events which seriously disturb normal system loading.
The risks or consequences of loading a transformer beyond its nameplate rating are:
Damage of the dielectric strength of the transformer insulation due to development of gas bubbles as the result of hot-spot temperature exceeding 140:C that could occur at the winding, leads or cleats. Eddy-current heating in metallic parts as the result of increased leakage flux outside the core. Damage of bushings, tap changer, terminations and current transformer, due to higher stresses beyond their design limits.
Primary Equipment
171
Due consideration should also be given on the withstand capability of other equipment in the system such as power and auxiliary cables, secondary system and equipment as well as settings of protection relays before decision to overload the transformer is made. Overloading of a transformer beyond its nameplate rating shall therefore be performed strictly in accordance with IEC 60076-7 and TNB Distribution Planning Guideline.
6.1.4.13. Tap Changer and Tapping Range Tap changer is a device used for changing the tapping connection of a winding to regulate voltage level affected by load variations. There are two types of tap changer used, the Off-Circuit Tap Changer (OCTC) and On-Load Tap Changer (OLTC) which are explained further under Subchapter 6.1.5.6. Tapping (regulating) range is the variation range of the tapping factor expressed as a percentage of the rated nominal voltage of the tapped winding i.e. HV winding. The typical tapping range of power and distribution transformer tap changers is shown in Table 6-6 below. Table 6-6: Tapping range according to transformer category Tapping Range (%)
Tapping per step on HV Winding (%)
Nominal Voltage on HV Winding (V)
Highest Voltage at Lowest Tap (V)
Lowest Voltage at Highest Tap (V)
33/11, 33/22-11
+10% to -15%
1.67%
33000
36300
28050
11/33
+15% to -10%
1.67%
33000
37950
29700
22/11
+10% to -15%
1.67%
22000
24200
18700
22/6.6
+9% to -16.5%
1.5%
22000
23980
18370
+5% to -5%
2.5%
33000
34650
31350
+5% to -5%
2.5%
22000
23100
20900
+5% to -5%
2.5%
33000
11550
10450
Transformer Transformer Voltage Ratio Category (kV)
Category 1
33/11, 33/0.433 Category 2, 22/11, 11/22, 3&4 22/0.433 11/0.433 0.415/11
6
172
Substation Design Manual
Typical design characteristics for distribution and power transformers are summarized in Table 6-7 and Table 6-8 respectively. Table 6-7: Category 1 & 2 Transformer Basic Technical Parameters Category Rated Voltage Ratio & Power Power Transformer with OLTC (Category 1)
6
Power Transformer with OCTC (Category 2)
Technical Parameter 33/11 kV
7.5 MVA, 15 MVA, 30 MVA
22/11 kV
12.5 MVA, 22.5 MVA
22/6.6 kV
3.5 MVA, 7.5 MVA, 12.5 MVA
33/22-11 kV (Dual ratio)
30 MVA
33/11 kV
7.5 MVA, 15 MVA, 30 MVA
11/33 kV*
7.5 MVA, 15 MVA
33/11 kV
5 MVA
No. of phases & rated frequency
3-phase, 50 Hz
Short Circuit Impedance
9 to 11% at reference temperature of 75°C with tolerance of ±10%
Vector Group
Dyn11, YNd1*, Ynd11*
Losses
Refer to 6.1.4.8
Maximum Noise Pressure Level
55 dBA
Insulation Level
Refer to 6.1.4.10
Temperature Rise
60°C (Top Oil), 65°C (Winding)
Tapping Range
Refer to 6.1.4.13
*Step-up transformer
Primary Equipment
173
Table 6-8: Category 3 & 4 Transformer Basic Technical Parameters Category Rated Voltage Ratio & Power Small Power Transformer (Category 3)
Technical Parameters 33/11 kV
1.5 MVA
22/11 kV
2 MVA
11/22 kV*
2 MVA
33/0.433 kV 22/0.433 kV
Distribution Transformer (Category 4)
11/0.433 kV
100, 300, 500, 750, 1000 kVA
6.6/0.433 kV 0.415/11 kV*
300, 625, 1250 kVA
No. of phases & rated frequency
3-phase, 50 Hz
Short Circuit Impedance
4.75% at reference temperature of 75°C with tolerance of ± 10%
Vector Group
Dyn11, YNd1*, Ynd11*
Losses
Refer to 6.1.4.8
Maximum Noise Pressure Level
60 dBA
Insulation Level
Refer to 6.1.4.10
Temperature Rise
60°C (Top Oil), 65°C (Winding)
Tapping Range
Refer to 6.1.4.13
*Step-up transformer
6
174
Substation Design Manual
6.1.5.
Transformer Construction
The main parts of a transformer are the core, the windings, transformer tank to house the core and windings; bushing terminals for the external electric circuit connection and the cooling arrangements to remove heat generated in the core and winding for dissipation. 6.1.5.1.
Core
The purpose of transformer core is to provide a low reluctance path for the magnetic flux linking primary and secondary windings. The core is made up of stacks of thin laminated magnetic sheet. Each lamination is insulated by a thin non-conducting layer of insulation that increases resistivity of the material to minimize the eddy current loss. The use of high permeability grain oriented silicon steel is preferred due to its improved grain orientation to reduce hysteresis loss.
6
The transformers used in TNB distribution system is of three-phase core with three-limbs which are magnetically connected with each other at the upper and the lower ends by yokes. In three-phase transformers, all the windings for each phase are located at their own limb.
Figure 6-10: Distribution transformer three-limb core
Primary Equipment
175
Figure 6-11: Core construction of power transformers
6
Figure 6-12: Complete core winding assembly
𝜙1
𝜙3
𝜙2
Window
Yoke
Limb
Figure 6-13: Three-limb transformer design that shows the flux
176
Substation Design Manual
6.1.5.2.
Winding
A winding is made up of conductors, coiled concentrically around the magnetic circuit limbs to produce the desired number of turns in which will determine the voltage of the winding. The conductor is usually made of copper which is electrically insulated from each other with paper and in some cases with enamel and paper to ensure that the current travels throughout every turn. The number of turn and the current in the winding primarily determine the choice of winding type. The maximum current density in any winding is 2 designed usually not higher than 3 A/mm to reduce the dynamic effect during short circuit.
6
Figure 6-14: Distribution transformer windings
Enamel coating Conductor
Figure 6-15: Enamelled copper conductor
Primary Equipment
177
Figure 6-16: Single strand with Kraft paper insulation
Figure 6-17: Continuous transposed cable (CTC)
Windings for transformers can be divided into four main types: Layer windings Foil windings Disc windings Helical windings Distribution transformers are usually designed having layer winding on the HV and foil winding on the LV, whilst power transformers have disc winding on the HV and either disc or helical winding on the LV, depending on the value of the rated current. For layer type winding, the turns are arranged axially along the winding. The consecutive turns are wound close to each other without any intermediate space. The winding may be made as a single or multilayer winding.
6
178
Substation Design Manual
Figure 6-18: Layer type windings Foil windings are made of wide copper sheet, from some tenths of millimeter up a few millimeters thick. It is usually used for windings with a small number of turns but relatively high currents. The main technical advantage is that axial mechanical forces acting on the windings in the transformer during short circuit currents become insignificant.
6
Figure 6-19: Foil winding
Primary Equipment
179
The disc winding concept is used for windings with a large number of turns and relatively small currents. It is built up of a number of discs connected in series. The major difference between a helical and a disc winding is the number of turns per disc. In helical windings there is never more than one turn per disc while disc windings have more than one turn per disc.
6
(a)
(b)
(c) Figure 6-20: Disc winding
180
Substation Design Manual
The helical winding is suitable for high currents where the current is shared between several parallel strands. The quantity of conducting material that can be fitted inside a given volume is high compared to other types of winding. Moreover it is mechanically robust and easy to manufacture, particularly when continuously transposed cable is used.
6
(a)
(b)
(c) Figure 6-21: Helical winding
Primary Equipment
181
Tapping (regulating) winding is usually wound at the outermost winding in a power transformer for easy connection to the OLTC. Similar to the type of windings mentioned above, tapping winding can either be made in layer, helical or disc winding depending on the design requirement. 6.1.5.3.
Transformer Insulation
Transformer main insulation can be divided into solid and liquid insulation. Solid insulation in transformers consist mainly of oil impregnated paper and pressboard. These are cellulose materials, which include Kraft, creped, presspaper and diamond dotted paper (presspaper with partial resin coating). Other type of cellulose materials are manila and rag paper as well as cotton jute and linen fibres. Nowadays, thermal upgraded paper is preferred. It is a normal cellulosic paper treated by the addition of stabilizers during manufacture to provide better temperature stability and reduced thermal degradation. Mineral hydrocarbon oil has been the major liquid electrical insulation due to its high dielectric strength to withstand the electric stresses imposed in service. It also has sufficiently low viscosity to circulate and transfer heat, thus it has been used as cooling medium in power transformers. The combination of oil and cellulose material is one of the most satisfactory insulant yet known and the electrical and thermal strength of this combination is much higher than that of the individual materials used separately. For example in terms of temperature rise, cellulose material alone is of Class Y insulation with thermal withstand capability of up to 90:C. However, with the impregnation of oil, the cellulose material has become Class A type insulation with the maximum thermal withstand capability of up to 105:C.
6
182
Substation Design Manual
6
Figure 6-22: Samples of cellulose insulations used in transformers
Primary Equipment
6.1.5.4.
183
Tank and Preservation System
Tanks are designed to house the core and windings complete with oil so that it can be lifted or moved by cranes, winch or jacks without over straining any joints and without causing damage to the internal active parts and cause subsequent leakage of oil. Some tanks are fitted with skid under bases suitable for handling with roller bars. The skids are drilled to accommodate axles and rollers when required. In practice, there two types of transformer tank construction i.e. conventional type tank with flat top cover mounted or belt type tank where the cover junction or belting is near the bottom of the tank, dividing the complete tank into top tank and bottom tank.
6
Figure 6-23: Conventional type tank
Figure 6-24: Belt type tank
184
Substation Design Manual
Distribution transformers have corrugated tank design to function as cooling fins. All distribution transformers in TNB distribution system used after the year 1990 are of cover mounted tank type with hermetically sealed preservation system. The tank, which does not require nitrogen or air cushions, is completely filled with oil. The expansion and contraction of oil, due to temperature fluctuations, is taken up by the expendable tank corrugations. Transformer tanks are designed to withstand an internal overpressure of 28 – 35 kPa (4 – 5 psi) in excess of that required to operate the pressure relief device. The design of the tank is suitable for use as ground mounted or pole mounted transformer. The tank is sealed in every opening point with sealant and O-rings or flat type gaskets made of synthetic rubber bonded cork or hot oil resistance synthetic rubber (Neoprene) that is of chemical and thermal resistant for hot oil up to 120°C.
6
Figure 6-25: Hermetically sealed type transformer
Primary Equipment
185
Another type is a free breathing conservator type transformer where the expansion of oil due to temperature or pressure increase is taken up by the conservator. The most importance feature and use of a conservator are: (a) To allow for expansion and contraction of oil which is temperature dependent. (b) To reduce the surface area of the oil exposed to atmospheric air so that contents of oxygen gas dissolved in the oil is reduced, thus reduces the rate of oxidation of the oil which would otherwise tend to shorten insulation life. (c) To allow the main tank to be filled to the top cover, thus permitting oilfilled bushing and the use of a gas actuated relay in the connection pipe between the main tank and the conservator of a power transformer.
6
Figure 6-26: Conservator type distribution transformer
186
Substation Design Manual
Figure 6-27: Conservator type power transformer
6
For distribution transformer, hermetically sealed type is more advantageous compared with the conservator type transformer. The main advantage is that the oil is not in contact with the atmosphere, thus avoiding absorption of moisture and oxygen from the environment that can speed up the degradation process of the insulation.
6.1.5.5.
Cooling System
More than 85% of the heat generated in a transformer is caused by the resistive loss in the winding and the remaining by the stray losses in the structural metal parts of the transformer. Transformers utilize cooling systems to transfer the heat produced to the surroundings and control the temperature rise. This heat transfer mechanism helps to prevent the core, windings, or any structural parts from reaching critical temperatures that could deteriorate the insulation.
Primary Equipment
187
The cooling designations for oil immersed transformers expressed in fourletter code in accordance with IEC 60076-2 are described in Table 6-9. Typical types of cooling systems used in TNB distribution system are ONAN and ONAF. In ONAN type cooling system, heat is transferred from the windings, core and structural metal parts to the oil. The heated oil circulates in the transformer tank by the principle of natural convection and it is cooled by the natural air. Cooling fins and radiators provide the means of increasing the area for heat dissipation. In ONAF type cooling system, fans mounted on the radiators, are used to force an air blast on the radiators to increase the heat dissipation rate. The fans are automatically switched on when the temperature of the oil and windings increases above the permissible value. This happens during heavy load condition and during higher ambient temperatures. Forced cooling can increase the kVA rating of an oil immersed transformer by 15% to 30%. Table 6-9: Cooling designation four letter code First letter O K L Second letter N F D Third letter A W Fourth letter N F
Internal cooling medium in contact with the windings Mineral oil or synthetic insulating liquid with fire point < 300:C Insulating liquid with fire point > 300:C Insulating liquid with no measurable fire point Circulation mechanism for internal cooling medium Natural convection flow through cooling equipment and windings Forced circulation through cooling medium, natural convection in windings Forced circulation through cooling medium, with directed flow through at least the main windings External cooling medium Air water Circulation mechanism for external cooling medium Natural convection Forced circulation (fans, pumps)
6
188
Substation Design Manual
6.1.5.6. 6.1.5.6.1.
Tap Changer Off-Circuit Tap Changer (OCTC)
Off-Circuit Tap Changer (OCTC) or sometimes called De-energised Tap Changer (DETC) is a simple, cheapest but reliable device that can be used as a mean of adjusting transformer voltage ratio by adding or removing tapping turns. It is connected on the HV side and designed only to be operated when the transformer is de-energised. Thus it is only applicable to installations in which the loss of supply can be tolerated. In TNB distribution system it is applicable for distribution and small power transformers up to 5 MVA 33/11 kV. Figure 6-28 shows the typical OCTC used in distribution transformers. The OCTC connection types normally employed in the distribution transformers are Linear and Single Bridging type as shown in Figure 6-29.
6
Figure 6-28: Off circuit tap changer
(a)
(b)
Figure 6-29: Off circuit tap changer basic connection type (a) Linear and (b) Single Bridging
Primary Equipment
6.1.5.6.2.
189
On-Load Tap Changer (OLTC)
The function of an OLTC is to switch from one winding tap to another without interrupting the load current. OLTC can be installed inside the transformer (intank) or in an externally mounted compartment which is welded or bolted to the transformer tank. Figure 6-30 illustrates both of the OLTC installation types.
6
Figure 6-30: Type of OLTC installation showing in-tank (left) and external compartment (right) There are two different designs of OLTC which are the diverter switch type and the selector switch type OLTC. Figure 6-31 (a) shows diverter switch type which has a tap selector and a diverter switch in a separate compartment; and (b) the selector switch type also known as arcing type selector which combines both functions of tap selector and diverter switch in one oil-filled compartment. The oil filled compartment is a free breathing tank connected via a pipe to a conservator with the addition of a dehydrating breather to remove moisture from the air that is in contact with the oil as shown in Figure 6-32. On the other hand, there are two switching principles that have been used for the load transfer operation during tapping transition i.e. by means of high speed resistor or reactor.
190
Substation Design Manual
Change-over selector
Diverter switch
Selector/Arching switch Transition resistors
Tap selector
(a)
(b)
Figure 6-31: Two Different Types of OLTC (a) Diverter Switch Type OLTC, (b) Selector Switch Type OLTC
6
1. 2. 3. 4. 5.
OLTC Cover Oil Compartment (Belly Tank) OLTC Insert Motor Drive Unit Oil Surge Relay
6. 7. 8. 9.
Oil Conservator Horizontal Drive Shaft Vertical Drive Shaft Bevel Gear
Figure 6-32: OLTC general arrangement showing oil filled compartment, conservator and motor drive
Primary Equipment
191
Majority of OLTC designs used in power transformers of TNB distribution system is of in-tank selector switch type with oil immersed switching (arcing) contacts and transition resistors for load transfer operation. The switching arcs occur in oil due to the making and breaking of currents during normal tap change operation. These arcs cause carbonization of oil that reduces the dielectric strength of the insulating medium. They also cause heating of oil that speed up its degradation process thus requires shorter maintenance intervals of the OLTC. The new technology confines the current switching in interrupted vacuum bottles where the switching contacts are no longer immersed in the oil of the OLTC compartment. This new breed of OLTC known as the Vacuum Switch OLTC helps to prevent contamination of oil due to carbonization and hence lower the rate of oil degradation due to heating. As the results, the OLTC has longer maintenance intervals up to 300,000 switching operations and thus reduces maintenance costs.
Change-over selector
Roller type arcing switch
Transition resistors
Figure 6-33: OLTC compartment and insert of oil Immersed switching contacts
6
192
Substation Design Manual
Vacuum switch
6
Figure 6-34: OLTC compartment and insert of vacuum switch OLTC
There are three different kinds of connecting schemes to which the OLTC can be connected to the tapping winding (Figure 6-35) which are: (a) linear, (b) plus/minus; and (c) coarse/fine. Tapping winding in linear arrangement is commonly used for small tapping ranges e.g. 10% of nominal voltage. The addition of the tapping winding connected in series with the main winding results in the addition of voltage across the tapping winding to the voltage across the main winding.
Primary Equipment
193
6 Figure 6-35: Typical arrangements of tapping winding for OLTC connection On the other hand, for larger tapping ranges, tapping winding in plus/minus or coarse/fine arrangements can be used. In plus/minus arrangement, the tapping winding is connected to the main winding via a change-over selector that functions as plus minus switch. This switch provides an ability to add or subtract the voltage of the tapping windings to or from the voltage of the main winding allowing the tapping range to be doubled and at the same time reduce the number of the tapping windings. In a coarse/fine arrangement, the tapping winding is split into two groups, coarse and fine windings. The coarse winding can be connected or disconnected in series to the main winding to provide the larger addition or subtraction of voltage whilst the fine winding is added or subtracted sequentially with the smaller value of tapping step voltage.
194
Substation Design Manual
Oil Surge Relay
The oil surge relay is an oil-flow controlled relay installed between the OLTC head and the conservator. Faults even at low-energy can lead to oil flow in the OLTC oil compartment. The relay will trip when the specified oil flow speed between the on-load tap-changer head and the oil conservator is exceeded. However, any gases generated during OLTC switching will escape via a small opening in the relay unobstructed to the oil conservator. The relay operates according to the principle of a movable flap valve. When triggered, the flap valve operates a reed switch and makes a signal available. Once it has been triggered, the flap valve remains in its position and has to be reset manually.
6
Rupture disk
Oil surge relay
Figure 6-36: Oil surge relay showing the internal components
Primary Equipment
195
Rupture Disk
The rupture disk is a pressure-relief device without signaling contact located in the OLTC cover. Faults with large energy release can lead to strong pressure waves with high pressure peaks, which can damage the on-load tap changer oil compartment. An overpressure of more than 5 bar will rupture the disk and enables the pressure to relieve immediately.
Motor Drive Unit
Generally, on-load tap changers come with a motor to provide the drive to allow the tap changer to operate. A typical OLTC with motor operating mechanism connected to the tap changer is given below in Figure 6-37. The Geneva gear principle is used to change a rotary motion into a stepping motion. Drive is transmitted via a shaft system and bevel gears from the motor-drive mechanism. A spring energy accumulator actuates the Geneva gear. The Geneva gear operates the selector switch and the change over selector. The Geneva gear is also used to lock the moving contact system into position.
Figure 6-37: Typical motor operating mechanisms
6
196
Substation Design Manual
6.1.5.7.
Dimensions & Weight
The maximum dimension and weight for new distribution and power transformers based on rated power is as shown in Table 6-10 and Table 6-11. Table 6-10: Maximum dimension and weight for new distribution transformers 11/0.433 kV
22/0.433 kV
Transformer Rated Power
L x W x H (mm)
Total Weight (kg)
L x W x H (mm)
Total Weight (kg)
100 kVA
1000x700x1200
900
1100x750x1340
1100
300 kVA
1250x870x1370
1410
1350x900x1450
1800
500 kVA
1500x940x1500
2010
1760x1120x1550
2200
750 kVA
1700x930x1630
2460
1710x1040x1830
2500
1000 kVA
1750x950x1800
3200
1950x1200x2030
3800
(a)
6
33/0.433 kV
Transformer Rated Power
L x W x H (mm)
Total Weight (kg)
100 kVA
1200x820x1570
1300
300 kVA
1450x920x1590
2050
500 kVA
1710x1020x1700
2400
750 kVA
1750x1020x1780
2900
1000 kVA
1880x1070x1820
3400
(b) Table 6-11: Maximum dimension and weight for new power transformer 33/11 kV Transformer
Complete Installation Arrangement
Transport Arrangement
L x W x H (mm)
Total Weight (kg)
L x W x H (mm)
Total Weight (kg)
1.5 MVA
2380x1400x2460
5500
2380x1400x2460
5500
5 MVA
3500x3300x3400
15000
3400x1480x2540
12000
7.5 MVA
5890x3140x3120
20000
3640x3020x3120
16550
15 MVA
6160x3730x3380
32300
3940x3730x3380
28750
30 MVA
7390x3900x4120
46800
4390x3900x3190
41900
30 MVA (33/22-11 kV)
7260x4950x4710
54350
4760x4950x3370
49300
Primary Equipment
6.1.5.8.
197
Fittings and Accessories
Transformers are provided with the following standard fittings and accessories: 6.1.5.8.1.
Bushing Terminals
Distribution and power transformers are equipped with outdoor type oil-air bushings made of solid porcelain on HV and LV sides for both phase and neutral terminals. All conducting parts of the bushing are designed for rated current of the transformers and capable to withstand overcurrent during earth fault and cyclic overloading. New distribution transformers come with cover-mounted open bushings whilst most of power transformers have side mounted bushings in air filled cable box. For distribution and power transformers, crimping type terminal lugs are provided where they are bolted onto the HV and LV bushing terminals. For new LV bushing design, bushing flag is provided on the LV and neutral terminals for the cable lug connection. Table 6-12: Crimping type terminal lugs for distribution transformers Transformer Rating
HV Terminals
LV Terminals
6.6, 11, 22, 33 kV
Phase
Neutral
100 kVA
1 x bimetal lug for 2 70 mm Al cable
1 x bimetal lug for 2 300 mm Al cable
1 x bimetal lug for 2 300 mm Al cable
300 kVA
1 x bimetal lug for 2 70 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
500 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x bimetal lug for 2 300 mm Al cable
1 x bimetal lug for 2 300 mm Al cable
625 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x bimetal lug for 2 500 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
750 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x bimetal lug for 2 500 mm Al cable
1 x bimetal lug for 2 500 mm Al cable
1000 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x tinned copper lug 2 for 500 mm Cu cable
1 x bimetal lug for 2 500 mm Cu cable
1250 kVA
1 x bimetal lug for 2 70 mm Al cable
2 x tinned copper lug 2 for 500 mm Cu cable
1 x bimetal lug for 2 500 mm Cu cable
6
198
Substation Design Manual
Table 6-13: Minimum size for crimping type terminal lugs for Power Transformers
6
Tx Rating
HV Terminals 33 kV
LV Terminals 11 kV
Neutral
30 MVA
3 x tinned copper lug 2 for 400 mm Cu cable
9 x tinned copper lug 2 for 400 mm Cu cable
1 x tinned copper lug 2 for 400 mm Cu cable
15 MVA
3 x tinned copper lug 2 for 400 mm Cu cable
6 x tinned copper lug 2 for 300 mm Cu cable
1 x tinned copper lug 2 for 300 mm Cu cable
7.5 MVA
3 x tinned copper lug 2 for 400 mm Cu cable
3 x tinned copper lug 2 for 300 mm Cu cable
1 x tinned copper lug 2 for 300 mm Cu cable
5 MVA
3 x bimetal lug for 2 150 mm Al ABC
3 x bimetal lug for 2 240 mm Al ABC
1 x bimetal lug for 2 240 mm Al ABC
The minimum air clearances between bushing terminals of a transformers for altitude 1000 meters and below, differs according to space constrains on the transformer. When space is a constraint, air clearance particularly in a cable box shall make reference to Surat Pekeliling Pengurus Besar Kanan (Pengurusan Aset) Bil. A17-2011 and BS 6435 where the minimum air clearance is specified according to the following conditions:
Partially insulated cable box – cable cores only are fully shrouded for the appropriate highest system. Fully insulated cable box – All live metal parts and cable cores are fully shrouded for the appropriate highest system voltage.
Primary Equipment
199
The minimum air clearance for open bushing terminals and bushing terminals in cable box is tabulated in Table 6-14 below. Table 6-14: The minimum requirement for air clearances Open Bushing Nominal System Voltage
415 V
Cable Box
Minimum Clearance Phase-toPhase
Minimum Clearance Live Metalto-Earth
Minimum Clearance Phase-to-Phase
Minimum Clearance Live Metal-to-Earth
77
58
-
-
127 (partially insulated) 45 (fully insulated) 242 (partially insulated) 100 (fully insulated) 356 (partially insulated) 125 (fully insulated)
76 (partially insulated) 32 (fully insulated) 140 (partially insulated) 75 (fully insulated) 222 (partially insulated) 100 (fully insulated)
11 kV
254
203
22 kV
330
279
33 kV
432
381
The minimum creepage distance of the bushing insulator is in accordance with IEC 60137 where the specific creepage distance is typically of pollution Level II (20 mm/kV).
6.1.5.8.2.
Gas actuated relay
Gas actuated relay is also known as Buchholz relay after its inventor. The gas actuated relay is fitted in the connection pipe between the main tank and the conservator. The relay has two functions: To collect free gas bubbles on their way up to the conservator from the transformer tank. To detect abnormal oil flow to the conservator in the event of a serious fault such as arcing within the transformer.
6
200
Substation Design Manual
Figure 6-38: Gas actuated relay
6
Figure 6-39: Buchholz relay cross-section At all times, the gas actuated relay should be filled with oil. When gas is generated in the transformer due to incipient fault, the gas will displace the oil in the relay and float will sink down. The protection is therefore arranged in such a way that when a minor amount of a gas is collected in the gas actuated relay an alarm signal is actuated. If an additional amount of gas is collected tripping contact may be actuated.
Primary Equipment
201
When a serious fault such as arcing occurs in the transformer, the gas evolution will push a burst of oil up towards the conservator causes the lower element to be deflected, actuating the contacts of the tripping circuit, thus disconnecting the transformer from the supply.
6.1.5.8.3.
Temperature indicator
HV WTI
HV WTI
OTI
Figure 6-40: Winding temperature indicators for power transformer (left) & distribution transformer (right) A new distribution transformer uses a top-mounted type thermometer fitted on the transformer tank cover for direct measurement of top oil temperature. For power transformer, the top oil temperature is measured using a sensor or a bulb in the thermometer pocket on the top tank cover. The measurement of winding temperature can be carried out in a direct or indirect method. For a direct measurement, fibre optic sensors can be used to measure the winding temperature. For indirect measurement, a thermal image of the winding can be made to simulate the winding temperature of the HV and LV windings. In this type of measurement, a current transformer on the HV or LV winding supplies the output current to a heating element that produces a temperature rise in addition to the oil temperature measured by the sensing bulb in the thermometer pocket on the top tank cover. The heating element is provided with an adjustable shunt or a calibration circuit so that the precise thermal image can be set by shunting the CT output current. In TNB distribution system, a single CT system is used where only one CT is used on the HV and LV winding respectively.
6
202
Substation Design Manual
Dedicated CT Calibration circuit Calibration circuit Temperature sensing bulb Capillary tube Dial gauge & switches
Figure 6-41: Winding temperature indicator schematic arrangement
6
The temperature of the winding depends on the transformer load and the temperature of the cooling medium. These two parameters are measured and made to interact in the temperature indicator. The winding temperature is therefore measured by adding the temperature difference of the winding to top oil temperature. Fans are preferably activated as soon as the temperature hits the set value, but it is not switched off again until the oil has truly cooled. There should be a 10 degree temperature difference in fan auto start and stop to avoid hunting. The recommended temperature settings are: 1. 2. 3. 4. 5. 6.
Fan auto Start: 70:C Fan auto Stop: 60:C Top oil temperature alarm: 80:C Top oil temperature trip: 90:C Winding temperature alarm: 95:C Winding temperature trip: 105:C
Primary Equipment
6.1.5.8.4.
203
Oil Level Gauge (OLG)
The new hermetically sealed distribution transformer design uses magnetic type OLG, fitted on top of the transformer tank. The indication for maximum and minimum is given by colour coding. The various brands of oil level gauge have different colour coding. The maximum level indicated by the oil gauge should correspond to the level of oil near the tip of HV bushings. For power transformer, magnetic type OLG is used to gauge the level of oil in the conservator for main tank and OLTC. Both magnetic types OLG for power and distribution transformers have a float inside the main tank or conservator tank where the position is transmitted magnetically through the tank walls to the indicator installed on the tank surface.
6
Figure 6-42: Magnetic oil level gauge for (left) the conservator tank; and (right) top cover of hermetically sealed distribution transformers
Pressure Relief Device Oil Level Gauge
Figure 6-43: Conventional oil level gauge and pressure relief device at distribution transformer
204
Substation Design Manual
6.1.5.8.5.
Pressure Relief Device (PRD)
PRD is used to release overpressure build up in the transformer tank so that tank rupture can be prevented. It is a spring operated self-resealing PRD that operate at absolute overpressure between 28 and 35 kPa (4 – 5 psi). PRD for power transformers are equipped with a micro-switch. The operation of the spring will in turn trigger the contacts of a micro-switch and trip the transformer. It should be noted that PRD is not used for alarm indication.
6
Figure 6-44: Pressure relief device for power transformer
Figure 6-45: Pressure relief device for distribution transformer
Primary Equipment
6.1.5.8.6.
205
Dehydrating Breather
The dehydrating breather contains silica gel crystals. During expansion and contraction of transformer oil due to change in temperature, the air passes over the crystals which absorb any moisture in the air. Thus, allowing only dry air goes inside the tank and reducing the amount of moisture absorbed in the oil and winding insulation that can speed up degradation process. Due to moisture absorption, the silica gel changes colour from blue to pink in the course of time. On the other hand, new type of silica gel is cobalt chloride free and is non-carcinogenic. It changes colour from orange when dry to green or colourless when contains moisture. The amount or mass of silica gel used is calculated based on among others the mass of oil used, the maintenance interval and the average thermal cycle of the transformer. Silica gel can be dried and restored to the original colour by heating, though, proper health and safety cautions should be taken. The dehydrating breathers are also provided with an oil trap, preventing continuous contact between the moist air and the silica gel, thus allowing a longer life and lower maintenance of the silica gel.
<10%
35% 50% 60% 90% (a)
(b)
(c)
Figure 6-46: Dehydrating breather showing (a) conventional silica gel, (b) new cobalt free silica gel that changes colour depending on the percentage of moisture content, and (c) oil trap
6
206
Substation Design Manual
Other standard fittings and accessories include: Table 6-15: Standard fittings and accessories of a transformer Standard Fittings
Description
Drain/Sampling valve
The valve is used for sampling and draining oil from the tank. For conservator type transformers, the valve is in the form of either gate, globe or ball type, and is provided at the bottom of the main tank. However for hermetically sealed transformers, the valve should not be operated unless guided by an expert or the manufacturer.
Earthing terminals
Two earthing terminals on opposite long sides positioned closed to the bottom are provided for the tank. Both terminals should be connected to earth at all times during operation.
Top cover earthing connections
External earthing connections positioned diagonally on opposite top corners of the tank are provided for ensuring earth continuity between top cover and main tank.
Core earth terminal
The core earth terminal box is provided for power transformer and located on top of the transformer main tank cover to facilitate testing on transformer core. Only single point bonding from core to the transformer body is allowed to prevent circulating current in the core and metal structure.
6
6.1.5.8.7.
Valves
Figure 6-48 and Table 6-16 below shows typical schematic drawing for valves arrangement and their functions respectively for power transformers.
(a) (b) (c) Figure 6-47: Typical valve used for different functions on power transformers. (a) Showing gate type valve with flanges, (b) Gate type valve with sockets and (c) Plate or butterfly type valve
Primary Equipment
207
Valve Legend Open while transformer is in operation Close while transformer is in operation
Figure 6-48: Schematic drawing showing typical valves arrangement and positions Table 6-16: Description of typical valves and types used for power transformer Item 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.
Description Oil sampling/complete drain valve Filter valve (top) Shut off valve for HV disconnecting chamber Buchholz relay shut off valve Radiator shut off valve OLTC conservator drain valve Return valve for OLTC Oil drain valve for HV disconnecting chamber Oil surge relay shut off valve Main conservator drain valve Suction valve for OLTC
Size 50 mm gate type 50 mm gate type 25 mm gate type 80 mm gate type 80 mm plate type 25 mm socket type 25 mm gate type 25 mm socket type 25 mm gate type 25 mm socket type 25 mm gate type
6
208
Substation Design Manual
6.1.5.9.
Terminal Markings
The terminal markings have been standardised for many years based on the British Standard, BS 171 using the alphabets ABCN and abcn as the phase and neutral symbols. For the 3-phase transformers used in TNB distribution system, when facing the HV side, the position of the HV terminals from left to right are in the order of ABC for delta connected winding or NABC for star connected winding. When facing the LV side, the position of the LV terminals from left to right are in the order of cban for star connected winding or cba for delta connected winding.
n
6
b
a
A
B
a
c
C
N
b
A
c
B
C
Figure 6-49: Typical terminal markings for step-down (left) and step-up (right) transformers
6.1.5.10. Rating Plate Figure 6-50 and Figure 6-51 in the following pages show typical rating plates for distribution and power transformers containing basic design data of the transformers.
Primary Equipment
209
6
Figure 6-50: Example of rating plate for distribution transformer
210
Substation Design Manual
6
Figure 6-51: Example of rating plate for power transformer
Primary Equipment
6.2.
Switchgear
6.2.1.
Overview
211
In “IEC 62271-1 Part 1: High-voltage Switchgear and Controlgear – Common Specifications”, switchgear is defined as a general term covering switching devices and their combination with associated control, measuring, protective and regulating equipment, also assemblies of such devices and equipment with associated interconnection, accessories, enclosures and supporting structures. The distribution system has predominantly indoor air insulated switchgear (AIS) installations while the current trend is to employ gas insulated switchgear (GIS) on the 33 kV network. Ring main units (RMU) are used in the distribution network for the purpose of providing economical ring reticulation systems. Sulphur hexafluoride (SF6) insulated RMUs are being used extensively in the distribution network while existing oil RMUs in the system are gradually being phased out. Switchgears used in TNB distribution network are in the form of extensible metal-enclosed switchboard and complying with IEC Standards such as IEC 62271-100, IEC 62271-200 and IEC 62271-1. The switchgear used in TNB distribution system is designed with specific characteristics to suit the system requirement for safe operation under normal service condition. By definition according to IEC 62271, normal indoor switchgear service conditions are at an altitude of not greater than 1000 m above sea level, within an ambient temperature range not exceeding 40:C, with no solar radiation consideration. The ambient air is not significantly polluted by dust, smoke, corrosive and/or flammable gases, vapours and salt. Also, the relative humidity level shall not exceed 90% for duration of one month and a seismic activity is also not considered as external vibration forces on the switchgear.
6
212
Substation Design Manual
For outdoor switchgear, consideration would be taken into account of the solar radiation, the ambient air may be polluted by dust, smoke, corrosive gas, vapours or salt but does not exceed pollution level II (medium) according Table 1 of IEC 60815. 6.2.1.1.
Enclosure/Panel
Installations are designed so that their insulation capacity, degree of protection, current carrying capacity, switching capacity and mechanical functions conform to TNB requirements. These designs are tested against the IEC standards to verify that the design could withstand and perform within their designated rating. 6.2.1.2.
6
Insulation Material
The rated value for the insulation level of a switchgear must be selected on the basis of the requirements at site, e.g. on a 33 kV or 11 kV network. Consideration is also made for the lightning and switching overvoltage impulses and earthing/neutral configuration. Switchgears used in TNB distribution network utilises these forms of insulation within the switchgear enclosure:
Atmospheric air Fluid form e.g. SF6 gas, oil
Solid insulation are utilised in the metal-enclosed switchgear to provide support to the current carrying conductor within the metal enclosure. Normally epoxy resins insulation is used and they must possess the necessary creepage distance between live parts and earth, also would be able to withstand electrodynamics stresses during short circuits.
Primary Equipment
6.2.2.
213
Air Insulated Switchgear (AIS)
Air insulated switchgears comprise of busbars, circuit breakers and cable termination compartments insulated by air at atmospheric pressure. Busbars are supported by specially designed resin bushing / insulator. Typical air insulated switchgear is as shown in the figure below. (1)
(2)
(3)
(4)
6
(5) (12) (6)
(7) (8)
(11) 1. 2. 3. 4. 5. 6.
(10)
Metering Compartment Railing Drawout VT Truck Pressure Relief Flap Busbar Cable termination
7. 8. 9. 10. 11. 12.
(9) Multi Core Cable Box Earth bar Arc protection Heater Vacuum Circuit Breaker Air Filter
Figure 6-52: Side View of AIS Switchgear
214
Substation Design Manual
6.2.2.1.
Enclosure/Panel
Metal-enclosed switchgear panels normally consist of: 1. 2. 3. 4.
Circuit breaker compartment Busbar compartment Cable compartment LV compartment
6.2.2.1.1.
Circuit Breaker Compartment
To house the withdrawable circuit breaker and the facility to test the circuit breaker in isolated position. A set of metal shutters is provided to cover each 3-phase group of stationary isolating contacts. Each set is capable of being individually operated and padlocked closed. The shutters shall open and close automatically by a positive movement. When padlocked the shutters shall prevent access to the fixed isolating contacts.
6
Figure 6-53: Withdrawable Circuit Breaker Truck
Primary Equipment
215
Metal shutter
Earthing switch
Space heater
Figure 6-54: Circuit Breaker Compartment with safety shutters in closed position (Double Busbar)
Reserve busbar spout
Cable spout
Main busbar spout
Figure 6-55: Circuit Breaker Compartment showing live electrical contacts (Double Busbar)
6
216
Substation Design Manual
6.2.2.1.2.
Busbar Compartment
Busbar is an electrical conductor, adequately insulated at a specific voltage level and capable of carrying a high current and normally a common connection between several circuits in the system. The busbars and connections is in accordance with IEC Recommendations and is continuously rated for the site conditions and currents specified. Any insulating material used as the busbar insulation is capable of withstanding the heating effects of the rated short time current and rated continuous current without permanent deformation or deterioration and complies with IEC 60085 on thermal stability and IEC 60466 on flammability.
6
The busbars shall be adequately supported against short circuit forces and provision shall be made to allow for thermal expansion of the conductors due to normal and pulse load currents and short circuit current. The busbars shall be contained in a separate compartment within the general casing of the switchboard.
Figure 6-56: Busbar compartment in air (AIS)
Primary Equipment
6.2.2.1.3.
217
Cable Compartment
The cable compartment is designed to cater for the connection of the power cables and the switchgear. This is to provide lasting and dependable connection of cable conductors and the switchgear. The methods of connection employed could be of the bolted or the plug in method. In the case of air insulated switchgear panels, cable compartment would cater for a 3-phase air insulated cable box suitable for dry type non thermal termination system. The cable box shall be suitable for terminating the maximum size of the following types of cables: 1. 2. 3.
2
33 kV, XLPE, single core, 630 mm , Aluminium 2 11 kV, XLPE, single core, 500 mm , Aluminium, with M16 bolts 2 11 kV, XLPE, three core, 240 mm , Aluminium, with M12 bolts
Cable bushings should be designed to terminate with the open palm to accommodate bimetal termination lugs suitable for deep indentation crimping in accordance to TNB Distribution Technical Specifications. Provisions shall be made for earthing the body of each cable box. Adjustable cable clamps and cable box base plate with approved cable entry seals that can accommodate different cable sizes shall be provided. For single core cables, ferrous base plate MUST NOT be used to prevent damaging heating effect to the cable due to circulating current that flows on the ferrous plate
Figure 6-57: AIS Cable compartment
6
218
Substation Design Manual
6.2.2.1.4.
LV Compartment
Depending on type of installation, provision for the controlgear and protective relays can be made at the top of the switchgear panels or in the Control Relay Panel.
6 Figure 6-58: Control relay panel at the top of the switchgear
Figure 6-59: Control gear and protective device inside the control relay panel
Primary Equipment
6.2.2.2.
219
Circuit Breakers
Circuit breakers must be capable of making, conducting and breaking off current under normal operational conditions. Furthermore, they have to trip / open in accordance with a defined current / time characteristic under overload and fault condition. This can be achieved with protection relays. Circuit breakers used complies with the requirements of IEC 62271-100 and meets the technical specification of TNB Distribution. All circuit breakers having the same rating shall be identical in arrangement and shall be interchangeable. Operating mechanisms shall be operated electrically by DC Motor, and the operating voltage of the DC motor shall correspond with the specified voltage level at the substation. The operating mechanisms shall have a proven operational endurance equivalent to the mechanical life of the circuitbreaking unit and consistent with a low maintenance requirement. The circuit breaker type is differentiated by its arc extinction medium for example vacuum, SF6 gas and dielectric oil. The type of circuit breakers that has been used in TNB Distribution system is as follows: 6.2.2.2.1.
Bulk Oil/Minimum Oil Circuit Breaker
Bulk and minimum oil circuit breaker utilize transformer insulating oil for arc extinction. In bulk oil circuit breakers, the contacts are separated inside a steel tank filled with dielectric oil while in minimum oil circuit breaker, the three phase contacts are mounted in separate insulated housing filled with dielectric oil. Bulk and minimum oil circuit breaker has been phased out due to environmental and operational issues.
6
220
Substation Design Manual
Figure 6-60: Example of bulk/minimum oil circuit breaker
6 6.2.2.2.2.
Vacuum Circuit Breaker
In vacuum circuit breakers, the fixed and moving contacts are housed permanently inside a sealed vacuumed ceramic bottle. The arc is quenched as the contacts are separated in vacuum. In the MV switchgear range, vacuum is the most predominant insulating medium for circuit breaking.
Figure 6-61: Example of vacuum circuit breaker
Primary Equipment
6.2.2.2.3.
221
Gas Circuit Breaker
Gas circuit breaker employs Sulphur Hexafluoride (SF6) gas for its arc quenching medium. The three phase breaking contacts are individually housed in gas filled insulated chambers at pressures of above 1 bar. The pressure and gas flow for arc quenching is obtained by piston action.
Stationary arc contact
Stationary contact Nozzle
Moving arc contact
Moving contact Piston rod
Cylinder
Piston Opening
Opening
Figure 6-62: Arc quenching mechanism for gas circuit breaker
Figure 6-63: Example of gas circuit breaker
6
222
Substation Design Manual
6.2.2.3.
Earth Switch
Earth switches are installed in switchgears primarily near the cable termination end and in some cases, busbars. Every earthing switch must be able of conducting its rated short-time current without damage. TNB Distribution Division requires that the earth switch be provided to earth the outgoing circuit. Circuit earthing shall be carried out by means of three phase quick-acting fault-making earthing switches which forms an integral part of the switch panel. The design utilised for earth switches is normally of the manual charged spring operation.
6
Figure 6-64: Typical earth switch device used in AIS switchgear 6.2.2.4.
Pressure Relief
For both air insulated and gas insulated switchgears, pressure relief facility is provided to ensure that the any arc discharges that the operating personnel may be exposed to, in the course of their duty e.g. operation of pressure relief devices with arc discharges deflected in all directions, side and rear of panel where operator may be working/ standing. 6.2.2.5.
Indicators
Capacitive voltage indicator is provided for every feeder to give indication if the every phase of the feeder is live or not. Mounted on the front fascia, the indicator typically uses neon bulbs that light up or blink when the circuit is energised.
Primary Equipment
6.2.2.6.
223
Ingress Protection
IEC 60529 defines the Ingress Protection (IP rating) and rates the degrees of protection provided against the intrusion of solid objects (including body parts like hands and fingers), dust, accidental contact and water in mechanical casings and with electrical enclosures. Ingress protection specified for Air Insulated Switchgears in the TNB distribution network is as follows: 6.2.2.7.
IP42 externally & IP4X in-between compartments Interlocks
All switchgears shall be provided with a comprehensive system of strong mechanical interlocking device as well as electrical and software interlocks to prevent any dangerous or undesirable operations. The interlocks are to ensure safety to operators and correct sequence of operation of all circuit breakers, load break switches, isolators, earthing switches. Examples of mechanical interlocking facilities in the TNB Switchgear are:
Switching on the earth switch when the Circuit Breaker in CLOSED position Racking in the CB when the Earth Switch is in CLOSED position
The complete interlock scheme shall be subjected to TNB Distribution Division specification and requirement.
6
224
Substation Design Manual
6.2.2.8.
Typical Rating of AIS Table 6-17: Ratings of air insulated switchgear 11 kV Switchgear
22 kV Switchgear
33 kV Switchgear
50 Hz
50 Hz
50 Hz
2. Rated voltage
12 kV rms
24 kV rms
36 kV rms
3. One minute power frequency withstand voltage
28 kV rms
50 kV rms
70 kV rms
4. Impulse withstand voltage
75 kV peak
125 kV peak
170 kV peak
5. Rated short time current
20 kA rms
25 kA rms
25 kA rms
6. Rated duration of short circuit
3 seconds
3 seconds
3 seconds
7. Rated 15 minutes DC withstand voltage of parts directly connected to power cables
28 kV dc
50 kV dc
70 kV dc
None
None
None
AIS Parameter 1. Rated frequency
6
8. Visible or audible corona
6.2.2.9.
Configuration for 11 kV Bulk Supply Switchgear Table 6-18: Configuration of 11 kV Bulk Supply Switchgear
Requirements VCB Rating Differential Protection Relays
Protection CTs Metering CT Voltage Transformer Ammeter/Voltmeter Relay Test Terminal Block Trip Circuit Supervision
A1 A4 A5 A6 VCB=12 kV, 630 amps. Fault rating at 20kA, 3sec. Busbar = 800 amps Areva Siemens Siemens MICOM 7SD610 Solkor N P541 5P20 600/300/5 Amps for OCEF
5P20 600/300/5 Amps for OCEF Class X 600/300/5 Amps
Not Required Not Required Ammeter to be in built in Relay but voltmeter is required Automatic current shorting and isolating trip circuit to be provided To utilize relay in built functions
Primary Equipment
225
Table 6-19: Configuration of 11 kV Bulk Supply Switchgear (continue) Requirements VCB Rating Protection CTs
Metering CT
B2(A)
B2(B)
C1
VCB=12 kV, 630 amps. Fault rating at 20 kA, 3 sec. Busbar = 800 amps 5P20 600/300/5 amps for OCEF
B2-50 = 50/5 CT B2 -75= 75/5 CT B2-100= 100/5 CT B2-150 = 150/5 CT
B2-200= 200/5 CT B2-300= 300/5 CT B2-400 = 400/5 CT
Voltage Transformer
11/0.11 kV(sq.rt 3)
Ammeter/Volt meter
Ammeter to be in built in Relay but voltmeter is required
Relay Test Terminal Block
Automatic current shorting and isolating trip circuit to be provided
Trip Circuit Supervision
To utilize relay in built functions
Not Required
6 To provide push buttons
Where, A1 – Circuit Breaker with Overcurrent & Earth Fault Protection Relay A4, A5, A6 – Circuit Breaker with OCEF, inclusive of Class X 600/300/5 CT’s with relays for unit protection with specific relays B2 (1) – Circuit Breaker with OCEF Protection Relay and VT &CT for metering (wound) B2 (2) – Circuit Breaker with OCEF Protection Relay and VT & CT for metering (ring) C1 – Bus Section
226
Substation Design Manual
6.2.3.
Gas Insulated Switchgear (GIS)
In Gas Insulated Switchgear (GIS), all live parts of the gas insulated switchgear are enclosed in a compressed SF 6 gas system. SF6 gas with its good dielectric strength provides the basic insulation medium for the switchgear. Currently, GIS is mandatory for all new PPUs in the 33 kV and the 11 kV Class 1 systems. (11) (1) (2) (10)
(3) (4)
6
(5)
(6) (8)
(9) (7)
1. 2. 3. 4. 5. 6.
LV compartment Relays Gas density meter Single line diagram / semaphore indication CB operating mechanism Live indicator
7. 8. 9. 10. 11.
Current transformer Cable termination Circuit breaker Disconnectors/Isolators Busbar in SF6
Figure 6-65: Example of GIS Switchgear
Primary Equipment
227
13 8 10 12 2 13
1
10
3 9
8
4 5 6
7
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.
2
Three position disconnector Multifunctional protection and control unit Gas density sensor and filling valve Vacuum circuit-breaker Cable socket Inner cone cable connector Plug-in voltage transformer – feeder Pressure relief disk Current transformer or combined current and voltage sensor Pressure relief duct Measuring sockets for capacitive voltage indicator system Busbars Plug-in voltage transformer – busbar
Figure 6-66: Vacuum Interrupter in SF6 enclosure switchgear, with rated three position disconnector (isolator)
6
228
Substation Design Manual
6.2.3.1.
Enclosure/Panel
The gas-insulated and metal-enclosed switchgear has been designed to optimize availability and operator safety. The advantages of having gasinsulated switchgear are as follows:
Insensitive to environmental influences, such as humidity, dust and aggressive gases. To provide high degree of personnel safety by having complete metal enclosure for all live parts.
6.2.3.2.
Cable Compartment
For Gas Insulated Switchgears, the type of termination kits to be supplied with each panel shall be of the inner cone or outer cone system and shall be designed for use on the various types of cables used by TNB. The termination kits are type tested in accordance with the relevant IEC Standards.
6
Figure 6-67: Cable termination compartment with inner cone connectors
Primary Equipment
229
Figure 6-68: Cable termination compartment with outer cone bushings
6.2.3.3.
Vacuum Circuit Breaker
GIS only utilises vacuum circuit breakers (VCB) as the breaking mechanism. In vacuum circuit breakers, the fixed and moving contacts are housed permanently inside a sealed vacuumed ceramic bottle. The arc is quenched as the contacts are separated in vacuum.
2 1
1. 2.
Circuit breaker compartment with front cover on CB compartment with front cover removed
Figure 6-69: Typical fixed type circuit breaker used in GIS
6
230
Substation Design Manual
Vacuum Interrupter
Contact fingers (fixed type)
6 Figure 6-70: Typical Fixed Type CB used in GIS 6.2.3.4.
Pressure Relief
In the event of an internal fault, a pressure relief device operates before the internal pressure exceed design pressure limit of the switchgear. The pressure relief device should direct all the harmful gases and by products of the internal fault away and safely from the operating personnel. 6.2.3.5.
Indicators
Another important indicator is the SF 6 gas level gauge, also called manometer. The manometer gives indication whether sufficient level of SF 6 is present inside the tank especially prior to operation of the switches.
Primary Equipment
6.2.3.6.
231
Ingress Protection
Ingress protection specified for Gas Insulated Switchgears in the TNB distribution network is as follows: 6.2.3.7.
IP42 externally and IP65 for gas enclosures Interlocks
The interlocks are to ensure safety to operators and correct sequence of operation of all circuit breakers, load break switches, isolators, earthing switches. For gas insulated switchgear, interlocks are enabled during operation of isolators when the circuit breaker is in CLOSED Position. 6.2.3.8.
Disconnector/Isolators with Earthing
Disconnectors are mechanical switching devices which provide an isolating distance in the open position. They are capable to open or close a circuit if either a negligible current is switched or there is no significant change in voltage between the terminals of the poles. Currents can be carried for specified times under normal operating conditions and under normal conditions. In gas-insulated switchgear, the earthing of the feeder is often achieved by the earth-switch and completed by the closing of the circuit breaker 6.2.3.9.
Typical Rating of GIS Table 6-20: Rating of Switchgear Panels
Rating of Switchgear Panels a b c d e
Feeder Panel Transformer Panel (LV Side) Transformer Panel (HV Side) Bus Section Bus Coupler
11 kV
33 kV and 22 kV Transformer Capacity
630 A 2000 A
90 MVA 1250 A 2000 A
45 MVA 1250 A 2000 A
30 MVA 1250 A 2000 A
N/A
N/A
N/A
1250A
2000 A N/A
2000 A 2000 A
2000 A 2000 A
2000 A 2000 A
6
232
Substation Design Manual
6.2.4.
Ring Main Units (RMU)
6.2.4.1.
Overview
In general, the Ring Main Unit (RMU) is a combination of two units of switches, which are Load Break Switch (LBS) for the incoming and outgoing feeders and switch-fuse or circuit breaker for the transformer T-off feeder. All these switches are contained inside a tank filled with insulation. To operate the switches inside the tank, operating mechanisms are mounted externally on the tank and actuated manually using operating handles. When SCADA function is required, motors connected with RTU for communication and battery charger for dc supply are installed within the operating mechanisms to enable switches to be operated remotely or via supervisory.
6
In TNB, the RMU is the switching equipment used extensively in the 11 kV and 22 kV systems as it suits the system configuration and protection practice. Additionally, the RMU offers the following advantages: (a) (b) (c) (d)
Economical Ease of maintenance Space saving Suitable for indoor and outdoor use
The suitability of indoor and outdoor applications depends on the degree of protection of the RMU (Ingress Protection (IP) rating). IP42 is suitable for indoor while outdoor applications require a minimum of IP54. To achieve the IP54 requirement, the RMU is clad with mild steel enclosure to cover the front fascia. The definition of this IP is given in Appendix C.
Primary Equipment
233
SF6 tank
Operating mechanism
Figure 6-71: Example of operating mechanisms mounted on the tank in a RMU (the front fascia of this RMU was removed) Different types of RMU configuration (number of LBS and switch-fuse/circuit breaker in the RMU unit) are used depending on the network requirement at the substation. Typical configurations used in TNB are:
2L + 1T or 2S+1F ( referring to 2 LBS and 1 switch-fuse/circuit breaker) 2L + 2T or 2S+2F 3L + 1T or 3S+1F 3L + 2T or 3S+2F 3L of 3S
For the insulation, RMU can either use mineral oil or Sulphur Hexafluoride (SF6) gas. The insulation is responsible to clear the arc during operation. Other than that, the insulation will also assist in cooling the bus-bar and the switch blade inside the tank. In TNB, the RMU installed in the system is currently of SF6 gas insulated.
6
234
6
Substation Design Manual
(a) (b) Figure 6-72: (a) Example of an outdoor RMU with front enclosure to achieve IP54 requirement (b) When the enclosure is opened, the front fascia can be accessed for operation and to observe indications.
Figure 6-73: An Example of Indoor RMU (Toprank Model TPM)
Primary Equipment
235
The typical ratings for the RMU are given in the following table. Table 6-21: Typical ratings for the RMU Parameters Continuous normal current Short-time Withstand Load break switch Earthing switch Making capacity Load break switch Earthing switch Power frequency withstand Voltage Across earth and between poles Across isolating distance Lightning impulse withstand Voltage Across earth and between poles Across isolating distance
12 kV 630 A
24 kV 630 A
20 kA, 3 sec 2.1 kA, 1 sec
20 kA, 3 sec 2.1 kA, 1 sec
50 kA peak 5.4 kA peak
50 kA peak 5.4 kA peak
28 kV 32 kV
50 kV 60 kV
75 kV 85 kV
125 kV 145 kV
Additionally, the RMU is internal arc tested to minimum 20 kA, 1 second for the tank with accessibility Type A. Internal arc test is a type test used to verify that the RMU is able to withstand the overpressure within the RMU due to fault or flashover and hence to contain the arc internally without endangering the authorised operators present near the RMU. Pressure relief valves are installed on the tank usually at the bottom and are designed to rupture first when there is overpressure inside the tank to release the arc away from the authorised operators. Tank
Pressure relief device
Figure 6-74: Pressure relief device
6
236
Substation Design Manual
6.2.4.2.
Load Break Switch
Switches are mechanical switching devices, which not only make, carry and interrupt current under normal conditions in the network but must also carry for a specific time and possibly make currents under specified abnormal conditions in the network. A load break switch (LBS), as used in an RMU, can be used to make and break a circuit under normal load current. However, it can only make but cannot break the circuit during short circuit or fault conditions. Due to this characteristic, the operating handle supplied with the RMU to activate the operating mechanism of the LBS must have features to prevent inadvertent breaking on fault to occur within 3 seconds after unintentional closing on fault during operation. This requirement can be achieved for example by the use of anti-reflex handle. The LBS is gang-operated to ensure the 3 phases are operated simultaneously.
6
Figure 6-75: Internal view of LBS in Merlin Gerin RM6
Primary Equipment
237
Figure 6-76: Internal view of LBS in Tamco GR1
6
Figure 6-77: Example of anti-reflex handle for LBS (Siemens 8DJ 20)
238
Substation Design Manual
6.2.4.3.
Switch-Fuse
The main function of this switch-fuse is to control the T-off circuit, which is connected to the distribution transformer. Switch-fuse is essentially an LBS connected in series with a fuse. Other than the closing and opening operations, this switch is able to trip and isolate the supply automatically during overload and fault conditions. In order to trip and isolate, a medium voltage fuse is used to trigger the tripping mechanism. Alternatively, the switch-fuse can also be replaced by a circuit breaker to control the transformer T-off feeder. The tripping of this circuit breaker is controlled by a time-lag fuse. The correct ratings of high voltage fuse and time-lag fuse must be ensured for proper protection is achieved. 6.2.4.4.
Interlocks
The RMU is equipped with mechanical interlocking facilities to ensure safety to operators by principally preventing the following operations:
6
Earthing the circuit while it is in live condition Opening the testing access or the cable compartment and the fuse compartment when the circuit is not earthed Switching ON of the circuit when the cable box compartment is opened
6.2.4.5.
Indicators
Capacitive voltage indicator is provided for every feeder to give indication if the every phase of the feeder is live or not. Mounted on the front fascia, the indicator typically uses neon bulbs that light up or blink when the circuit is energised. It is possible to conduct low voltage live phasing of the ring feeders at the capacitive voltage indicator. Another important indicator is the SF6 gas level gauge also called manometer. The manometer gives indication whether sufficient level of SF 6 is present inside the tank especially prior to operation of the switches. 6.2.4.6.
Ingress Protection
IP42 for indoor application and IP54 for outdoor application
Primary Equipment
6.3.
Neutral Earthing System
6.3.1.
Overview
239
TNB distribution practices an “effective system earthing” policy where the source of supply at PMU and PPU must be earthed at the star point on the secondary side of the transformer. This type of earthing system is known as Neutral Earthing System where neutral is earthed by means of solid or resistive earthing. Resistive earthing is achieved by the use of Neutral Earthing Resistor (NER). The main purpose of the NER is to limit the single phase to earth fault to a transformer rated full load current, thus protecting installations, such as cables and transformers from damages due to extreme heat generated by the fault current.
6 NEI
NER
Figure 6-78: Neutral earthing system showing NER & NEI
240
Substation Design Manual
Figure 6-79 below shows a schematic diagram of a Neutral Earthing System setup on the star side of power transformers which consists of NER, Neutral Earthing Isolators (NEI) and associated earthing conductors and devices. Busbar NEI Close
Open
Isolator NEI
Close
Open
Transformer 1 (T1)
6
Solid Earthing
NER
Transformer 2 (T2)
Figure 6-79: Neutral earthing system configuration NER is installed at the star points of a large-capacity transformer that normally exceeds 12.5 MVA. In most cases, transformers rated below 7.5 MVA do not require NER. As such, only solid earthing is required. Table 6-22 summarizes the normal rating of voltage, current and the size of NER and NEI used. Table 6-22: Standard ratings of voltage, current and the size of NER and NEI Power Transformer
NER
NEI NEI Secondary Secondary Voltage Current Voltage Current Voltage Capacity Resistance Busbar voltage current rating rating Rating Rating ratio (kV) (MVA) (Ohm) size rating (V) rating (A) (V) (A) (V) (A) 2 (mm ) 33/22-11 30 22 787 16* 22 1600 10x100 36 1600 33/22-11 30 11 1575 4* 22 1600 10x100 36 1600 33/22 30 22 787 16 22 800 10x100 36 1600 33/11 30 11 1575 4 11 1600 10x100 12 1600 11/33 15 33 262 24 33 800 10x100 36 1600 33/11 15 11 787 8 11 800 10x100 12 1600 22/11 12.5 11 656 16 11 800 10x100 12 1600 22/6.6 12.5 6.6 1093 4 11 1600 10x100 12 1600 *Note: NER dual rating specific for connection of star point transformer dual ratio 33/22-11 kV
Primary Equipment
6.3.2.
Design and Construction
6.3.2.1.
Neutral Earthing Resistor (NER)
241
There are two types of NER i.e. liquid and dry metallic type. Liquid type NER requires frequent maintenance to ensure the electrolyte solution is kept topped up and at the correct ionic strength where the bulk resistance value of the electrolyte must be accurately calibrated so that the value will not increase significantly with the increase in surrounding temperature. Furthermore, dry metallic type NER does not suffer from evaporation, freezing and leakage. For this reason, dry metallic NER is preferred and it has been used as early as 1990 to replace the liquid type NER in PMU and PPU. Dry metallic type NER, comprises of non-corroding heavy duty metallic resistor elements, enclosed in a ventilated cubicle made of stainless mild steel or galvanised steel, suitable for outdoor installation on concrete flooring.
6
Figure 6-80: Dry metallic type NER showing the metallic resistor elements (grid)
242
Substation Design Manual
6.3.2.1.1.
Voltage
NER is often described by the system or line voltage of the supply, e.g. 11 kV NER. The maximum voltage that NER actually experiences in service is the line to neutral or phase voltage. The available voltage ratings of the NER in TNB distribution network is as shown in Table 6-22. 6.3.2.1.2.
Continuous Current & Ohmic Resistance
NER is rated by current at phase voltage and it is usually chosen to be equal to or lower than the rated current of the transformer on the star side as shown by the formula below. Ifull
load
MVA
=
3 × Vline
System impedances are ignored. This implicitly specifies the ohmic resistance value of the NER as follow.
6
NER =
Vphase Ifull load
By Ohms Law, the ohmic resistance value of the NER can also be calculated by: NER =
V 2 line MVA
Example: For 30 MVA 33/11 kV Transformer, Ifull
load
=
30 3 × 11
= 1574 A
The ohmic resistance value for the transformer is thus, NER =
112 =4Ω 30
Table 6-22 provides a comprehensive list of the current ratings and ohmic resistance values according to the transformer capacity.
Primary Equipment
6.3.2.1.3.
243
Time
Resistors are generally rated to carry their current for a time of 10 seconds. The current will actually flow for a much shorter time than this. The 10 second time is chosen to allow for the occurrence of multiple events. This can happen when auto-reclosers are used. It also allows for the operation of an upstream backup protection device, if the protection relay fails. 6.3.2.1.4.
Insulation Levels
NER never experience voltages in excess of phase voltage. However, insulation level is designed based on the line voltage. This has minimal impact on size, weight and cost of the NER designed for medium voltages. 6.3.2.1.5.
Temperature Rise
Temperature rise is limited to 760°C maximum, in strict accordance to ANSI/IEEE 32, 1972. This was based on the resistor alloy and insulation technology available in 1972. Current technology may allow for a rise of 1000°C, maximum. The specification of a 1000°C design may significantly reduce size, weight and cost. 6.3.2.1.6.
Temperature Coefficient of Resistance (TCR)
Metallic resistors have a positive temperature coefficient of resistance (TCR). This means that the current flowing will not exceed the rated value. Current reduces as the NER warms up. In general the TCR is limited to 3.5% per 100°C rise. 6.3.2.1.7.
Termination
NER has three main terminals or connection points. The first terminal connects one end of the resistor to the neutral of the transformer. The second terminal connects the remaining end of the resistor to earth. The third terminal provides enclosure earth bonding. The enclosure earth terminal and resistor earth terminal is separated to facilitate for testing on site.
6
244
Substation Design Manual
The resistor neutral terminal is typically in the form of a porcelain bushing rated for the line voltage. The resistor earth terminal is typically in the form of a bushing rated for 1.2 kV. The enclosure earth terminal is usually in the form of a M12 stud. 6.3.2.1.8.
Ingress Protection (IP) Rating
The NER in TNB distribution network is typically designed to have the degree of ingress protection for the enclosure of at least IP23 in accordance with IEC 60529. The materials used within a NER typically include resistive alloys, stainless steels, ceramics, galvanised steel and copper. All of these materials are durable in harsh environments. Hence the need for stringent environmental protection is low.
6
Higher IP ratings of the NER in excess of IP54 can significantly restrict the escape of heat from the resistor. High IP requirement thus can significantly increase size and weight of the NER to cater for effective heat dissipation. This will result in higher cost. NER is hot during and after operation. The IP rating does not infer that it is safe to touch the NER. 6.3.2.1.9.
Enclosure
The enclosure is made of stainless mild steel or galvanised steel for free maintenance. 6.3.2.1.10.
Neutral Earthing Interlock
The NER is normally provided with interlocking mechanism so that it can be interlocked (electrical or mechanical) with the 33/11 kV transformer incoming circuit breaker. The interlock works in such a way that it is not possible to close the transformer 11 kV incoming circuit breaker if its respective earthing link is open.
Primary Equipment
6.3.2.2.
245
Neutral Earthing Isolator (NEI)
NEI is a simple switching mechanism to provide isolation of the NER for maintenance of any section of the substation. The NEI is designed for outdoor operation, complete with supporting steelwork with minimum safety clearances in accordance with IEC 60071. The Isolators are typically single pole double air break, centre rotating post type with minimum 50 degree blade opening and is of wall mounted type. Neutral busbars is made of tinned copper. The isolator blade is made of copper where its tip is coated with silver for good electrical contact. The neutral earth switch is normally provided with vertical drive rod and mechanism box. The adjustable drive rod is made of galvanised steel pipe with length and diameter suitable for easy operation. Adjustable rod clamp is also provided to allow for on-site adjustment of the vertical drive rod. Neutral cable connections to the NEI shall be insulated with non-thermal termination kit. The typical ratings of NEI use in TNB distribution network was tabulated in Table 6-22 and Figure 6-81 shows typical arrangement of NEI for 11 kV 1600 A ratings. 6.3.2.2.1.
Ratings
The ratings of the NEI namely, voltage, impulse withstand voltage continuous current and time are designed to be at least equal to the ratings of the NER. The minimum short circuit current rating of the NEI is shown in Figure 6-22 below. Table 6-23: Minimum short circuit current rating of the NEI NEI Rated Voltage
Short Circuit Current
11 kV
20 kA, 3 secs
22 kV
20 kA, 3 secs
33 kV
25 kA, 3 secs
However, most of the NEI used in the system is often rated at 25 kA, 3 secs.
6
246
Substation Design Manual
50˚ blade opening
NEI busbar Adjustable drive rod
Disconnectors Vertical drive rod Non-thermal termination
Adjustable drive clamp
Mechanical switch assembly Connection from transformer 1
Connection from transformer 2
Figure 6-81: Typical arrangement of NEI rated at 11 kV 1600 A
6
6.3.2.2.2.
Size of Conductors
The conductors are sized so that they are capable of carrying the continuous current rating of the NER. The typical size of the main busbar conductors was summarized in Table 6-22. 6.3.2.2.3.
Clearance
The air gap between terminals of the same pole with the isolator open is designed to be of a length to withstand a minimum impulse voltage wave of at least 115 percent of the specified impulse insulation rating to earth. The typical distance of the gap between the terminals of the same pole for NEI rated at 33 kV is 500 mm. 6.3.2.2.4.
Ancillary Equipment
NEI installations should be equipped with the following accessories: i.
ii.
2 units of outdoor ring current transformer (CT) of Class X and frequency 50 Hz for REF protection. The knee point voltage V KP and CT resistance RCT are to be determined based on the relaying scheme. 2 units of outdoor ring CT of Class 5P20, frequency 50 Hz and burden 15 VA for SBEF protection.
Primary Equipment
247
Sample calculation to determine REF and SBEF CT ratios for 30 MVA 33/22 kV transformers neutral earthing system is as follows.
NER
22,0002 30,000,000
16
INER = IEF = IFL ≈ 800A
IFL = 524.9A ≈ 600A
CTSBEF = 800/5A 900/1 A
3
800/5 A
3
30 MVA 33/22 kV
SBEF
REF
IFL = 787.3A ≈ 800A
NER
CTREF 600
33 / 1 900 / 1A 22
22 kV 800 A 16 Ω
6 Sample calculation to determine REF and SBEF CT ratios for 30 MVA 33/11 kV transformers neutral earthing system is as follows.
NER
11,0002 30,000,000
4
INER = IEF = IFL ≈ 1600A
IFL = 524.9A ≈ 600A
CTSBEF = 1600/5A
IFL = 1574.6A ≈ 1600A
1800/1 A
3
1600/5 A
3
30 MVA 33/11 kV
SBEF
REF
NER
CTREF 600
11 kV 1600 A 4Ω
33 / 1 1800 / 1A 11
248
Substation Design Manual
In practice, a dual ratio CT is mostly used to cater for upgrading of transformer capacity in the PMU and PPU. Table 6-24 lists the typical CT ratios used according to the transformer ratings. Table 6-24: CT ratios for REF and SBEF protection Power Transformer
NER
Voltage ratio (kV)
Capacity (MVA)
33/22-11
30
Secondary voltage rating (V) 22
33/22-11
30
11
33/22
30
33/11
30
33/11
15
11/33
15
22/11 22/6.6
CT Ratio
Resistance (A)
REF (A)
SBEF (A)
16*
1800/900/1
1600/800/5
4*
1800/900/1
1600/800/5
22
16
1800/900/1
1600/800/5
11
4
1800/900/1
1600/800/5
11
8
1800/900/1
1600/800/5
33
24
600/300/1
600/300/5
12.5
11
16
800/1
800/5
12.5
6.6
4
800/1
1200/5
6 CT 1
CT 2
Figure 6-82: Installation of CT 1 and CT 2 for REF and SBEF protection respectively
Primary Equipment
iii.
249
Neutral Switch Auxiliary Contacts enclosed in stainless steel cubicle for each isolator connecting to Transformers 1 and 2, NER and direct earth connection and is rated for 110 VDC with eight numbers (8 Nos.) of Normally Open and eight numbers (8 Nos.) Normally Close contacts.
Figure 6-83: Neutral Switch Auxiliary Contacts cubicle for indication of the isolator’s open-close operation
6.3.3.
6
Safety
During single line fault to ground, fault current will flow through NER, copper conductor connecting NER to NEI, copper busbar on the NEI and back to the transformer star point via the neutral cable as depicted by Figure 6-84. Red Phase
Star Point
VNER
NER
Yellow Phase
Blue Phase If
Fault
Earthed Sheath Cable
Figure 6-84: Fault current flowing If due to phase short circuit to earth
250
Substation Design Manual
The fault current flowing through the NER will instantaneously produce a voltage across it approximately equal to the value of the phase voltage or VL/√3. For example, the voltage across the NER connected on the star point of a 33/11 kV transformer during single line to ground fault is approximately 6.35 kV. This proves that NER and NEI including all neutral earthing conductors are High Voltage equipment as defined in TNB Safety Rules since during single line to ground fault the equipment will experience phase-toearth voltage of more than 600 V. As such, NER, NEI and all neutral earthing conductors shall be treated strictly in accordance with TNB Safety Rules. In the event where NER is isolated and transformer star point is connected directly via solid earthing, fault current will flow directly to earth. This will produce a voltage approaching the earth potential or 0 V. However, the value of the fault current will rise as no NER is connected to limit the fault current. Hence, when working with NER, NEI and all neutral earthing conductors, the procedures stipulated in Subchapter 6.3.4 shall be strictly observed.
6 6.3.4.
Procedures When Working with NER, NEI and Neutral Earthing Conductors
6.3.4.1.
General Procedures:
(a) The NER Bay shall be locked at all time to prevent anyone from entering the area without the permission from TNB authorized personnel. (b) All TNB personnel or contractors must wear safety shoes provided or approved by TNB when entering the high voltage zone including the NER Bay. (c) All TNB personnel must wear the personal protective equipment (PPE) when operating the high voltage equipment during shutdown and normalization of supply. (d) Only TNB approved wooden ladder shall be used when working in the high voltage zone including the NER Bay.
Primary Equipment
6.3.4.2.
251
Procedures When Working with NER or Conductors Directly Connected to NER for Maintenance, Repair or Replacement Work
Prior to commencement of work on the NER or any parts of the conductors directly connected to the NER, a shutdown of the power transformers connected to the common neutral earthing system must be performed in accordance with Seksyen 3, Aturan Keselamatan Elektrik, Bahagian Pembahagian TNB, where the transformers shall amongst others be made dead, isolated, proven dead and earthed at all points of isolation of supply to the transformers including points of isolation from the neutral earthing equipment.
6.3.4.3.
Procedure When Working with Exposed Neutral Earthing Conductors on Neutral Bushing and Neutral Cable of the Transformer, NEI Busbar or Conductors Directly Connected to the NEI and Transformer Star Point
When work requires direct contact on the exposed metal parts of the Neutral Earthing Conductors on the neutral bushing and neutral cable of the transformer, NEI busbar or conductors directly connected to the NEI and transformer star point, a shutdown of the power transformers connected to the common neutral earthing system must be performed in accordance with Seksyen 3, Aturan Keselamatan Elektrik, Bahagian Pembahagian TNB, where the transformers shall amongst others be made dead, isolated, proven dead and earthed at all points of isolation of supply to the transformers including points of isolation from the neutral earthing equipment.
6.3.4.4.
Procedure When Working with Solid Earthing Conductor
When work requires direct contact on the exposed metal parts of the solid earthing conductor, the respective isolator or disconnector for the solid earthing on the NEI must be made open and any parts of the solid earthing conductor shall be inspected to ensure all connection to the NEI busbar and to any one of the transformer star point is safely disconnected before allowing permission to work.
6
252
Substation Design Manual
6.3.4.5.
Prohibitions
(a) Any work performed on the NER, NEI and neutral earthing conductors that are directly connected to NER, NEI Busbar and star point of any energised transformer is totally PROHIBITED. This is to avoid danger to the personnel resulting from the high voltage produced in the event of single line to earth fault. (b) Bypassing the NER by means of connecting the solid earthing to the neutral earthing system at any time is totally PROHIBITED. This is to protect the respective apparatus such as cables and transformers from damage due to infinitely high fault current due to the absence of the NER. (c) Concealing the neutral earthing conductors underneath the surface of the substation wall is PROHIBITED. The fault current will leak through the wall surface under wet condition and can cause electrical shock to personnel touching the wet wall. Additionally, heat caused by the fault current will cause surface crack and degradation of the wall.
6
6.4.
Medium Voltage Fuse
Medium voltage (MV) fuses are used in the switch-fuse of RMU to provide fast isolation of circuit when there is fault in the distribution transformer or transformer tail on the HV and/or LV side. A fuse interrupts excessive current (or termed as blows) so that further damage to the equipment protected is prevented. MV fuses used in RMU in TNB system are of high rupture capacity (HRC) and back-up current limiting type. A HRC fuse is a fuse that is filled with silica sand surrounding the fuse link. It is used on applications where the fault current needs to be suppressed fast and with no flash over. On a fault current a tremendous amount of heat is created within the fuse. That heat melts the silica sand into glass, and glass being an insulator, suppresses the arc over and breaks the circuit instantaneously.
Primary Equipment
253
MV fuses used in RMU in TNB system are also fitted a striker mechanism. This would provide the user with a visual indication that the fuse link has operated. Striker mechanisms are driven by explosive charges or compressed springs and both are triggered by a thin fuse in parallel with the elements that when a current flows through it, the elements would melt. The current would then heats up the wire and detonates the explosive charge or melt the wire and releases the spring, pushing the striker pin out of the fuse link’s end cap. A suitable mechanism is used to prevent from the pin being pushed back into the fuse body.
End cap
Porcelain barrel
Moisture tight seal
Star core
6 Fuse elements
Granular Quartz Striker coil
Figure 6-85: Front view of MV fuse
Star core
Silver ceramic point contact Striker coil
Granular Quartz
Fuse elements Porcelain barrel
Figure 6-86: Cross-section of MV fuse
Expelled striker
254
Substation Design Manual
Another type of fuse used for transformer protection in RMU utilising circuit breaker is the time lag fuse. This type of fuse, also known as anti-surge, or slow-blow is designed to allow a current which is above the rated value of the fuse to flow for a short period of time without the fuse blowing. This situation normally arises in magnetising inrush current of transformers which can draw larger than normal currents for up to several seconds when first energised.
6
Figure 6-87: Time Lag Fuse
6.4.1.1.
Dimension and Design of Fuse Contact
MV fuses are available in different dimensions and designs of the fuse contacts which are selected according to the types of RMU where the fuses will be used (refer to Table 6-25). For SF6 gas insulated RMU, the MV fuse shall comply with dimension as specified in DIN 43625. Often, this fuse is referred to as MV DIN fuse.
Primary Equipment
255
Table 6-25: Type of fuses in different RMUs No. 1.
Type of RMU SF6 – gas insulated Example: RMU Tamco GR1, RMU Indkom, RMU Merin Gerin RM6
Features Based on DIN 43625 standard
442 mm 22 kV
11 kV 292 mm
2.
Oil insulated with in-air fuse compartment Example: HFU Tamco, HFU Cutler-Hammer
Based on IEC 60282-1 Type III with type D tags
6 Side view
Top view
3.
Oil insulated with the fuse compartment immersed in oil Example: RMU ABB (oil type), RMU Long and Crawford, RMU EPE Rokks
Based on IEC 60282-1 Type II
256
Substation Design Manual
6.4.1.2.
Fuse Rating
The rating of the MV fuse to be used depends on the capacity of the distribution transformer connected to the switch-fuse feeder and is determined based on the following characteristics: (a) Shall provide 3-phase protection against short-circuit current that occurs in the HV or LV side of the transformer (b) Able to withstand transformer inrush magnetising current which is typically 12 x full load current transformers for 100 ms (c) Able to withstand the usual periodic overcurrent up to 150% of transformer full load current (d) Giving discriminatory grading with low voltage (LV) fuses for the highest rating used in the LV system which is 250 A. This is to ensure that the LV fuses operate properly when there is fault in the LV system.
6
Referring to the time-current characteristics for MV fuse, the ratings in Table 6-26 should be observed for 11 kV and 22 kV SF6 gas insulated RMU. Table 6-26: The fuse rating must be suitable with the transformer ratings System voltage
11 kV
22 kV
Transformer capacity (kVA)
Fuse rating (A)
100
16
300
31.5
500
50
750
80
1000
100
100
6.3
300
16
500
25
750
40
1000
50
Primary Equipment
6.5.
Feeder Pillar
6.5.1.
DIN-Type Feeder Pillar
257
Feeder pillars (FP) are used as an LV distribution point from the substation transformer outgoing feeder to the customers. In TNB, feeder pillars used are designed based on standards developed by the German Institute for Standardization or Deutches Institut fur Normung (DIN). Previously, the feeder pillars installed in the system were of the British Standards (BS) design. The design and technology of the DIN-type feeder pillar has been used by TNB for feeder pillar rated at 400 Amps (also known as mini feeder pillar) since 1999. Based on the experience of using DIN-type feeder pillar 400 Amps, TNB has started to migrate to DIN-type feeder pillar for rating 1600 A since 2010, and since 2012 for 800 A rating.
6
Figure 6-88: DIN-type feeder pillar rated at 400 Amps (or mini feeder pillar)
258
Substation Design Manual
Figure 6-89: Example of a BS Type 1600 A feeder pillar
6.5.2. 6
Rational for Using the DIN-Type LV Feeder Pillar
There are several advantages of using DIN-type feeder pillar compared to BS type feeder pillar. The features of DIN type feeder pillar are: 1) 30% reduction of size from the existing BS type feeder pillar 2) Operational safety due to the fully shrouded concept 3) The design which can minimize the risk of vandalism and theft: Red phase, Yellow phase and Blue phase busbars are not easily accessible as the incoming and outgoing units are installed onto the busbars very close to one another with gaps of less than 10 mm between the units. Neutral busbar is also not easily accessible as it is mounted behind the front plate. All bolts and nuts securing the busbars to the feeder pillar frame are applied with special chemical called thread locker to prevent these bolts and nuts from being opened by spanner. No link and fuse carriers are present in the DIN-type feeder pillar as in the BS type. These link and fuse carriers contain copper and are very prone to theft. In the DIN-type feeder pillar, all copper contacts are embedded within the incoming and outgoing unit bodies and are hence difficult to be stolen.
Primary Equipment
259
Copper contacts
Figure 6-90: Copper contacts on fuse carrier of BS-type feeder pillar
6
Copper contacts
Figure 6-91: Copper contacts embedded within the disconnector body of DIN-type feeder pillar
260
Substation Design Manual
6.5.3.
Design and Construction of Feeder Pillar
The design for the 1600 A, 800 A and 400 A feeder pillars (FP) are essentially similar in terms components and functions. The differences lie in the size of current-carrying components used to suit the required ratings, the number of incoming and outgoing units to suit network requirement as well as methods of cable termination.
(1) Instrument panel (4) Fuse-switch disconnector (Outgoing)
(2) Disconnector unit (Incoming)
6
(3) Cable termination
Figure 6-92: DIN-type 1600 A LV feeder pillar In general, feeder pillars consist of four main components as shown in Figure 6-92 and provide the functions as follows: 1.
Instrument panel Instrument panel is only available in FP 1600 A and 800 A. It is frontmounted and is equipped with ammeter with maximum demand indicator and 13 A, 3 pin switched socket outlet. Additionally, the instrument panel is fitted with 60 A cartridge type fuse wired to the blue phase busbar and one neutral link wired to the neutral busbar to facilitate the connection of auxiliary single phase loads such as substation lighting, portable tools, etc.
Primary Equipment
261
Figure 6-93: Close up of the instrument panel 2.
3.
Incoming disconnector unit Rating: 2 x 1000 A (for FP 1600 A and 800 A) Contains copper solid link rated 1000 A or size NH3 Single-pole operated For FP 400 A, the incoming consists of direct terminations of incoming cables onto the busbars. Function: Provide means to isolate the FP from the source/supply Cable termination Cable cores of the incoming and outgoing cables for Red, Yellow and Blue phases are terminated via bolted connection in the termination area provided at the bottom of the respective incoming disconnector and outgoing fuse-switch disconnector units (for FP 1600 A and 800 A).
Figure 6-94: Close up of cable termination for one feeder
6
262
Substation Design Manual
4.
6
For FP 400 A, the incoming cables are directly terminated via bolted connection onto the busbars. The outgoing cables are connected to the termination area provided at the bottom of the outgoing fuse rail units via core clamps. All neutral cores are terminated directly via bolted connection onto the neutral busbar.
Outgoing fuse-switch disconnector Rating: 8 x 400 A (for FP 1600 A), 5 x 400 A (for FP 800 A) and 6 x 160 A ( for FP 400 A) Contains LV DIN fuse blade contact type of size NH2 (for FP 1600 A and 800 A) and size NH 00/000 (for FP 400 A). Depending on the operation requirement the available fuse ratings are as follow: o 125 A, 160 A, 200 A and 250 A for NH2 o 50 A, 80 A and 100 A for NH 00/000 Function: o Provide fast isolation through interruption by fuse when fault occurs at outgoing feeders o Provide means to isolate the outgoing feeders from source/supply
Figure 6-95: LV DIN fuse blade contact type of size NH2 used in the outgoing unit
Primary Equipment
5.
Busbar The phase busbar system is designed to carry the rated continuous current Made of tinned copper with the following minimum copper equivalent dimension: o 80 mm x 10 mm (for FP 1600 A) o 38 mm x 10 mm (for FP 800 A) o 6 mm x 40 mm (for FP 400 A) The neutral busbar has similar material and dimension to the phase busbar. The neutral busbar is connected to the earth bar through braided copper wire.
6.
Feeder pillar enclosure The enclosure is made of electro galvanised steel. Sufficient ventilation is provided to permit natural circulation of air. The doors are equipped with camlock for locking of the doors. The camlock is opened using the Allen Key provided by manufacturer with every feeder pillar. As such, standard padlocks are no longer required to lock the doors. The padlocking facility provided on the door is to enable Authorised Persons to use non-standard lock during shutdown or breakdown as per safety requirement.
Camlock Handle
Padlocking facility
Camlock
Figure 6-96: Camlock with Allen key
263
6
264
Substation Design Manual
6.6.
Current Transformer (CT)
A current transformer (CT) is a device for sensing current flowing through a power system and sending current signal to a protective relay system. The functions of current transformer are: (a) To reduce power system current to lower value for measurement (b) To insulate secondary circuits from the primary (c) To permit the use of standard current ratings for secondary equipment The differences between current transformers (CT) for metering and protection are shown in Table 6-27. Table 6-27: Difference between CT for metering and protection Metering
Protection
1
Used for instrumentation such as ammeter, energy meters, transducer etc.
Used for operation of protective devices such as relays in CBs and reclosers. Can be connected is series with ammeter
2
Accuracy is paramount
Reliability and stability during operation up to accuracy limit current
3
Specified in accuracy class e.g. 0.2 and 0.5
Specified in accuracy and accuracy limit factor (ALF) e.g. 5 P 10, 5 P 20, cl X, S etc.
4
Operate at rated accuracy class between 100%-120% current ratings. Normal operating range is 20%100%. Beyond 120%, CT saturates so no further increase in secondary current with further primary current rise
Accurate from rated primary to accuracy limit (ALF) current
6
Primary Equipment
265
The protective current transformer must be capable of providing an adequate output over a wide range of fault conditions, from a fraction of full load to many times full load. The CT standards are governed by IEC 185:1987, IEC 44-6:1992, BS 3938: 1973, and BS 7626. Characteristics and specifications of the current transformer include:
Current transformer is normally of the dry type design using epoxy resin as insulation and tested to IEC 60044-1. The CT shall be capable of carrying rated primary current for one minute with the secondary winding open. Where open circuit secondary voltage would exceed 3.5 kV, suitable protection shall be provided at the secondary terminals to limit the voltage. The CT is installed on the circuit side of the circuit breaker except on busbar sectionalising and coupling equipment as may be required.
6
(a) Ring type
(b) Wound type
Figure 6-97: MV current transformer
266
Substation Design Manual
Protection CTs
Metering CTs
Figure 6-98: CT for protection and metering inside switchgear
6 6.6.1.
Protection Current Transformer (CT)
The protection CT has the following characteristics: 1.
2. 3.
The output of each protection CT is 15 VA with an accuracy limit factor of 20. The adequacy of these figures can be confirmed by calculation. The CT Class is typically 5P20 for protection. For high impedance unit protection where specified in the specification, class X CT is used. The knee point voltage is confirmed by calculation. The classification of CT for protection is normally written as 5P10 or 5P20; 5 are 5% composite error at 10 or 20 times of the rated current, while P denotes protection CT.
Primary Equipment
6.6.2.
267
Metering Current Transformer (CT)
One of the characteristics for metering CT is the accuracy class that is typically 0.2 and 0.5. This means that the errors have to be within the limits specified in the standards for that particular accuracy class. Specifications of metering CTs for consumers taking 415 V are:
Ratio
:
Is 5A *where Is is the primary ratio of the metering CT
Class
:
0.2
Burden
:
7.5 VA
Unit
:
3 Nos. (One for each feeder)
Standards
:
IEC 60044-1 (1996)
Specifications of metering CTs for consumers taking 6.6 kV, 11 kV, 22 kV and 33 kV (indoor breaker) are:
Ratio
:
6
Is 5A *where Is is the primary ratio of the metering CT
Class
:
0.2
Burden
:
15 VA
Unit
:
3 Nos. (One for each feeder)
Standards
:
IEC 60044-1 (1996)
Table 6-28: Current Transformer (CT) sizes LV CT ratio
100/5, 150/5, 200/5, 300/5, 400/5, 500/5, 600/5, 800/5, 1000/5, 1200/5, 1600/5
MV CT ratio
50/5, 75/5, 100/5, 150/5, 200/5, 300/5, 400/5
An example of metering Current Transformers (CT) installed for each phase is shown in Figure 6-99.
268
Substation Design Manual
Figure 6-99: Example of Metering Current Transformer (CT) Example: Current Transformers (CT) Size Calculation To determine CT size, the following calculation should be done: 𝑃=
6
3 × 𝑉𝑝−𝑝 × 𝐼 × cos 𝜃
𝐼=
𝑃 3 × 𝑉𝑝−𝑝 × cos 𝜃 cos 𝜃 = 0.85
Where:P Vp-p
= Apparent power = Line voltage system I = Line current ampere cos θ = Power factor
For example: I=
500 𝑘𝑊 3 × 0.415 𝑘𝑉 × 0.85 I = 818.36 𝐴
Thus, the suitable CT size is 1000/5 A. Note: Metering CT size should be higher than the calculated value.
Primary Equipment
269
Figure 6-100: Armoured cable is used to connect the CT and PT to the meters
6 Table 6-29: Armoured Cable Configuration Cable No.
Cable configuration
1
S1 terminal red phase current transformer
2
S2 terminal red phase current transformer
3
S1 terminal yellow phase current transformer
4
S2 terminal yellow phase current transformer
5
S1 terminal blue phase current transformer
6
S2 terminal blue phase current transformer
7
Red phase voltage
8
Yellow phase voltage
9
Blue phase voltage
10
Neutral
11&12
Earthing
270
Substation Design Manual
6.7.
Potential Transformer (PT)
Potential Transformers (PT) are used to step down the voltage for measurement, protection and control. TNB Distribution Division only uses electromagnetic type potential transformers. The functions of the PT are for: (a) Measurement/metering (b) Automatic Voltage Regulation (AVR) (c) Protection for directional OCEF relay
6
The PT is normally of the cast resin filled type and it is complies with IEC 60044-2 with a class of 0.5. The rated output of the PT is normally specified at 50 VA per phase but alternatively adequacy can be determined by calculation of the burden. The normal ratio of PT is normally to the rating of 33 kV, 22 kV, and 11kV/110V (3 single phase star-connected and neutral earthed). The PT should be able to be isolated from the circuit during testing by means of isolatable links or withdrawable mechanism.
Figure 6-101 below shows an example of an electromechanical PT and Figure 6-102 shows the location for the PT inside a switchgear compartment.
Figure 6-101: Electromechanical PT
Primary Equipment
271
Potential Transformer
Figure 6-102: Potential Transformers inside the switchgear compartment
6 Specifications of potential transformers are:
Ratio
: Vs
3
110 3 *Where Vs is the supply voltage given to the consumer
Class
: 0.5
Burden
: 50 VA minimum. Sharing between protections and metering PT can be allowed provided that separate fusing is provided and the burden of the shared load does not exceed 10 VA. If the burden of the shared load is more than 10 VA, then 100 VA PT should be used.
Unit
: 3 Nos. (one for each feeder)
Standards
: IEC 60044-2 (1997)
272
Substation Design Manual
Figure 6-103: Potential Transformer Fuse Each PT is equipped with PT fuse normally rated at 3.15 A. This fuse will isolate the PT from the system in the event of fault at the PT i.e. internal winding, secondary bushing. Therefore, the system will not trip or deenergize.
6
However, the fuse will not blow if the fault is at the secondary circuit because the fault current equivalent at the primary side is too small to blow the fuse. Normal practice is to place fuse or MCB at the secondary side to protect the circuit, but they are prone to tampering and nuisance tripping causing incorrect energy consumption recorded by the meter. For the future, TNB will replace these fuses with copper links to avoid PT fuse blow issue and solely depends on OCEF protection to trip if there is any fault caused by the PT.
Secondary Equipment
Chapter 7: 7.1.
273
Secondary Equipment
Overview
Secondary equipment is needed to ensure reliable operation of the primary equipment. They cover the functions of protection, monitoring, control, automation and communication.
7.2.
Protection/Protective Relaying
7.2.1.
Protection System
Protection System is a branch of electrical power engineering concerned with design and operation of primary equipment. It detects abnormal power system conditions to rapidly remove and selectively isolate such conditions from service in order to return affected power system to its normal state. There are 3 main functions of Protection System: 1.
To safeguard the entire system to maintain continuity of supply
2.
To minimize damage and repair costs where it senses fault
3.
To ensure safety of personnel.
7.2.1.1.
Components of Fault Isolating System
Fault isolation system consists of: 1.
Protection Relay / Equipment
2.
Current Transformer (CT) & Potential Transformer (PT)
3.
Circuit Breaker
4.
DC System
Each component above is explained further in the following subchapters. The relationship among these components is as shown in Figure 7-1.
7
274
Substation Design Manual
Protection System Circuit Breaker CT Protection Equipment / Relay
CB Mechanism
Trip Coil
PT
DC System
CT – Current Transformer PT – Potential Transformer CB – Circuit Breaker
Figure 7-1: Fault Isolation System 7.2.1.2.
7
Protection Relay
A protection relay is a device that monitors power system parameters such as current, voltage and frequency input. It triggers alarm or initiate trip to the circuit breaker if the input measured is outside its preset range. Protection relays respond to abnormal system conditions such as short-circuit, open-circuit, overloading, and reverse power flow. Particularly for transformer, it responds to the oil and winding temperature as well as gas pressure. There are 3 types of relays used in TNB Distribution Division system: 1.
Electromechanical relay
2.
Electronics/static relay
3.
Numerical Intelligent Electronic Device (IED)
Secondary Equipment
7.2.1.2.1.
275
Electromechanical Relay
Electromechanical relays are constructed with electrical, magnetic and mechanical components, have an operating coil and various contacts and are very robust and reliable. Time dial sets the stop position of the disk and therefore sets the contact travel distance
Upper poles Metal disk Moving contact Damping contact Fixed contact Direction of torque produced on disk
Current Spring Lower pole
Shaft
Restraining force of spring; normally holds disk at rest against mechanical stop
Pickup point adjusted by selecting current tap
Figure 7-2: Basic principle of electromechanical relay Although this type of relay has been in operation for many years, there are several limitations such as: (a) Demagnetizing problem due to ageing (b) Limited functionality as compared to numerical relays
7
276
Substation Design Manual
The figure below shows an example of CDG 36 type electromechanical relay.
Figure 7-3: Electromechanical relays (CDG 36)
7
7.2.1.2.2.
Static Relay
Static relays with no or few moving parts became practical with the introduction of the transistor. Static relays offer the advantage of higher sensitivity than purely electromechanical relays, because power to operate output contacts is derived from a separate supply, not from the signal circuits. Static relays eliminate or reduce contact bounce, and could provide fast operation, long life and low maintenance. Limitation for this relay is mainly on the expected lifespan which is approximately based on TNB Distribution Division maintenance policy. An example of a static relay that is used in TNB Distribution Division is shown in Figure 7-4.
Secondary Equipment
277
Figure 7-4: Examples of static relay (MCGG52)
7.2.1.2.3.
Numerical Intelligent Electronic Devices (IED)
Numerical Intelligent Electronic Devices (IED) is a relay that converts voltage and current to digital form and processes the resulting measurements using a microprocessor. The digital relay can emulate functions of many discrete electromechanical relays in one device, simplifying protection design and maintenance. A typical IED contains protection functions, control functions controlling separate devices, an auto-reclose function, self monitoring function, communication functions etc. IEDs receive data from sensors and power equipment, and can issue control commands, such as tripping circuit breakers if they sense voltage, current, or frequency anomalies, or raise/lower voltage levels in order to maintain the desired level.
7
278
Substation Design Manual
Among the features available in a numerical relay include: (a) (b) (c) (d) (e)
Facility for local and remote relay setting Event recording Group setting features Password protected Fault disturbance waveform
One of the advantages of the IED relay is that size is significantly reduced compared to the electromechanical type. Examples of IED relays used in TNB Distribution Division are shown in Figure 7-5.
7
(a) SIEMENS SIPROTEC 7SD61
(b) MICOM P123
Figure 7-5: Examples of Numerical IED relays
7.2.1.2.4.
List of Accepted Relays
TNB implements stringent standard procedure for product acceptance for procurement of relays. The list of the TNB accepted relays is kept and updated by Transmission Protection.
Secondary Equipment
7.2.1.3.
279
Current Transformer (CT) & Potential Transformer (PT)
The Current Transformer and Potential Transformer are part of the components in the switchgear as discussed in Subchapter 6.6 and Subchapter 6.7. 7.2.1.4.
Circuit Breaker
Circuit breaker is primary equipment that isolates faults. The device is as discussed in Subchapter 6.2. Generally, under fault condition, protection relay receives and analyzes information and closes its contacts. This will energize the trip coil inside the CB and operate its opening mechanism to isolate the faulty circuit from the power system. 7.2.1.5.
DC System
Protection system requires uninterrupted and independent power source. Typically, DC supply is preferred over AC supply due to its reliability and immunity to disturbance and surges. DC system is required to power up the relays and CB auxiliaries. It will be further elaborated in Subchapter 7.4
7.2.2.
Protection Scheme
Physically, protection relays are connected to other components such as CT, PT, time-delay relays, auxiliary relays, secondary circuits, trip circuits, auxiliary wiring, fascia, and tripping relays to make up for a protection scheme. This protection scheme is designed to safe guard primary equipment from various type of fault. The design of such scheme varies depending on the:
Type and rating of the primary equipment to be protected Size and the complexity of the substation
Examples of protection schemes are overcurrent earth fault scheme, pilot wire protection scheme, current differential scheme, transformer differential scheme, etc.
7
280
Substation Design Manual
7.2.2.1.
Protection Schemes for PPU
Figure 7-6 shows general protection schemes for PPU. Solkor RF/Current Differential OC/EF 33 kV 33 kV Outgoing 1HO
2HO
Tx Differential Tx Guard OC/EF
Tx2
Tx1
Tx Differential Tx Guard OC/EF
NER
31
OC/EF REF
Bus Section
11 kV Outgoing
7
32
SBEF Tx1 SBEF Tx2
OC/EF Translay
Figure 7-6: Protection schemes for PPU
OC/EF REF
Secondary Equipment
7.2.2.1.1.
281
Underground Feeder
Protection schemes implemented are:
Over Current Earth Fault (OCEF) Current Differential (CD) using fibre optic or Pilot Wire Protection Directional OCEF Other alternatives subject to the network configuration.
7.2.2.1.2.
Overhead Feeder
Protection schemes implemented are:
OCEF Auto reclose Other alternatives subject to the network configuration.
7.2.2.1.3.
Transformer Feeder HV
Protection schemes implemented are:
Transformer Differential OCEF Transformer mechanical protection – refer to Subchapter 6.1.5.8 o Gas activated relay (Buchholz) o Winding and oil temperature o Pressure Relief Device (PRD) Other alternatives subject to the network configuration.
7.2.2.1.4.
Transformer Feeder LV
Restricted Earth Fault Standby Earth Fault OCEF
7
282
Substation Design Manual
7.2.2.1.5.
Busbar
Protection schemes implemented are:
Busbar separation scheme (BSS) - The scheme is to separate the busbar when outgoing feeder fails during fault. Busbar/switchgear protection scheme - TNB Distribution Division employs arc protection technique as the busbar protection scheme. It comprises of: o Master relays installed at independent arc protection panel for transformer LV incomers and feeder incomers. o Slave relays located in switchgear, and o Sensors in switchgear and busbar compartments.
Current input to the scheme is taken from the LV incomer. The scheme is such that outgoing feeder breaker will trip for downstream fault in the switchgear and the scheme will trip LV incomers for busbar fault. In case of a transformer breaker failure or delays to open, an intertrip to HV transformer feeder will take place.
7
VAMP 220 (Master) Master
Master VAMP 220 (Master) Ib> T2
T2
VX010 (Slave)
VX010 (Slave) CB1
T1
CB2
T1
CB3
X2
X1
Sensors
Figure 7-7: Example of Arc Protection Scheme
Secondary Equipment
7.2.2.2. 7.2.2.2.1.
283
Protection Schemes for 11 kV Stations Underground Feeder
Schemes implemented for underground feeder protection are:
Over Current Earth Fault (OCEF) Current Differential (CD) using fibre optic or pilot wire protection (Translay) Directional OCEF Other alternatives subject to the network configuration.
7.2.2.2.2.
Overhead Feeder
Schemes implemented for overhead feeder protection are:
OCEF Other alternatives subject to the network configuration.
7.2.2.2.3.
11kV/0.4kV Distribution Transformer Feeder
Scheme implemented for 11kV/0.4kV distribution transformer feeder protection is:
OCEF
7
284
Substation Design Manual
7.3.
Control
Control hierarchy is designed in TNB equipment to ensure safety to personnel in the field by restricting the permission to control the equipment. It comprises: 1. 2. 3.
Local Control (Highest Priority) Remote Control (Second Priority) Supervisory (Least Priority)
This priority determines how the internal wiring will be designed. Descriptions of the controls are as follows: 1.
Local Control Personnel are required to do switching at the equipment or switchgear. This facility is to facilitate maintenance, inspection and emergency operation.
2.
Remote Control In this mode, personnel are required to do switching activities from the control room.
7
Permission for switching from supervisory is determined here. 3.
Supervisory Control Switching activities are done from Regional Control Centre (RCC), where principal items of substation are controlled and monitored via SCADA system. The SCADA is covered in Chapter 8.
Secondary Equipment
7.3.1.
285
Control Hierarchy for PPU
For PPU, the control hierarchy is achieved by using the Control and Relay Panels (CRP). CRP facilitates centralized control, monitoring and status of primary equipment in that particular substation. The control panel incorporates: (a) Protection relays (b) Alarms fascia - Alarm handling facilities for operational personnel (c) Switches - Inclusive of control switches (discrepancy switch), remote/supervisory switch (d) Analogue meter (Ammeter and Voltmeter) - Indicating actual current and voltage reading. (e) Auto/Manual trip counter for circuit breaker - Auto is for cumulative number of CB tripping while manual is for cumulative number of CB opening. (f) Auxiliary relays (g) Interposing transformers - An instrument installed in overcurrent circuit to protect transducer, ammeter. (h) Fuses (i) Links (j) MCBs (k) Test terminal blocks - Facilities for secondary testing. (l) Transducer - An equipment to provide remote on line system parameters. (m) Semaphore - Visual indication of the status or position of its primary equipment. (n) Mimic and labels - A representation of the primary equipment and its voltage rating. - In the mimic diagram, the breakers are systematically numbered/coded.
7
286
Substation Design Manual
The colour coding for the mimic as practiced in TNB are as follows: Table 7-1: Colour coding for the mimic Colour
Voltage
Yellow
11 kV
Blue
22 kV
Red
33 kV
Green
132 kV
Brown
275 kV
Black
Neutral/Ground
Metering Windows Alarm Fascia Protection Relay
7
Mimic Diagram & Control
Figure 7-8: An example of Control and Relay Panels In the mimic diagram, each circuit breaker is uniquely numbered for ease of identification. These numbers are always referred to during operation. The standard numbers are as explained in Subchapter 3.3.1.
Secondary Equipment
7.3.1.1.
287
Interlock
Mechanical and electrical interlocks are included on mechanisms and in the control circuits of apparatus installed in substations as a measure of protection against an incorrect sequence of manoeuvres by operating personnel. The common interlocks are: 1. 2. 3. 4. 5. 6.
7.3.2.
Opening & closing of NER Opening & closing of transformer isolator Insertion of PT Transformer HV and LV opening and closing interlock Busbar live transfer Earthing interlock
Control Hierarchy for 11 kV Stations
Generally, for 11 kV stations only the local control mode is available. If the station is equipped with Remote Control Box (RCB) the three levels of control hierarchy can be achieved. The Remote Control Box (RCB) can be incorporated into existing 11 kV circuit breaker / RMU to provide control and indication of the circuit breaker / LBS (RMU). The control panel incorporates: (a) Two different coloured lamps to show the status of the circuit breaker/LBS (RMU): i. Green lamp : “OFF” condition of circuit breaker/LBS (RMU) ii. Red lamp : “ON” condition of circuit breaker/LBS (RMU) (b) Feeder signal (c) Station alarm (d) Switches i. Supervisory remote switches ii. Open/close switch iii. Earth switch
7
288
Substation Design Manual
The RCB indicators are shown in Figure 7-9.
Figure 7-9: RCB indicators The RCB is SCADA ready for future interconnection with RTU. The signal must include:
7
Supervisory Open Command: signal from RTU to trip circuit breaker Supervisory Close Command: signal from RTU to close circuit breaker Supervisory Indicator: signal to be sent to RTU to indicate the selector switch selected to supervisory mode Remote Indicator: signal to be sent to RTU to indicate the selector switch selected to remote mode CB Open Indicator: signal to be sent to RTU to indicate the circuit breaker “OFF” condition CB Close Indicator: signal to be sent to RTU to indicate the circuit breaker “ON” condition
Each RCB box can control up to 4 feeders. Where space is a constraint, RCB can be mounted outside the substation’s wall as shown in the Figure 7-10.
Secondary Equipment
289
RCB
Figure 7-10: Remote Control Block (RCB) for P/E
7.4.
DC & AC Auxiliary Systems
7.4.1.
DC System
In a substation, Direct Current (DC) system is used to provide power to all auxiliaries such as: (a) Protective devices (b) Tele-control equipment such as Remote Terminal Unit (RTU) (c) Circuit breaker auxiliaries 7.4.1.1.
DC System for PPU and SSU
The DC system for PPU and SSU is rated at 110 V DC; comprising chargers, battery banks (86-88 cells) and DC distribution board. The DC system is of dual parallel redundant chargers with interlocking system and operating in parallel with battery banks.
7
290
Substation Design Manual
Battery charger DC distribution board
Battery bank
Figure 7-11: DC system in the battery room
7.4.1.1.1.
7
Charger
A charger is an equipment that rectifies AC supply into DC. It is used as the main DC source to supply station DC auxiliaries and at the same time to charge the standby battery bank during normal operation.
Charger 1
Charger 2
DC distribution board
Figure 7-12: Dual battery charger panel and DC distribution board (110 V)
Secondary Equipment
7.4.1.1.2.
291
Battery Bank
Battery bank is used as backup to supply station auxiliaries whenever station AC supply fails. It is designed to cater for 5 hours during any station AC supply blackout. It also serves as an extra DC source whenever the station DC load requires supply more than what can be delivered by the charger. Battery banks and battery chargers must be well maintained to ensure that the protection system functions properly.
7
Figure 7-13: A dual battery bank
7.4.1.1.3.
DC Distribution Board
The DC distribution board distributes the 110 V DC supply to the required apparatus, for example CBs trip coil, protection relays and annunciators. The DC distribution board can be seen in Figure 7-12.
292
Substation Design Manual
7.4.1.2.
DC System for P/E with VCB Switchgear
The DC system for P/E with VCB switchgear is rated at 30 V DC. The system comprises charger, battery bank (25 cells) and terminal blocks that are incorporated in a single cubicle as shown in Figure 7-14.
7 Figure 7-14: A typical single cubicle battery charger (30 V DC) in an 11 kV substation
Secondary Equipment
7.4.2.
293
AC System
AC System is required to supply all substation AC auxiliaries such as:
OLTC driving mechanism Remote Tap Changer Control Panel Each Battery Charger Control and Relay Panel – Heater & Lighting Switchgears – Heaters
The AC supply can be derived from:
Local transformer LV Distribution Board (DB) in the case of PPU; or LV distribution transformer or LV mains from SAVR; or Customer AC supply
Figure 7-15 shows an example of an LVAC Switchboard.
7
Figure 7-15: LVAC Switchboard
294
Substation Design Manual
7.5.
Heater
7.5.1.
Heater for 33 kV Switchgears
For 33 kV switchgears, heaters are installed at 3 locations in the switchgear: 1. 2. 3.
Breaker compartment Cable compartment CT compartment
All the heaters are installed in parallel. The power capacity and the number of heaters are dependent on the type/model of the switchgear. The typical ratings for the heaters are given in Table 7-2. Table 7-2: Heater rating 33 kV switchgear Heater Location
Power Rating
Breaker compartment
120 W
Cable compartment
80 W
CT compartment
80 W
7 Fuse
ON/OFF Switch
Thermostat
Heater 3
Heater 2
Heater 1
L
Link N
Figure 7-16: Circuit for heater installation inside 33 kV switchgears
Secondary Equipment
7.5.2.
Heater for 11 kV Switchgears
7.5.2.1.
Heater for 11 kV Switchgears at PPU and SSU
295
For 11 kV switchgears at PPU and SSU, heaters are installed at 2 locations of the switchgear: 1. 2.
Breaker compartment Cable compartment
Both heaters are installed in parallel. The power capacity and the number of heaters are dependent on the type/model of the switchgear. The typical ratings for the heaters are given in Table 7-3. Table 7-3: Heater rating 11 kV switchgear Heater Location
Power Rating
Breaker compartment
80 W
Cable compartment
80 W
Fuse
ON/OFF Switch
Thermostat
L
Heater 2
Heater 1
7
Link N
Figure 7-17: Circuit for heater installation inside 11 kV switchgears
296
Substation Design Manual
7.5.2.2.
Heater for 11 kV Switchgears at P/E
For 11 kV switchgears at P/E, heaters are generally installed at the breaker compartment and cable compartment. However, sometimes a breaker is installed only at the breaker compartment. The power capacity and the number of heaters are dependent on the type/model of the switchgear. These heaters are typically rated at 80 W and 100 W.
7.6.
Secondary Wiring
7.6.1.
DC Wiring
DC wiring is the nerve for the control and the protection of station auxiliaries. 2 Wires of multistrand 2.5 mm grey insulated coloured are used as standard DC wiring. Special tagging is required for tripping circuits whereby the wires should be labelled with red coloured TRIP tagging.
7.6.2. 7
AC Wiring
AC wiring is the nerve for all the AC station auxiliaries. 2 Black coloured 2.5 mm wiring 1000 V grade is used for AC circuitries. AC wiring should be segregated from DC wiring for fear that induced AC will be present in the DC system. Special attention should be given to CT wiring as it is required to be colour coded as per the phase that it carries namely RYB and the size of 2 the conductor shall be 4.0 mm . All circuitries are to be numbered for its usage as per BS 158.
Secondary Equipment
297
Wiring for measurement
Wiring for tripping circuit
Figure 7-18: Secondary wiring
7.7.
Metering
The purpose of metering in the substation is as follows: 1.
2.
MV metering (a) For customer taking bulk supply 6.6 kV, 11 kV, 22 kV, 33 kV, 66 kV, 132 kV, 275 kV. (b) For PMU between transmission and distribution (c) For PPU between primary distribution medium voltage (33 kV & 275 kV) and secondary medium voltage (22 kV and 11 kV) (d) For P/E between neighbouring area or ‘Kawasan’ LV metering (a) For customer taking bulk supply more than 100 A (b) for recording substation use or free units
For metering installations up to 33 kV, CTs and VTs shall be provided and installed by TNB at TNB's outgoing switchgear. A floor mounted metering cubicle shall be provided by the consumer in the specified metering room for the installation of TNB meters.
7
298
Substation Design Manual
For LV metering and supply scheme with substation, the meter panel/cubicle is installed inside TNB substation perimeters (refer ESAH).
Figure 7-19: Typical LV meter wall-mounted in a substation
Table 7-4 shows the comparison between MV metering and LV metering. Table 7-4: Comparison between MV metering and LV metering.
7
Voltage
Parameter
MV
LV
CT operated
With PT
Without PT
110 V
415 V
63.5 V
240 V
Phase to phase Phase to neutral Current (max)
5 A (10 A) 1 A (2 A)
5 A (10 A)
Example of MV metering wiring configuration is shown in Figure 7-20.
Secondary Equipment
299
Metering Panel Main meter kWh/kVARh
Check meter kWh/kVARh
Voltage Isolators
Potential Transformer
110 V (Line)
Test Terminal Block
11 kV (Line) PT Fuse (PT)
7
Figure 7-20: MV wiring The main and check meters are located at the front panel of the metering compartment as shown in Figure 7-21. Main meter is on the left side and check meter is on the right side.
Feeder main meter
Feeder check meter
Figure 7-21: Typical MV metering panel with main and check meter
300
Substation Design Manual
7.7.1.
Test Terminal Block (TTB)
The Test Terminal Block (TTB) is located inside the Meter Test Box (MTB) in the metering panel. It is used to isolate the meter from the current source to perform maintenance works on the meters. The number of TTBs required depends on the number of feeder, i.e. 1 TTB per feeder.
(a) TTB connections label
7
(b) Installation with wiring inside MTB Figure 7-22: Test Terminal Block (TTB)
Secondary Equipment
7.7.2.
301
Voltage Isolators
The function of the voltage isolators is to replace fuse to overcome the latter’s disadvantage in terms of possibility to blow. It is used to isolate the meter from the current source to perform maintenance works on the meters. The number of voltage isolators required depends on the number of feeder, i.e. 6 voltage isolators per feeder.
Figure 7-23: Voltage isolators
7.7.3.
Meter Test Box (MTB)
The main function for Meter Test Box (MTB) is to cover and protect the installation of voltage isolators and the Test Terminal Block (TTB). This Meter Test Box (MTB) is installed inside the meter panel. The external view of the Meter Test Box (MTB) is shown in Figure 7-24 whereas the internal view is shown in Figure 7-25.
Figure 7-24: Meter Test Box (external view)
7
302
Substation Design Manual
Voltage isolators
Test Terminal Block (TTB)
Figure 7-25: TTB and voltage isolators inside MTB (internal view)
7.8. 7
Communications
Two types of communication cables exist in TNB, i.e. fibre optics and pilot cables. They are both used for Supervisory Control and Data Acquisition (SCADA), communication and protection system. Currently, TNB only use fibre optics for new installation.
Figure 7-26: Cross-sectional view of armoured pilot cable (left) and an optical fibre cable (right)
Secondary Equipment
7.8.1.
303
Pilot Cable
Typical number of pilot cable pairs currently being used according to distribution network needs are summarised in Table 7-5. Table 7-5: Typical no. of pilot cable pairs used in the distribution system Voltage (kV)
No. of pairs
No. of pair used for unit protection
No. of pair used for SCADA to RCC 1-2 pairs per communication loop
12 pairs 11
1 pair 8 pairs for telecontrol & telecoms
37 pairs 33
37 pairs
17 pairs for telecontrol
1 pair
10 pairs for telecoms
Table 7-6 below shows the diameter resistance and elongation of conductor in completed cable. Table 7-6: Diameter resistance and elongation of conductor in completed cable Resistance of Conductor/km at 0 20 C
Diameter
Elongation
Overall Diameter of Insulated Conductor
Nominal
Max
Min
Max
Min
Nominal
mm
mm
Ω
Ω
%
mm
0.918
0.920
25.32
27.04
18
2.00
Table 7-7 shows the maximum mutual capacitance and capacitance unbalance with the conductor size. Table 7-7: Mutual capacitance and capacitance unbalance Conductor Size
Maximum Mutual Capacitance
Maximum Capacitance Unbalance
mm
µF/km
pF/161m
0.914
60
200
7
304
Substation Design Manual
Table 7-8 shows the core identification for the pilot cable. Table 7-8: Core identification Size 12 Pairs
37 Pairs
Core No. 1
Black/Red
Core No. 2
4
Black/Green
7 10 1 4
7.8.2.
Black/White
5
Black/Yellow
6
Black/Brown
Black/Grey
8
Black/Orange
9
Black/Violet
Red/Blue
11
Red/White
12
Red/Green
Black/Red
2
Black/Blue
3
Black/White Black/Brown
Colour
Colour
Black/Green
5
Black/Yellow
6
7
Black/Grey
8
Black/Orange
9
Black/Violet
10
Red/Blue
11
Red/White
12
Red/Green
13
Red/Yellow
14
Red/Brown
15
Red/Grey
16
Red/Orange
17
Red/Violet
18
Blue/White
19
Blue/Green
20
Blue/Yellow
21
Blue/Brown
22
Blue/Grey
23
Blue/Orange
24
Blue/Violet
25
White/Green
26
White/Yellow
27
White/Brown White/Violet
28
7
Black/Blue
Core No. 3
Colour
White/Grey
29
White/Orange
30
31
Green/Yellow
32
Green/Brown
33
Green/Grey
34
Green/Orange
35
Green/Violet
36
Green/Brown
37
Yellow/Grey
Optical Fibre
There are two types of fibre optic used in TNB Distribution Division: 1. 2.
Slotted Loose tube
The loose tube type is more preferable as it is easier to do splicing whereas the slotted type requires a special splicing machine.
Secondary Equipment
305
Fibre optic cables provide better performance compared to pilot cables. The reasons behind the use of optical fibre cable as against pilot cables are: (a) (b) (c) (d) (e) (f) (g) (h)
No signal degradation Immune to electromagnetic interference No electrical interferences Higher speed and longer distance coverage Support more RTUs in a communication loop Less repeater needed to boost signal for long distance Better dependability and security Lower capital costs
Table 7-9 and Table 7-10 show the underground fibre optic cable specifications and underground fibre optic characteristics. Table 7-9: Underground fibre optic cable specifications Particulars Cable sheath material
Construction
Cable marking Mechanical properties
Optical properties
5
Details 1. 2. 3. 1. 2.
UV resistant Fungus resistant Black colour Slotted tube or loose tube construction 24 single mode fibres compliant to ITU-T 5 G.652.C 3. Resistant to water penetration 4. Non-armoured and non metallic Adequate cable identification and marking 1. Proof test (whole length) is 1.0% strain during ≥ 1.0sec 2. Stress corrosion factor (n) is ≥ 18 3. Weibull modulus (calculated from 60% of the fractures) is ≥ 40 Compliant to ITU-T G.652.C
Refers to the fibre optic cable that fulfils the needed criteria to support applications up to capacity of STM-16, and permits the transmission of extended wavelength between the range of 1360nm to 1530nm.
7
306
Substation Design Manual
Table 7-10: Underground fibre optic characteristics Description Fibre type
Silica/Silica doped, Single Mode
Maximum attenuation
0.40 dB/km at 1310 nm 0.25 dB/km at 1550 nm
Average attenuation
≤ 0.35 dB/km at 1310 nm ≤ 0.23 dB/km at 1550 nm
Mode field diameter Peterman II
(8.6 µm – 9.5 µm) ± 0.6 µm @ 1310 nm
Cut-off wavelength
1150 nm – 1330 nm (fibre) ≤1260 nm (cable)
Zero dispersion wavelength
1300 nm – 1324 nm
Maximum dispersion/chromatic
≤ 3.5 ps/(nm*km) at 1310 nm ≤ 18 ps/(nm*km) at 1550 nm
Maximum zero dispersion slope
0.092 ps/(nm *km)
Cladding diameter
7
Details
Attenuation at bending of fibre Attenuation at 1310nm for 100 turns, ø40mm Attenuation at 1550nm for 100 turns, ø60mm
7.8.2.1.
2
125 ± 1 µm
≤ 0.05 dB ≤ 0.05 dB
Cable Sheath
The supplied fibre optic cable is black track resistance high-density polyethylene. The typical value of the dielectric strength is in accordance to IEC 60243 test method. Outer sheath surface is smooth with no irregularities.
Secondary Equipment
7.8.2.2.
307
Colour Coding
The fibre cores are colour-coded using ANSI/TIA/EIA-598-A standard colour codes for ease of identification, as listed in the following table. Table 7-11: Fibre colour coding Fibre/Tube no.
Colour
1 2 3 4 5 6 7 8 9 10 11 12
Blue Orange Green Brown Slate / Grey White Red Black Yellow Violet Rose / Pink Aqua / Turquoise
The fibre core groups for the slotted type cable need to be easily identified by slot Identification markings. 7.8.2.3.
Fibre Optics Boundary of Responsibility
TNB Distribution Division has developed fibre optic infrastructure in power system to replace the pilot cable as a telecommunication medium. In order to ensure efficient management of the fibre optic infrastructure, TNB Distribution Division has agreed to hand over the fibre optic infrastructure to ICT Division (Fibre Optic Distribution Management Charter between ICT 6 Division and Distribution Division, June 2012) . The ICT – Distribution Operational Boundary is shown in Figure 7-27.
6
Fibre Optic Distribution Management Charter between ICT Division and Distribution Division, June 2012
7
308
Substation Design Manual
Patch panel & patch tray
Underground Fibre Optic Cable
110/24 VDC Power Supply (PPU)
Telecommunication equipment MDF/DDF
RTU Communication Box RTU Multi-core/ Control Cable RTU/SCS
Equipment 1
Equipment 2
Legend Distribution ICT
Figure 7-27: ICT – Distribution operational boundary
7
7.9.
Other Secondary Equipment
7.9.1.
Earth Fault Indicator
Earth Fault Indicators (EFI) was introduced in the 11 kV underground systems since 1990 (Arahan Ketua Jurutera Pembahagian 25/90 & 25/90A). The key objective of the EFI installations is to reduce the restoration time through identifying the faulty section in the network. Optimal use right placements and correct installations of the EFI are one of the factors that could contribute towards achieving the targeted key performance index measured by System Average Interruption Duration Index (SAIDI). Typical earth fault indicators are shown in Figure 7-28 and Figure 7-29.
Secondary Equipment
309
A complete unit of EFI consists of: A split-core current transformer – to detect fault current in cable core Indicator unit – for indicator unit, they have two functions: i. Controller box (a) Consist of DIP switch for EFI setting (b) Function as a brain of the EFI where the indicator will blink during fault ii. LED Lens (a) Show indications during fault
(a) Soule Bardin
7
(b) Cabletroll
CT Ring EFI Controller box
LED Indicator
(c) Endau
Figure 7-28: Earth Fault Indicator
310
Substation Design Manual
Figure 7-29: Components inside Earth Fault Indicator 7.9.1.1.
Working Principle of EFI
The EFI used in TNB Distribution Division system is designed to operate in a normally open-ring system with non-automatic feeder switches at all the distribution substations. It basically consists of two components, a core balance current transformer and an indication facility.
7
Its current transformer is attached at the outer sheath of the 3-phase 11 kV cable in each installation either at the incoming feeder cable termination or outgoing feeder cable termination of the substation.
Controller Box (EFI)
Transformer Switch
Incoming
Outgoing
CT
Figure 7-30: Layout location for earth fault indicator (EFI)
Secondary Equipment
7.9.1.1.1.
311
EFI Current Sensor
The EFI current sensor is in the form of a CT ring for the detection unit is an encapsulated split – core design suitable for embracing the sheath of:
2
3 core cables of conductor section of up to 300 mm (maximum diameter – 90 mm) 2 3 single core cables of conductor section of up to 500 mm (maximum diameter – 300 mm)
The current transformer needs to be suitable for use in outdoor installations. 7.9.1.1.2.
Detection Unit
The fault passage indicator is required to detect earth fault currents down to a value of at least 40 A. The detection relay provides for multiple, discrete user settable earth fault current pick up values with a minimum range of 40 A to 240 A. It provides for user settable operation delay time with a minimum range 50 ms to 150 ms. The detection unit is mountable on the inside or outside wall of an indoor type substation or on a compact substation. The enclosure should be at least of protection index IP54 to IEC 529. 7.9.1.1.3.
Signalling Device
The indicator may be a separate unit in itself or form an integral part of the whole device. Indication (light indicator) of the passage of fault current which operates, remains in operated position until reset. The indicator may be mounted on the outside wall of an indoor type 11 kV distribution substation or on some support for an outdoor substation remote from the detection relay.
7
312
Substation Design Manual
CT Ring
Figure 7-31: Location of CT ring
7 EFI Controller Box
Figure 7-32: EFI controller box inside P/E
Secondary Equipment
7.9.1.2.
313
EFI Placement
The placement of EFI is recommended to be placed at outgoing feeder of substations. 7.9.1.3.
EFI Installation
The correct installation of EFI current transformer (CT) is shown as follows in Figure 7-33 and Figure 7-34.
Switchgear body BADAN PERKAKASUIS TAJUK
DILUKIS DISEMAK
GASKET Gasket
SKRU Screw
EFI
CABLE BOX-4
WILAYAH PAHANG
CABLE BOX Cable Box
SOKET 200A Socket 200A
DAERAH TEMERLOH
NO. FAIL
TN/
GAMBAR 4
SOCKET 200A Socket 200A BUMI P/E P/EBUSBAR earth bar SOCKET 200A Socket 200A
TENAGA NASIONAL BERHAD
S. MOGANADAS
DM
CLAMP DI KEKALKAN DAN DISAMBUNG KE BUSBAR BUMI MELALUI PVC COPPER 19/064 (35mmp) KE BAWAH MASUK DALAM CT EFI
Cable Gland
CABLE GLAND
BUAH PLUMB ATAS DI DALAM CT EFI Through the CT ring
SHEATH Sheath EFI CTCT ring
PENGALIR DARI CT KE EFI Conductor from CT to EFI BUAH PLUMB BAWAH
jumper pvc copper 19/064 (35MMP)
PERKARA
AMOURING CABLE Armouring PILC PILC Cable
MOHAN MANON
Figure 7-33: Installation of EFI for PILC cable
7
314
Substation Design Manual
TAJUK
DILUKIS
Switchgear Body BADAN PERKAKASUIS GASKET Gasket
Screw
SKRU
WILAYAH PAHANG
CABLE BOX-8
CABLE BOX Cable Box LOKASI A Location A
RAYCHEM Raychem
SOKET 200A Socket 200A
GAMBAR 8
DAERAH TEMERLOH
NO. FAIL
TENAGA NASIONAL BERHAD
S. MOGANADAS
P/E earth bar connected BUSBAR BUMI P/E DISAMBUNG to cable TERUS KE CABLEbox BOX
Location B LOKASI B JUMPER PVC COPPER 19/064 (35mmp) ATAU "BRAIDED COPPER WIRE"
Braided copper wire
EFI EFI
KABEL PILC ATAU XLPE XLPE cable
Location LOKASI C C
PERKARA
Figure 7-34: Installation of EFI for XLPE cable
7
MOHAN MANON
7.9.1.4. EFI Settings To ensure that the EFI perform according to its desired function, due care must be given when selecting the right settings for current trip level to avoid any form of mal-operations i.e. unnecessary/false indication OR no operation. To avoid these conditions, the following criterion for setting the EFI current trip level is to be adhered: 𝐼𝐸𝐹 > 𝐼𝑇𝑟𝑖𝑝 > 𝐼𝑇𝐶𝑎𝑝 Where: IEF = Prospective Earth Fault Current of feeder (minimum case) ITrip = EFI current trip level setting ITCap = Downstream capacitive current ITCap can be determined by multiplying the charging current (IC) of the various size of cables with the total length of the cables involved downstream from the location of the EFI.
Secondary Equipment
315
Table 7-12 shows the values of charging current (A/km) of various sizes of XLPE and PILC cables as given by manufacturer. Table 7-12: Charging current per unit length of 11 kV XLPE and PILC cables (Ic – Data from manufacturer) XLPE
PILC
Size (mm )
Rating (A)
Charging Current (A/km)
Size (mm )
Rating (A)
Charging Current (A/km)
150
280
0.7587
25
80
0.82
240
350
0.9359
70
140
0.9399
500
550
1.2695
120
200
1.1614
185
250
1.3849
300
330
1.6982
2
7.9.2.
2
Automatic Transfer Scheme (ATS)
A transfer scheme is an electrical switch that reconnects electric power source from its main source to a backup source. Switches may be manually or automatically operated. In the TNB distribution MV network, an Automatic Transfer Scheme (ATS) is often installed at SSU with two different sources which cannot be paralleled but need to be restored within 10 seconds whenever the main incomer fails.
7
316
Substation Design Manual
(a) ATS scheme installed at switchgear PPU 1
PPU 2
CB 18
CB 1 Multiple P/Es
st
1 Leg Main CB 16675 (PT new installation)
7 CB 16676 (PT-existing)
CB 16677
Backup CB 16678 (PT new installation)
P/E
Consumer (b) Single line diagram
Figure 7-35: Automatic Transfer Scheme without bus section
Secondary Equipment
317
(a) ATS scheme installed at switchgear PPU 2
PPU 1
st
CB 14980 NOP
st
1 Leg
1 Leg
Main CB 14976 Bus section (PT-new installation) open
Main CB 18622 (PT-new installation)
CB 14978 CB 14977 (PT existing)
P/E
CB 14979 (PT existing)
CB 14981 NOP
Consumer substation (b) Single line diagram
Figure 7-36: Automatic Transfer Scheme with bus section
7
318
Substation Design Manual
7.9.3.
Supervisory/SCADA Interposing Panel (SIP)
The Supervisory/SCADA Interface Panel (SIP) interfaces the signal from the Control and Relay Panel (CRP) and switchgear to the RTU in order to enable supervisory control point explained in Subchapter 7.3 from the remote control point. The SCADA Interface Panel (SIP) can be either floor standing or wallmounted.
7 RTU SIP
Figure 7-37: SIP and RTU
Secondary Equipment (1) (2)
(3)
319
(4)
(5)
(6)
(7)
(8)
7
(9) 1 2 3 4 5 6 7 8 9 10
(10)
Description Thermostat Miniature circuit breaker – AC power supply Cubicle illumination lamp Door switch Heater ON/OFF switch Terminal block Terminal block Terminal block (AC bus wiring) Heater Earth bar
Figure 7-38: Supervisory Interface Panel (SIP)
320
Substation Design Manual
Chapter 8: 8.1.
SCADA System
Overview
Supervisory Control and Data Acquisition (SCADA) is a concept used to describe a system that enables control and monitoring of devices or equipment remotely. In TNB Distribution Division, SCADA systems are used to assist the operation and management of transmission and distribution of electricity. The advantages of using SCADA system are optimization of plant processes, and provide operations that are more efficient, reliable and safer. The basic overview of a SCADA system is depicted in Figure 8-1. It consists of three (3) main components: 1. 2. 3.
Master System Communication System Remote Terminal Units (RTUs)
A SCADA system consists of a number of Remote Terminal Units (RTUs) collecting field data and sending data back to a Master System via a communication system. The Master System displays the acquired data and also allows the operator to perform remote control tasks.
8
Master Systems are located in Regional Control Centres (RCC). At present there are four RCCs in Distribution, namely, the Metro and Southern Regional Control Centres (MSRCC), located in Kuala Lumpur and the Northern and Eastern Regional Control Centres (NERCC) in Seberang Jaya.
SCADA System
321
Data
Communication Communications System system
RTU
RTU
Master System (RCC)
Communication System
RTU
Remote Terminal Units
Figure 8-1: Overview of SCADA system
Figure 8-2: Metro Regional Control Centre
8
322
Substation Design Manual
8.2.
Master System
The Master System is essentially a network of computer subsystems with various functions to support the operation of the SCADA based control centre, as shown in the Figure 8-3. The Master System consists of basic SCADA functionalities such as data acquisition from Remote Terminal Units (RTUs), processing of acquired data, supervisory control, user interface functionality or Human Machine Interface (HMI), historical data processing, trending, communication with the communication gateway, etc.
Front end Data Servers/Back end
Human Machine Interface Printer Operator’s workstation
Operator’s workstation
Figure 8-3: The basic layout of the Master System
8
Functionally, the Master System consists of three (3) main subsystems: 1. 2. 3.
Front-end Subsystem Server/Back-end Subsystem Human Machine Interface (HMI) Subsystem
SCADA System
8.2.1.
323
Front-end Subsystem
The functions of the front end subsystem are as follows:
Manages communication with the Remote Terminal Units Responsible for the transmission and reception of raw data to/from the Remote Terminal Units Receives data from Remote Terminal Units, pre-process them and send to Server/Back-end Subsystem Receives control requests from Server/Back-end Subsystem and sends to Remote Terminal Units
8.2.2.
Server/Back-end Subsystem
The Server/Back-end Subsystem contains main SCADA applications and databases which holds information of all points. It processes control commands received from the Human Machine Interface (HMI), packages it and sends to Front-end. It also processes data received from the Front-end and sends to HMI.
8.2.3.
Human Machine Interface Subsystem
The Human Machine Interface (HMI) allows the controller to interface with SCADA System. It processes controller commands and send to Server/Backend Subsystem. It also receives information from Server/Back-end Subsystem and presents it to the controller either visually on monitors or printers. It also receives alarms and alerts the controller visually and audibly.
Figure 8-4: Human Machine Interface
8
324
Substation Design Manual
Additionally, two Distribution Management Systems (DMS) are also implemented into the Master Systems:
The first DMS function covers activities and tasks such as Distribution Operation Analysis, Safety Documents, Operational Document Management and Operational Planning. The second DMS function is the Forced Outage Management Functions, which include Fault Location, Isolation, and Service Restoration function, estimation of customer interruption, and Network Normalization Management.
8.3.
Communication System
The SCADA communication system facilitates transfer of data between Master System (RCC) and Remote Terminal Units (RTU). The communication mediums are as below: i. ii. iii. iv. v. vi.
Fibre optic Pilot cable Leased lines GPRS Radio Microwave
The network topology consists of:
8
i. Point-to-point ii. Multi-drop iii. Loop configuration While the communication schemes are: i. Polling ii. Unsolicited reporting The telecontrol protocols currently implemented are: i. ii. iii. iv.
IEC 60870-5-101 DNP 3.0 Extended WISP+ Harris H6000
SCADA System
325
The Extended WISP+ and Harris H6000 are required for legacy systems to support existing RTUs. Whereas the IEC 60870-5-101 protocol is mainly used to communicate with the newer RTUs installed in TNB’s network. The Inter-Control Centre Protocol (ICCP) is also implemented as control centre to control centre communication protocol.
8.4.
Remote Terminal Unit (RTU)
A substation installed with a Remote Terminal Unit (RTU) is considered a remote station. The SCADA equipment in a remote station consists of the RTU and communication equipment. The RTU collects data from the remote station, processes and executes control commands from the Master System. An RTU is a microprocessor-controlled electronic device that interfaces objects in the physical world to a distributed control system or SCADA by transmitting telemetry data to the system, and by using messages from the supervisory system to control connected objects. An RTU monitors the digital and analogue field parameters and transmits data to the Master System. An RTU can be interfaced with the Master System with different communication media and it can support standard protocols. In TNB substations, the RTU can be classified into two types: 1.
Primary RTU for PMU/PPU/SSU 33 kV - RTU cubicle is Floor-Standing type - DC supply is 110 VDC - Generally located in Control Room beside Supervisory Interface Panel (SIP)
2.
Secondary RTU for PE/SSU 11 kV - RTU cubicle is Wall-mounted type - DC supply is 30 VDC - Located in the Switchgear Room beside Wall-mounted SIP
8
326
Substation Design Manual
Master System
Control and Relay Panel
Supervisory Interface Panel
Remote Terminal Unit
SIP
RTU
Figure 8-5: Connection of Control Panels, Relay Panels, SIP and RTU
8.4.1.
8
RTU Requirements
RTU must have a valid Product Certification / “Sijil Guna Pakai” by TNB. RTU and communication module (modem and fibre converter) must derive its power from the substation’s: o 110 VDC supply and expected to operate between the range of 95 VDC to 130 VDC for PMU, PPU and 33 kV SSU. o 30 VDC supply and expected to operate between the ranges of 25 V dc to 40 VDC for 11 kV substations. RTU must be equipped with DC power supply surge protector. RTU must also be equipped with another surge protector to protect line communication module (modem & fibre converter) from electrical surge. RTU shall be able to support all communication protocols listed below: - IEC60870-5-101 (balanced and unbalanced mode) - IEC60870-5-103 - IEC60870-5-104 - DNP3.0
SCADA System
8.4.2.
327
I/O Interface Card
Data and control signals from/to the plant equipment are relayed to/from the Control Centre via the RTU’s input/output interface card module. The RTU input/output interface cards can be configurable and modular to suit different input/output interfaces with various sizes. The RTU input/output interface cards comprise of three (3) main items as described below: 1.
Digital input is typically a voltage-free normally-open contact at the plant side. The opening or closing of the contact will indicate a new status of the plant, e.g. circuit breaker open or close status, link open or close status, protection relay operation alarms and supervisory or local switch status & substation DC system alarms.
2.
Analog input is typically dc current (4-20 mA) that is usable to the RTU. The source is normally transformed value of the CT and/or PT secondary output, converted by transducers. Modern electronic relays may provide the DC current as well e.g. feeder & transformer loadings/amps, PT voltages, tap changer positions and temperature. This analog input may not be available and/or required in some plants.
3.
Digital Output is normally an open contact of interposing relay at the plant side. The momentary closing of the contact, which energizes the closing coil of the interposing relay, simulates the operation of a switch. Energizing the voltage of the coil is normally given by the RTU, from the substation DC voltage supply. Heavy Duty Interposing Relay is normally used to manage high switching current at the plant side.
8
328
Substation Design Manual
Cabinet Lamp
HX RTC Module
RTU Cabinet Indicators Power Distribution and Interport Link Module
RTU Input/Output Module
8
Grounding Bar
Figure 8-6: Example of an RTU in a Primary Substation (RTU type: Viscon Dua)
SCADA System
8.5.
329
SCADA-ready Substations
A substation is said to be equipped with SCADA-ready facilities if the plant equipment has facilities for data acquisition of power system parameters (derived from plant transducers), breaker status (On/Off), protection relays, alarms and control of various power system devices (breaker Trip/Close, motor operated switches Trip/Close and relay reset). Switchgears, Control Panels, Transformers, Earth Fault Indicators (EFIs), Line Fault Indicators (LFIs) and their related components such as indication devices, protection relays and CT/PT outputs are referred to as Plant Equipment. A SCADA system provides monitoring and control facilities for this plant equipment from the Control Centre. A SCADA-ready substation has these facilities wired to an Input/Output Termination Box at the plant side and the connection from the Input/Output Termination Box to the RTU via a Supervisory Interface Panel (SIP) or Remote Control Box (RCB) is known as Plant Interfacing Work. Generally, in the TNB Distribution Division SCADA system, 11 kV substations (including P/E, SS and SSU) are referred to as Secondary Stations whereas 33 kV substations (including PMU, PPU & SSU) are referred as Primary Stations. Plant equipment in Primary Stations are equipped with SCADA-ready facilities. However, most of the plant equipment in Secondary Stations are not.
8
330
Substation Design Manual
Chapter 9: 9.1.
Earthing
Overview
Earthing may be described as a system of electrical connections to the general mass of earth. An earthing system consists of two elements, the earth conductors and the earth electrodes.
The earth conductor is a conductor of low impedance which provides an electrical connection between a given point in equipment (an installation or system) and an earth electrode. The earth electrode is a conductor or group of conductors in intimate contact with and providing an electrical connection to earth.
9.1.1.
Design objectives
In general, there are 3 types of earthing systems: 1. 2. 3.
Safety or equipment earthing i.e. to protect human life against excessive hazardous voltages (touch and step voltages). Power system earthing i.e. to earth the neutral of a system and provide zero reference voltage. Lightning protection system for effective operation of lightning protection devices.
The substation earthing system shall meet two main purposes which are:
9
1.
2.
To provide means to carry electric currents into the earth under normal and fault conditions without exceeding operating and equipment limits or adversely affecting continuity of service. To assure that a person in the vicinity of earthed installations is not exposed to the danger of critical electric shock.
Earthing
331
To meet the design objectives and requirements, the design for earthing of all equipment and the provision of earthing systems and connections shall be in accordance with the recommendations in the following standards:
BS 7430 – British Standard Code of Practice for Earthing IEEE Std. 80 – IEEE Guide for Safety in AC Substation Grounding IEEE Std. 81 – IEEE Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System
9.1.2.
Step and Touch Voltage
When fault current or lightning strikes current flows in the earthing system, a voltage drop or potential difference is created between the earth electrode and radiating points from the electrode as shown in Figure 9-1. As can be seen in the example shown in Figure 9-2, the voltage drops V1, V2, and V3 etc (known as surface potential) vary according to earth resistance and the earth current at particular instant of flow.
/ lightning
9 Figure 9-1: Fault current path to earth and its induced potential gradient
332
Substation Design Manual
Surface of earth Top view of energised electrode V1 V4 V3
V2
Figure 9-2: Top view of surface earthing potential differences
Due to the existence of this potential gradient, two critical potential differences can be defined:
9
Touch voltage – The potential difference between the earth surface on which a person may stand and the surface of an earthed facility the person is touching. Step voltage – The difference in surface potential experienced by a person bridging the distance of 1 metre with the feet without contacting any grounded object.
Earthing
333
Figure 9-3: Critical shock situations Earthing systems shall have an overall voltage rise, touch voltage and step voltage that are uniformly distributed and within the allowed tolerances. The detailed step-by-step calculations to determine the allowable step and touch voltages can be found in IEEE Std. 80.
9.1.3.
Tolerable Current in the Human Body
The magnitude and duration of a current conducted through the human body at 50 Hz should be less than the value that can cause ventricular fibrillation of the heart. Ventricular fibrillation is a heart condition that results in immediate arrest of blood circulation. Fibrillation current is assumed to be a function of duration of the current and individual body weight. The safety of a person depends on preventing the shock energy from exceeding the fibrillation threshold before the fault is cleared.
9
334
Substation Design Manual
9.2.
Earth Connections Above-Ground
Above-ground earthing connections involve the earthing conductors and all intermediate connections made from a given point in the equipment to an earth electrode. Besides using suitable conductor types, the connection method is also important to ensure proper earthing requirements are met. The following are the approved types of earthing conductors and connection methods, followed by above-ground earthing layout for different substations.
9.2.1.
Earth Conductors
Earth conductors are used as circuit protective and bonding conductors:
9
1.
Circuit protective conductor: The conductors that connect each circuit to ensure that the earth fault current will return to its source separately. Includes conductors that connect the supply neutral to the earth electrode. E.g. metallic sheath of a cable, tin-plated copper braid, copper strips.
2.
Bonding conductor: These ensure that exposed metallic parts such as metal enclosures of equipment and other items of conductive material are bonded together and remain at approximately the same potential during electrical fault conditions. E.g. copper strip.
The criteria for selecting the material and sizing of earth conductors are: (a) Compatibility with material of earth electrode to minimise galvanic corrosion. (b) Resistant to corrosion. (c) Sufficient cross-sectional area to carry maximum earth fault current for a short time.
Earthing
335
The following equation is used to calculate the minimum cross-sectional area, Ac, of an earth conductor. It is in accordance to IEEE Std.80. Equation (minimum cross-sectional area, Ac) 𝐼 𝐴𝐶 = 𝑇𝐶𝐴𝑃 ∙ 10−4 𝐾 + 𝑇𝑚 ∙ ln 𝑜 𝑡𝑐 ∙ 𝛼𝑟 ∙ ρ𝑟 𝐾𝑜 + 𝑇𝑎 Where, I is the rms current (kA) Ac is the conductor cross section in mm
2 o
Tm is the maximum allowable temperature in C o
Ta is the ambient temperature in C o
Tr is the reference temperature for material constants in C Ko is the 1 𝛼0 or 1 𝛼𝑟 − 𝑇𝑟 in C o
αr is the thermal coefficient of resistivity at reference temperature Tr in 1/ o C ρr is the resistivity of the earth conductor at reference temperature Tr in 𝜇Ω-cm tc is the duration of current in seconds TCAP is the thermal capacity per unit volume from Table 1, pg 42 IEEE 3 o Std.80, in J/(cm · C) Alternatively, equation from BS7430 can also be used to determine the minimum cross-sectional area, S of earth conductor. 𝑆=
𝐼
𝑡 𝑘
Where, I is the average fault current, in Amperes (rms) t is the fault current duration, in seconds
9
336
Substation Design Manual
The rms current density, k, is derived from: 𝑘 = 𝐾 𝑙𝑜𝑔𝑒
𝑇2 + 𝛽 𝑇1 + 𝛽
Where, o
T1 is the initial temperature, in C o T2 is the final temperature, in C And values of K and β for typical conductor materials are shown in Table 9-1. Table 9-1: Values of K and β Metal Copper Aluminium Steel
K 2 A/mm (rms) 226 148 78
β C 254 228 202 o
Based on the criteria and calculations for selecting earth conductors, the types of earth conductors used in TNB are copper strips and tin-plated copper braid.
9
Earthing
9.2.1.1.
337
Copper Strip
For P/E 11 kV, SSU 11 kV and 11 kV switching room in PMU/PPU: 2 o 70 mm Cu equivalent. e.g. 25 mm x 3 mm For P/E 22 kV, SSU 22 kV and 22 kV switching room in PMU/PPU: 2 o 120 mm Cu equivalent For SSU 33 kV , 33 kV switching room in PMU/PPU: 2 o 300 mm Cu equivalent e.g. 50 mm x 6 mm
Figure 9-4: Copper strips connecting the supply neutral to earth (circuit protective conductor)
9
Figure 9-5: Copper strip for earthing of equipment (bonding conductor)
338
Substation Design Manual
9.2.1.2.
Tin-plated Copper Braid
Tin-plated copper braid with minimum cross-sectional area of minimum 2 16 mm Switchgear body Gasket
Screw P/E earth bar connected to cable box Lug socket Heat shrink
Back to PMU (star point)
Braided copper wire
Earth fault flow PILC or XLPE cable
Earth fault occurring downstream
Figure 9-6: Braided copper wire connecting cable sheath to earth
9
Figure 9-7: Copper braid (circuit protective conductor)
Earthing
9.2.2.
Connection Methods
All connections made in an earthing system shall meet the same general requirements for the conductors used in terms of electrical conductivity and current carrying capacity. The connections shall be strong enough to withstand the mechanical forces caused by the electromagnetic forces of the maximum expected fault currents and be able to resist corrosion for the intended life of the installation. Correct connection technique will ensure minimal contact resistance. Connection methods to be used for above-ground applications are: o Brazing o Bolt and nut
9.2.2.1.
339
Brazing
Connection is made by heating a piece of Silver Copper Phosphorus (SilFos) in between two copper plates. This method gives a solid electrical and mechanical connection.
Silver SilFos
9
Copper plate
Figure 9-8: Brazing
340
Substation Design Manual
9.2.2.2.
Bolt and Nut
The copper plate is first drilled to the required size of the bolt, the plate is then pre-tinned in order to provide a better electrical connection and to avoid oxidation of the copper before connection is made. Brass bolts and nuts are used. The bolts and nuts must be tied firmly to give a solid connection In order to avoid loose connection over a period of time, jam nuts are used.
Brass bolt Brass nut Lock nut 50 mm
Pre-tinned copper plate
Figure 9-9: Bolt and nut
Jam nut
9
Figure 9-10: Jam nut
Earthing
9.2.3.
341
Earthing Conductor Layout in Substations
The above ground earthing conductor layouts in substations are designed to achieve the following: 1) All exposed metallic parts such as metal enclosures of equipment and other installations of conductive material in the substations are interconnected 2) Continuity of the earth conductors to the earth electrode so that earth fault current flow to earth is ensured 9.2.3.1.
Earthing at PPU
For complete protection of the equipment and personnel working in a PPU, earthing conductors must be connected to the following: (a) Lightning arrestors (b) Installations: i. Switchgears ii. Transformers iii. Cable sheath of the power cables iv. Neutral Earth Resistor (NER) and Neutral Earth Isolators (NEI) v. NER Junction Box vi. Remote Tap Changer Cubicle (RTCC) vii. Control and Relay Panel (CRP) viii. Supervisory/SCADA Interfacing Panel (SIP) ix. Remote Terminal Unit (RTU) x. LV AC board xi. Battery charger The earthing for lightning arrestors must have dedicated earth electrodes. The lightning earthing electrodes and system earthing electrodes must be bonded together.
9
342
Substation Design Manual 2
All metal parts shall be bonded together using copper strip of 300 mm Cu equivalent and connected at some points to the earth electrodes. All connections of earth conductors shall be brazed. The design of the earth electrodes (i.e. earthing layout below-ground) shall refer to Subchapter 9.3 in accordance to IEEE Std. 80. Common earthing layout of a typical one and a half storey PPU is shown in Figure 9-11 and Figure 9-12 for each floor.
50 x 6 mm copper tape to be concealed on the floor
9
50 x 6 mm copper tape to be buried under ground
50 x 6 mm copper tape to be buried under ground
Figure 9-11: Earth connection of PPU (Ground floor and cable cellar)
Earthing
343
Copper tape rise from floor below
EF-2
EF-3
Copper tape rise from floor below
9
Figure 9-12: Earth connection of PPU (First floor)
344
Substation Design Manual
Table 9-2: Legend for PPU earth connection figures Symbol
Description
1
Copper tape to be buried inside concrete for all doors
2
Earth chamber including earth rod and connector
3
Jointing to the outside
4
Copper tape to be exposed ( 1 ft from finish stone chipping level)
5
Individual chamber not connected to be grid
TC
Test clamp 50 mm x 6 mm copper tape to be concealed on the floor Individual earth chamber
50 mm x 4 mm copper tape 50 mm x 4 mm copper tape
50 mm φPVC CONDUIT/DUCT
4 mm DIA. HEX NUT
4 mm DIA. BOLT SEALED IN WALL O.2 PCD EQUALLY SPACE 5 mm THK. M.S
9
Figure 9-13: Test clamp detail
Earthing
345
Square Tape Clamp
Ground Level
Copper Tape to be encased on the floor level
450
450
Square Tape Clamp
PVC cover copper tape from first floor
Ground Level
Figure 9-14: Square tape clamp
9.2.3.2.
Earthing for Indoor Substations
The earthing layout for indoor P/E is shown in Figure 9-15 and Figure 9-16. Earth conductors shall connect LV neutral bushing, transformer body, RMU body, feeder pillar body and cable sheaths at termination to the earth rods. The connections of the earth conductors use either bolted connection or brazing. All earth rods are connected in parallel with separation of L to 2L, where L is the length of the earth rod. To achieve the required earth resistance value of less than 3 ohms, more earth rods can be added in parallel. The details of earthing layout for indoor P/E are included in the Substation Design Booklet (Buku Panduan Piawai Baru Rekabentuk Pencawang Elektrik (Jenis Bangunan) Bahagian Pembahagian, TNB).
9
346
Substation Design Manual
Feeder pillar
Transformer Switchgear
Doors
Earthing point
Earth Chamber
Figure 9-15: Earth Connection of Standalone Indoor Substation – Double Chamber
Metering room
Transformer
Switchgear
Earthing point
Feeder pillar
9
Entrance
Earth chamber
Figure 9-16: Earth Connection of Attached Indoor Substation – Double Chamber with Metering Room
Earthing
9.2.3.3.
347
Earthing for Outdoor Substation
For outdoor P/E, the earthing layout is shown in Figure 9-17. Earth conductors shall connect LV neutral bushing, transformer body, RMU body, feeder pillar body and cable sheaths at termination to the earth rods. The connections of the earth conductors use either bolted connection or brazing. Earthing point
Transformer
Switchgear
Feeder pillar
Earth chamber
Door
Figure 9-17: Earth Connection of an Outdoor Substation
9
348
Substation Design Manual
9.2.3.4.
Earthing for Compact Substation
For compact substation, the earthing layout is shown in Figure 9-18. Within the enclosure, LV neutral bushing, all metallic bodies of the equipment and cable sheaths at termination are bonded using earth conductors. Typically, the enclosure is connected to the earth rods via two earthing points, one from the LV compartment and the other from the RMU compartment. The connections of the earth conductors use either bolted connection or brazing.
LV Feeder Pillar
Transformer
RMU
Doors
Earth chamber
Figure 9-18: Earth Connection of Compact Substation
9
Earthing
9.2.3.5.
349
Earthing for SSU
The earthing layout for SSU is shown in Figure 9-19. Earth conductors shall connect LV neutral bushing, all metallic bodies of the equipment and cable sheaths at termination to the earth rods. The connections of the earth conductors use either bolted connection or brazing. Earthing point
Earth chamber
Figure 9-19: Earth Connection of SSU
9.2.3.6.
Earthing for Pole Mounted (PAT) Substation
For PAT, the earthing layout is shown in Figure 9-20. The lightning arrestors must have dedicated or separate earth electrode or download and connected to a dedicated earth electrode. Meanwhile, earth conductors shall connect LV neutral bushing, transformer body and cable sheaths at termination to the system earth electrode. The lightning earthing electrode and system earthing electrodes must be bonded together.
9
350
Substation Design Manual
Lightning arrester
LV neutral Copper braid from cable termination
Transformer body
Copper strip Add more earth rods in parallel as and when required to improve earth resistance Earth chamber
9
Earth rod
Figure 9-20: Earth Connection of Pole Mounted Substation (PAT)
Earthing
9.2.3.7.
351
Earthing for Pole Mounted (PAT) Substation with RMU
The earthing layout for PAT with RMU is shown in Figure 9-21 and Figure 9-22. Earth conductors shall connect LV neutral bushing, transformer body, RMU body, feeder pillar body and cable sheaths at termination to the earth electrodes.
LV neutral
Copper braid from cable termination
Transformer body
Copper strip
Earth chamber
Earth rod
Add more earth rods in parallel as and when required to improve earth resistance
Figure 9-21: Earth Connection of Pole Mounted Substation (PAT) with RMU (front view)
9
352
Substation Design Manual
Add more earth rods as and when required to improve earth resistance
Copper braid from cable termination Add more earth rods as and when required to improve earth resistance
Copper strip
RMU
Feeder pillar
Earth Chamber
Figure 9-22: Earth Connection of Pole Mounted Substation (PAT) with RMU (top view)
9
Earthing
9.3.
Earth Connections Below-Ground
9.3.1.
Earth Electrode
353
Earth connection below-ground is a system of connected conductors buried in the earth used for collecting ground current from or dissipating ground current into the earth. Criteria of earth electrodes:
Sufficient cross-sectional area to carry the maximum expected fault current for a short time. Good electrical conductivity. Corrosion-resistant in soil: – examples of materials are copper, galvanised steel and cast iron. Aluminium is not suitable as earth electrode as it is susceptible to accelerated corrosion the oxide layer formed is non-conductive.
Typically components for the earth electrode are: 1. 2. 3.
Earth rods Earth plates Horizontal conductors
Earth rods must have rigid cores for easy driving-in. The earth electrode used in TNB is copper-clad steel. Copper-clad steel is used as it has high tensile strength, copper plating for better conductivity. They are able to reach into deeper, low resistivity soil with limited excavation and backfilling. Additionally, they are easy and cheap to install. Minimum size requirement for the earth rod is:
16 mm diameter x 1.5 m (5 ft) long
Earth rods are protected inside earth chambers as shown in Figure 9-24. The earth chamber is specified as:
30 cm x 30 cm (12” x 12”) in size Made of concrete To allow access to earth rod for inspection and testing
9
354
Substation Design Manual
Driving head
Coupler Earth rod
Coupler
Earth rod
Figure 9-23: Earth rod parts
9
Figure 9-24: Earth rod chamber and cover
Earthing
9.3.2.
355
Connection Methods
For below-ground, connection method used to connect earth electrodes is the brazing technique. Bolted connections are not allowed for below-ground connections. Exothermic or heat-releasing welding techniques can also be used for belowground connections. An example of exothermic welding is the Cadweld® technique. This connection method provides strong connections, is corrosionresistant, and is long-lasting even when exposed to harsh environments.
9 Figure 9-25: Cadweld mould (left) and completed connection (right)
The connection to each earth rod inside the earth chamber is considered as an above-ground connection. Hence, bolted connections are allowed between earth conductor and earth rod inside the earth chamber.
356
Substation Design Manual
9.3.3.
PPU Earthing Design
Design must be based on IEEE Std 80 following the following design process:
acquiring data on the proposed substation and site characteristics developing a preliminary design calculating the various hazardous voltages at many locations within and outside the substation to determine the relative safety of the design modifying the design as necessary recalculating the hazardous voltages to insure the design meets the objectives the process may have to be worked through many times before the objectives are achieved
Case study calculations of the Bukit Gambir Containerised PPU can be found in Appendix B. The executive summary and case study results are as follows. The design of the earthing system for the newly proposed Bukit Gambir CPPU has been carried out. Preliminary calculations have been performed using the IEEE Std.80 routines and the final design has been checked using the specialized earthing software package which is Current Distribution, Electromagnetic Fields, Grounding and Soil Structure Analysis (CDEGS). The main parameters and findings are shown in Table 9-3. Table 9-3: Bukit Gambir CPPU site earthing study findings
9
Earth resistance
2.51 Ω
Net single-phase-to-earth fault current
1600 A
Earth potential rise (EPR)
4.02 kV
Maximum touch potential within allowable limit
yes
Maximum step potential within allowable limit
yes
Earthing
9.3.4.
357
SSU/PE/PAT/CSU Earthing Design
Typically, the basic layout uses 4 earth rods connected in parallel using copper strip installed at the corners of the substation. The separations between these earth rods are in the range of L to 2L, where L is the total length of the earth rod. The earth resistance value of the earthing must be less than 3 ohms.
9.3.5.
Earth Resistance Measurement
Earth resistance, RE , is the resistance of the earth electrode with respect to remote/true earth of zero resistance. RE is measured to verify the adequacy of a new earthing system, detect changes in an existing earthing system, determine hazardous step and touch voltages and determine the Earth Potential Rise (EPR).
Legend: 1 – Electrode resistance 2 – Contact resistance 3 – Earth resistance I – Current
I
I
Figure 9-26: Earth resistance
Measurement method used in TNB to determine RE is called the fall-ofpotential (FOP) technique.
9
358
Substation Design Manual
I V
Current electrode
P
E
C
Potential electrode
x Electrode being tested
Current electrode
d
Figure 9-27: Fall-of-Potential (FOP) technique The FOP involves measurement of voltage and current by using potential and current probes driven into the earth. RE is calculated from the measured voltage and current (R = V/I) as a function of distance between the potential probe and the earth electrode under test, x. This is achieved by moving the potential probe at a certain distance from current probe which remains fixed. A typical FOP test result is as shown in Figure 9-28. Auxiliary potential electrode
Earth electrode under test
Effective resistance areas do not overlap
9 Resistance
62% of D
38% of D
Resistance of auxiliary current electrode Resistance of earth electrode
Distance from Y to earth electrode
Figure 9-28: FOP test result
Auxiliary current electrode
Earthing
359
According to IEEE Std. 81, the apparent RE value is the resistance at the 61.8% of the distance between the earth electrode under test and the current probe, D. This 61.8% rule is credible provided the following are met:
Adequate probe distances Homogeneous soil resistivity Identical electrodes
According to IEEE Std. 81, the spacing between the current electrode and the electrode/earth system being tested, D, shall be minimum 6 to 10 times the diagonal size of the earthing system of the substation, d (Figure 9-29).
Diagonal distance Substation earthing system
Figure 9-29: Diagonal size of the earthing system of the substation
This may require the use of extended leads for the current and potential probes as the standard lead’s length provided with earth resistance test equipment is typically 100 m only. The spacing is required to obtain more accurate RE as adequate separation will ensure the return current and voltage measuring points are effectively outside the influence of the earth system to be tested. If separation is not adequate and effective resistance areas overlap, the test result in Figure 9-30 is obtained leading to inaccurate RE. Another source of measurement error in FOP is when the return current and voltage measuring points are within metallic objects inherent of the site such as buried pipes. In this case, the test equipment will read RE value that is not the true apparent value. Therefore, the measurement area must keep away from metallic objects and must minimize their interferences.
9
360
Substation Design Manual
Ground electrode under test
Auxiliary potential electrode
Auxiliary current electrode
Resistance
Overlapping effective resistance areas
Distance from Y to ground
Figure 9-30: FOP test result
9.3.6.
9
Improving Earth Resistance
Earth resistance of earth electrode must be lower than allowable design value to achieve effective earthing Factors affecting RE: – Soil resistivity – Size and type of arrangement of individual earth rods
9.3.6.1.
Soil Resistivity
Soil resistivity varies from one soil spot to another depending on: – Moisture content – Chemical composition – Concentration of salt dissolved in contained water – Grain size and distribution – Closeness of packing of soil grain
Low soil resistivity is desirable to achieve low RE
Earthing
Soil treatment to lower resistivity includes: – Salt treatment (possible leaching, must be renewed periodically) – Bentonite (2.5 Ω·m at 300% moisture, not suitable for very dry environment) – Chemical-type electrodes (copper tube with salt) – Ground enhancement materials placed around rod in-hole or around grounding conductors in trench (e.g. SanEarth, GEM)
A site with low soil resistivity should be chosen when possible
361
9
Figure 9-31: Soil treatment around earth rod to lower soil resistivity
362
Substation Design Manual
9.3.6.2.
Size & Type of Arrangement of Individual Earth Rods
RE can be reduced by: – Increasing the length of buried rod (using coupler to connect additional rod). However this is only effective for soil profile with low resistivity at the bottom layer. – Increasing number of rods connected in parallel. Separation of rods shall be from L to 2L (L is length of rod).
Percent resistance of one electrode
80 Two rod electrodes 3 m long x 15.9 mm diameter 70
60
50
40 0
5
10
30 Electrode spacing, m 0 15
20
25
Figure 9-32: Effect of inter-electrode spacing on combined resistance
9
Fire Fighting System
363
Chapter 10: Fire Fighting System 10.1.
Overview
In case of fire occurring in a substation, a properly designed fire fighting system is important to mitigate and contain the fire. This chapter aims to introduce the basic concepts and requirements for TNB Distribution Substations. Table 10-1 shows requirements for substation fire protection. Table 10-1: Fire Protection Requirements Fire Protection Requirements 1. Collateral Damage IS NOT ALLOWED 2. NO Clean Up Required Electrical Equipment Extinguishing Agent Shall Be Electrically NON-CONDUCTIVE Safety To Human Safety To Personnel: 1. NO Oxygen Deficiency 2. NO Fatality (Lethal) Extinguishing Agent 1. Immediately Vaporize Upon Discharge 2. Leaves NO RESIDUES 3. Do Not Cause Significant Condensation Fire Performance 1. Extinguish All Type Classes of Fires (Class A, B and C) with NO RE-IGNITION 2. Very Fast To Extinguish Fires (Fast Fire Knock Down) Operational Issues Capable to Be Refilled On Side to: 1. Minimize Down Time (Post Accidental Agent Discharged or Post Fire Agent Discharged) 2. Maintain the level of availability of protection at highest level possible. Environmental Minimal Impacts On Environment, ODP = 0, GWP Impacts and ALT are acceptable defined by AHJ (Authority Having Jurisdiction), DOE (Department Of Environment) or EPA (Environmental Protection Agency) - USA Parameters Running 24 x 7
10
364
Substation Design Manual
10.2.
Fire System Requirements for TNB Substations
10.2.1. System Performance Requirements A system installed within TNB substations must meet specific performance requirements. TNB fire suppression system performance requirements include, but are not limited to: (a) Performance Based Design must be used based on the design fire scenario for substation fires applied for each particular enclosure, i.e., control room, switchgear room and indoors transformer room. (b) For halogenated agent, the maximum HF by products shall be LESS than 500 ppm. Engineering correlation may be used to estimate the maximum allowable fire size. (c) Discharge time shall be as short as possible to extinguish fire efficiently and to limit further fire damage on protected equipment. (d) The under/over pressurization in the enclosure due to agent discharge shall be as low as possible to maintain the integrity of the enclosure boundaries (minor building modification is permitted). (e) Pressure relieving vents, located near the finished ceiling, may be necessary to regulate rapid pressure changes during discharge. Comply with the manufacturer’s recommended procedures relative to enclosure venting. (f) System Design Approval - Prior to installation of a fire extinguishing system, the system must be certified or approved as compliant to all TNB’s PSI requirements (ENGR-750-54, ENGR-5202-PSI and ENGR-5203PSI)
10
Table 10-2 and Table 10-3 highlight the extinguishing system performance parameters and minimum standard requirements for detection system.
Fire Fighting System
Table 10-2: Extinguishing Agent System Performance Parameter Minimum Standard Requirement Extinguishing Extinguish all fires without re-flash (re-ignition) Agent 8 AWG, XLPE Cable Fires – 350 Amp Current Flammable Liquid Spilled Fire (Pool Fire) Fast to Ultra Fast Fire Growth Agent Less than NOAEL concentration level or Not to exceed Concentration Maximum PBPK Concentration for 5 minutes exposure time. Enclosure Over Less than Lung Damage: 80 kPa (11.6 psi) Pressure Acid Gases (HF + Potential impact for Equipment: Less than 500 CF2O) by-products ppm peak. Potential impact for Human: Less than 200 ppm for 5 minute exposure to human. Oxygen Level Not below 16% for 5 seconds average Skin Burns Less than second-degree skin burns: o 2 < 1316 C-s over 10 seconds or heat flux < 160 kJ/m o 2 (<2400 F-s over 10 seconds or heat flux < 3.9 cal/cm ) 2 Discharge Forces Not to exceed 78 m/s (8g) over 30 ms Discharge Noise Not to exceed hearing protection level With hearing protection: 162 dB Without hearing protection: 140 dB Agent Accidental Not cause collateral damage (Leaves No Residues). Discharge (No Fire The protected equipments are in good running Discharged) condition 24 x 7, without any personnel intervention. Agent Fire Not cause collateral damage (Leaves No Residues). Discharged (Post The un-damage equipments are still in good Fire Capability) condition and may run (work) 24 x 7. Minimal down time to replace the damage equipment due to fire. Enclosure Venting Minimal Venting Based On: and Integrity 500 Pa Structural Strength 80% Minimum Protected Height During 10 Minutes Holding Time.
365
10
366
Substation Design Manual
Table 10-3: Detection System Performance Parameter Minimum Standard Requirement Smouldering Fires Cross Zoning Detection Systems o Photoelectric Smoke Detector with 10 C Rate o of Rise of Temperature and greater than 40 C o Ionization Smoke Detector with 10 C Rate of o Rise of Temperature and greater than 40 C Flaming Fires Cross Zoning Detection Systems o Photoelectric Smoke Detector with 10 C Rate o of Rise of Temperature and greater than 40 C o Ionization Smoke Detector with 10 C Rate of o Rise of Temperature and greater than 40 C Sensitivity Adjustable with minimum 0.5%/ft Detection Activation Capability to be activated at range of fire size from 100 kW to 200 kW, with onset cable damage at 400 kW fire size. Maintenance Easy to maintain: Intelligent, self diagnostic Built-in Drift Compensation Field Replaceable Optical Chamber Visual indication when time to clean False Alarm Immunity
10.2.2. System Design Approval The certification/approval plan defines the approval requirements for a system and should provide sufficient overall system detail and description so that all certification requirements can be adequately assessed and agreed to. The certification plan includes, but is not limited to, a functional hazard assessment (FHA), a detailed system description and operation, identification and means of compliance to each applicable regulatory requirement, minimum dispatch configuration, certification documentation, and a schedule.
10
ENGR-5202-PSI ENGR-5203-PSI
ENGR-5206-PSI
ENGR-5207-PSI
INSTALLATION
Fire Fighting System
367
A summary of contents from the PSI requirements that are required for system design approval are as follows. 10.2.2.1.1. 1. 2. 3. 4. 5. 6.
Design Brief Site Survey Report Performance Based Design Analysis Hydraulic Flow Calculation Battery Load Calculation Design Drawing (Shop Drawing)
7.
2. 3.
Fire Alarm And Detection Systems Layout Schematic Diagram - Fire Extinguishing System Schematic Diagram – Releasing Agent Control Panel Fire Suppression Piping Layout Fire Suppression Isometric Diagram
ENGR-5203-PSI – Materials Specifications
Technical Specification of the materials (components) used in the proposed design conforming to the SGP material list.
10.2.2.1.3. 1.
Plan Layout Drawing
Cylinder Arrangement and Demarcation Lines Manufacturer Type Endorsement Certificate for Design Analysis
10.2.2.1.2. 1.
ENGR-5202-PSI - Proposed Fire Extinguishing System Design
ENGR-5210-PSI – Delivery Quality Assurance and Installation Quality Control
Product Delivery Quality Assurance Certificate issued by third party appointed by TNB Installation Quality Control Certificate issued by third party appointed by TNB Testing Commissioning and Acceptance
10
368
Substation Design Manual
10.2.3. Component Design Requirements All component used shall be approved (listed) under the following internationally accredited bodies: 1. 2. 3. 4. 5. 6. 7. 8.
Underwriter Laboratories (UL) Factory Mutual (FM) Loss Prevention Certification Boards (LPCB) Vertrauen durch Sicherheit (VdS), German fire protection institute ASME B16.3 (2006) Malleable Iron Threaded Fittings, Classes 150 and 300 ASME B16.39 (2009) Standard for Malleable Iron, Threaded Pipe Unions; Classes 150, 250, and 300 ASTM A106/A106M (2010) Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service ASTM A53/A53M (2010) Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless
Defence-In-Depth (DID) philosophy and concept shall be applied: (a) Minimizing the probability of control panel damage and accidental discharge due to lightning strike.
220 – 240 VAC
Solenoid Actuator
POWER LINE LIGHTNING ARRESTOR
SIGNAL LINE LIGHTNING ARRESTOR
RELEASING AGENT CONTROL PANEL
BACKUP BATTERIES
The use of Power Line and Signal Line Lightning Surge Arrestor have the following benefits:
10
1. 2. 3.
Damaging the control panel system components Maintain the expected backup batteries life and avoiding the premature damage. Minimizing the accidental (voluntary) discharge due to lightning strike
Fire Fighting System
369
(b) In the case of control panel power loss during fire event, the extinguishing agent shall be capable to be discharged manually (redundancy system). MECHANICAL MANUAL DISCHARGE ACTUATOR
AUTOMATIC INITIATING DEVICES
ELECTRIC SOLENOID DISCHARGE ACTUATOR
MANUAL INITIATING DEVICES
CYLINDER VALVE
RELEASING AGENT CONTROL PANEL
AC POWER
BACKUP BATTERIES
The discharge system actuation of extinguishing agent shall have two actuation systems, i.e., electrically and manually. Electrical actuation can be triggered automatically by system detectors or manually by manual release station through control panel. The manual mechanical actuation will be the last survival of the system to enable to discharge the extinguishing agent in the case of electrical power loss during fire event. Any proposed system which has no manual mechanical actuation on the system cylinder will not be considered.
10
370
Substation Design Manual
10.2.4. Testing Requirements (a) Blow Off Testing - To ensure that there will be no residual solid particles inside the discharge piping distribution, which may cause damage to the protected equipment. (b) Extinguishing Agent Integrity Testing - To ensure that all extinguishing agent dispersed and mixed within the enclosure through discharge nozzle, in order to efficiently extinguish the fire. (c) System Component Functionally Testing – To ensure the component functionality as per specification. (d) Functional System Integrity Testing – To ensure the operation sequence of the systems as designed. (e) Room Integrity Testing - To Meet 10 Minutes Minimum Holding Time to ensure No Re-Ignition.
10.2.5. Guarantee Requirements The guarantee is for a period of 5 years with an option for another 5 years subject to the following conditions: (a) Installations and revisions are done by panel contractor (installer) possessing the DITCM (Design-Installation-Testing-CommissioningMaintenance) Approval from manufacturer having SGP from TNB. (b) Installations shall be done according to the Installation and Manual Operation from Manufacturer. (c) The guaranteed of the goods shall be for an initial period of 1 year, subject to an annual revision done by the panel contractor and annually renewed once every revision is done, with maximum guarantee of 5 years.
10
Fire Fighting System
371
Within the guarantee period in force, the manufacturer shall warrant the following conditions: (a) The extinguishing agent discharge shall be clean, non corrosive and will not damage to the machinery and equipment, non toxic and will not harm to human. Under technical advice from manufacturer, panel contractor (installer) shall be responsible for cleaning, repair work or replace or pay the damages claimed by TNB on TNB’s assets which are directly damaged by the voluntary discharge of extinguishing agent. (b) The system components supplied shall be genuine, new and complete system and function within the warranty period. Panel contractor (installer) shall be responsible for the damages or pay damages claimed by TNB on TNB’s assets which are directly damaged from the failure of the system to function during fire. (c) Within the warranty period, the systems shall not have false discharge due to the system manufacturing and/or design defect. Panel contractor (installer) shall be responsible for rectification work on the system supplied and gas refill due to the false discharge.
10.2.6. Sijil Guna Pakai (SGP) All fire fighting systems must utilize products that have obtained the certificate of Sijil Guna Pakai (SGP) from approved panel companies (syarikat panel). Products with the SGP are to be installed, commissioned and maintained by the supplying panel companies for five years after commissioning. A list of presently approved products with SGP can be found in the Circular Surat Pekeliling Pengurus Besar Kanan (Pengurusan Aset) Bil. A14/2012 Menggunapakai Khidmat Syarikat Panel dan Produk Sistem Pemadam Kebakaran untuk Bahagian Pembahagian.
10
372
Substation Design Manual
10.3.
System Components
The fire extinguishing system must be designed, tested and installed to be compatible with the existing building and substation. Typical fixed fire extinguishing system consists of: 1. 2.
Fire Suppression System Components Fire Alarm and Detection System Components
10.3.1. Fire Suppression System Components The set of components for the fire suppression system include the Extinguishing Agent, Master/Pilot Cylinder, Storage Cylinders, Piping Network including Manifold, Valve Opening Actuation Hoses, Manual Pneumatic Discharge Lever, Pneumatic Cones, Pressure Gauge, Safety Burst Disk, Discharge Hoses, Check Valve (Retention Valve), Pressure Switch, Solenoid Actuator and Discharge Nozzle(s).
10 Figure 10-1: Typical system components and arrangement
Fire Fighting System
7
TO PIPE DISTRIBUTION AND NOZZLE(S)
6
5
3 4
2
1. 2. 3. 4. 5. 6. 7.
373
2
2
1
Master cylinder Slave cylinder Solenoid actuator Opening valve connection hose Discharge hoses Manifold Restrictor (pressure reducer only for systems using inert gasses)
Figure 10-2: Arrangement of storage cylinder components
10
374
Substation Design Manual
10.3.2. Fire Alarm and Detection System Component The main detection system component is the Releasing Agent Control Panel. It receives signals from fire detectors and engages the fire suppression system. Other components of the fire detection system are Secondary Power Backup Batteries, Automatic Initiating Devices (Fires Detectors), Manual Initiating Devices (Manual Release and Abort Stations), Alarm Bell, Sounder (Horn/Siren) and Strobe (Beacon), Evacuate Sign, Agent Discharge Sign, LED Beacon. PENGESAN KEBAKARAN AUTOMATIC INITIATING DEVICE (ZONE-01)
RELEASING AGENT CONTROL PANEL
ALARM BELL
HORN STROBE
EVACUATION SIGNAL
AUTOMATIC INITIATING DEVICE (ZONE-02)
PANEL KAWALAN
AC POWER
12VDC BACKUP BATTERY
MANUAL INITIATING DEVICES
EVACUATE
SOLENOID ACTUATOR
BEKALAN ELEKTRIK
Figure 10-3: Releasing agent control panel connections
10
ALARM SYSTEM DEVICES
DETECTION SYSTEM DEVICES
LED BEACON
New Technology
375
Chapter 11: New Technology 11.1.
Mobile Equipment
11.1.1. Mobile Power Transformer 15 MVA 33/11 kV 11.1.1.1. Overview Transformer is the heart of any substation. It provides the power source to serve vast areas and consumer population including domestic, commercial, industrial, hospitals, governmental administrative centres and other critical areas. During its service life, the transformer needs to be maintained as to prolong its life and to prevent catastrophic failures. Often the case, shutting down a 33/11 kV transformer for maintenance or repair is almost impossible especially for areas where supply availability is most critical, for example administrative, commercial or industrial areas with high loading and limited or no injection points, islanded system or single transformer substations with no n-1 capability. Unexpected failures of the transformer as the result of internal failure, natural disaster, sabotage or act of terrorism are also possible resulting in system outage in the surrounding territory. If such failure occurs in the critical areas described above, then complete restoration of supply to such areas may take days, resulting in loss of income and serious damage to TNB reputation. For the reasons mentioned above, many utilities in the world have utilized mobile transformer simply for its main advantage of fast and rapid deployment capability. In short, mobile transformer can be used to ensure supply availability and reliability for the following purposes and conditions:
Planned maintenance Forced outage for transformer repair Supply restoration due to transformer failure Temporary supply before completion of PPU
11
376
Substation Design Manual
11.1.1.2. Design 11.1.1.2.1.
General Concept
The design of the mobile power transformer is based on the following concepts:
Mechanically Robust – To cater for mechanical vibration as the result of frequent movement along various kinds of terrain profiles and road conditions. Higher Thermal Withstand Capability – To suit for the thermal effect due to various load condition at different sites. Installation Flexibility – To be able to connect, terminate or dismantle from system easily and fast. Use of more superior or advance technology for ease of cable laying and connections such as plug-in bushings is being considered. Prolonged Life – To have better or improved design characteristics so that the transformer can be utilized when needed without failing. Environmentally Green – To minimize risk due to pollution of soils and environment with the consideration of the use of green technology i.e. synthetic bio-degradable oil for insulation and cooling. Ease of Installation & Operation – To possess ability for plug-and-play for ease of installation, operation and dismantling. Safety of Operators – To prevent any potential hazards to the operators by taking into consideration security and practicality of the design.
11.1.1.2.2.
Basic Configuration
The mobile power transformer consists of the following main components mounted on a trailer:
11
15 MVA 33/11 kV Power Transformer 11/0.415 kV 100 kVA Auxiliary Transformer Neutral Earthing Resistor (NER), Remote Tap Changer Control (RTCC) Panel
In addition, the mobile power transformer will be fully equipped with a Prime Mover suitable for the application.
New Technology
11.1.1.2.3.
377
Basic Parameters
The basic specification of the power transformer is as shown in Table 11-1. Table 11-1: Basic technical specification of the Power Transformer Category Technical Parameter No. of phases & rated frequency
3-phase, 50 Hz
Short Circuit Impedance
10% at reference temperature of 75°C
Vector Group
Dyn11
No-Load Losses at Nominal Voltage
8.5 kW ± 10%
Load Loss at Nominal Voltage Tap
75 kW ± 10%
Maximum Noise Pressure Level
55 dBA
Core Maximum Flux Density
1.6 Tesla
Winding Maximum Current Density
2.5 A/mm
Temperature Rise
50°C (Top Oil), 55°C (Winding)
Tapping Range
+10% to -15% at 1.67% per step on HV winding
Type of Oil Insulation
Synthetic Ester Bio-degradable Oil
Type of Cooling
ONAN/ONAF
Type of Bushing HV & LV
Plug-in Type
Maximum Dimensions (incl. Trailer & Prime Mover)
17 x 4 x 5 meters (L x W x H)
2
Similar to the power transformer, the auxiliary transformer will also be using synthetic ester bio-degradable oil. All other technical parameters are similar to the specification of a normal distribution transformer. The NER ratings will follow the basic parameters as listed in Table 6-22 Chapter (NER).
11
378
Substation Design Manual
RTCC
Figure 11-1: Illustration of the proposed mobile power transformer arrangement showing the main components
11.1.2. Mobile Step-Up Transformer 625 kVA 0.415/11 kV 11.1.2.1. Overview When power interruption occurs due to power system breakdown or failure of power equipment, system operators are obliged to restore supply as soon as possible to ensure SAIDI is below targeted level. In the process, some operators tend to feed supply into 11 kV network using the existing step down transformer in order to reduce the number of mobile generators used until supply is normalized and fully restored. In the case where breakdown occurred in the rural area, a 500 kW mobile generator may be sufficient to step up supply to feed a number of substations.
11
However, the above practice to step up supply using a normally step down transformer is strictly prohibited by TNB with the issue of the Vice President Directive No. A14-2008. This is because under normal load flow and normal voltage regulation condition, use of step down transformer as step up will work and supply can be fed without any problem. However, problem usually occurs during line-to-earth fault condition in the 11 kV (delta) side. This is because step down transformer with Dyn11 vector group has no star point on
New Technology
379
the 11 kV side and therefore the system protection could not detect the earth fault current to trip the protection device. Under this condition, the faulty phase will normally approach zero volts but the voltage of the un-faulty phases will rise by hazards.
3 times their phase voltage and give rise to safety
11.1.2.2. Use of a Permanently Installed Step-Up Transformer To solve the issue on using step down transformer for stepping up supply, the Senior General Manager (Engineering) has issued a circular No. A17-2009 to give guidelines on the use of permanently installed step-up transformer. The technical requirement set-up in the circular that need to be complied is as follow: i.
ii. iii. iv. v. vi. vii.
viii.
The vector groups for the step-up transformer shall either be YNd11 or YNd1 or YNyn0. For standardization purposes, the use of YNyn0 vector group is not recommended for new project. Voltage ratio shall be 0.415/11 kV. Installation of the step-up transformer shall be at substation on a spur feeder. The selected substation shall be installed with added RMU T-off Transformer Circuit or a VCB. The RMU T-off Transformer Circuit shall be fitted with appropriate fuses whilst the VCB shall be fitted with appropriate relays. LV distribution board or feeder pillar may be installed when necessary. The capacity of the step-up transformer shall be equal or more than the capacity of the mobile generator. For example 625 kVA transformer for 500 kW generator. The step-up transformer shall be tested and proven healthy for use.
The substation selected for the permanent installation may be at the upper stream, middle or downstream of the spur feeder depending on the rating and size of 11 kV cables, logistic and installation suitability, operation and customer requirement as illustrated in the diagram below:
11
380
Substation Design Manual
Step up transformer 0.415/11 kV YNd1 or YNd11
Step down transformer 11/0.415 kV Dyn11
Distribution Board (DB) or Feeder Pillar
Mobile generator set
To LV customer Distribution Board (DB) or Feeder Pillar To the other substation To the other substation
PE 11/0.415 kV
Figure 11-2: Schematic Diagram of 11 kV network showing substation with permanently installed step-up transformer
11.1.2.3. Use of a Mobile Step-Up Transformer 11.1.2.3.1.
General Concept
Based on the Senior General Manager (Engineering) Circular No. 17-2009 described in Paragraph 3 above, the proposed mobile step-up transformer will consist of a step-up transformer 625 kVA 0.415/11 kV securely mounted on a mobile truck or drawbar trailer. Appendix 1 shows the basic layout drawing for the proposed design. For the proposed mobile step-up transformer unit, RMU T-off Transformer Circuit or VCB shall be permanently installed at the selected substation and will not be part of the mobile step-up transformer unit.
11
New Technology
11.1.2.3.2.
381
Design Concept
The proposed concepts for the design of the mobile step-up transformer are:
Mechanically Robust – To cater for mechanical vibration as the result of frequent movement along various kinds of terrain profiles and road conditions. Higher Thermal Withstand Capability – To suit for the thermal effect due to various load condition at different sites. Installation Flexibility – To be able to connect, terminate or dismantle from system easily and fast. Use of more superior or advance technology for ease of cable laying and connections such as plug-in bushings may be considered. Prolonged Life – To have better or improved design characteristics so that the step-up transformer can be utilized when needed without failing. Environmentally Green – To minimize risk due to pollution of soils and environment with the consideration of the use of green technology such as synthetic bio-degradable oil for insulation and cooling. Ease of Operation – To ease in particular, monitoring of the load so that it shall not exceed the capacity of the step-up transformer or the mobile generator. Safety of Operators – To prevent any potential hazards to the operators by taking into consideration security and practicality of the design.
11.1.2.3.3.
Application
It should be noted that the substation or feeder fed by the mobile generator through the step-up transformer shall be operated in islanded operation and isolated from other system or other source of supply.
11
382
Substation Design Manual
11.1.2.4. Rationale for the Use of Mobile Step-Up Transformer and the Advantages over Permanent Installation The rationales and advantages for the use of mobile step-up transformer are as follow:
The step-up transformer if permanently installed will only be utilized when major power interruption occurs. Hence, the use of mobile step-up transformer is practical for effective asset utilization. The use of the mobile step-up transformer will give more flexibility for selection of the substations (indoor or outdoor). This is because the selected substation for stepping up voltage into the 11 kV network will only require added installation of either a RMU T-off Transformer Circuit or a VCB and will therefore solve the issue of space constrain.
Figure 11-3: Illustration the proposed arrangement of the mobile step-up transformer
11
New Technology
383
11.1.3. Mobile Compact Sub The Mobile Compact Substation is basically a compact substation unit (CSU) that is mounted on a mobile platform. It is designed for the following purposes:
Temporary replacement in the event of substation failure due to transformer or switchgear failure. Used for the immediate need of power supply especially for fast track projects while permanent substations are being constructed. Used to fulfil temporary power supply application which require high 3phase load.
The capacity of the transformer of CSU is 1000 kVA and further details are the same as in Chapter 4.6.
Figure 11-4: Mobile compact substation
11
384
Substation Design Manual
11.2.
Energy Efficient Distribution Transformers
11.2.1. Overview Transformers operate 24 hours a day, seven days a week during which time they undergo constant losses of 1 to 2% of the electricity that passes through them. Energy efficient transformers can help to minimize these losses. In Malaysia, more than 80% of electricity generation is by fossil fuel that contributed to the CO2 emission. In financial year 2010/11, a total of 0.54 metric tons of CO2 emission was estimated per MWh of electricity produced by TNB. Thus, by reducing transformer losses, CO 2 emission can directly be reduced to minimize the global green house effect. In TNB distribution network, distribution transformers are the third largest loss-making component after LV and 11 kV overhead and underground cables. The total losses contributed by distribution transformers throughout the distribution network are as shown in Figure 11-5.
Distribution Transformer 1.21%
33kV OH & UG cables 0.29%
22kV OH & UG cables 0.10%
11kV OH & UG cables 1.61%
Power Transformer 0.41%
LV OH & UG cables 1.67%
6.6kV OH & UG cables 0.06%
Figure 11-5: Technical losses by components in TNB distribution system
11
New Technology
385
In order to reduce transformer losses and to achieve overall reduction in technical losses, TNB had acknowledged the following transformer technologies. However, the adoption of these technologies will commence once they are cost effective where the total ownership costs of these transformers are at least equal to the total ownership cost of the conventional silicon steel core transformers.
11.2.2. Amorphous Wound Core Transformer Silicon steel has been used over the years as transformer core material. Silicon steel like most metals, have a crystalline structure. This means that the atoms in the structure arrange themselves in an ordered manner. On the other hand, the atoms in an amorphous metal are not arranged in any ordered structure; rather they have a tightly-packed, but random arrangement. Amorphous metal are formed by cooling the liquid material quickly enough to prevent crystallization; the atoms do not have time to arrange themselves into an ordered structure. Figure 11-6 shows the structure of crystalline, polycrystalline and amorphous materials.
Figure 11-6: Structures of crystalline, polycrystalline and amorphous materials Amorphous metal contains ferromagnetic elements such as iron, or cobalt alloyed with a glass former such as of boron, silicon, or phosphorus. These materials have high magnetic susceptibility, with low coercivity and high electrical resistance. The high resistance leads to low losses by eddy currents when subjected to alternating magnetic fields, a property particularly useful in
11
386
Substation Design Manual
transformers. Typically, core loss can be 70–80% less than with traditional crystalline materials.
Figure 11-7: Flat wound core and coil assembly of amorphous core transformer
As explained in Chapter 6.1.5.1, most distribution and power transformers core construction are typically of stack core type. However, because of the specific characteristics of amorphous metal i.e. brittleness, sensitivity to pressure, low saturation, wafer thickness at only 0.025 mm, etc., the amorphous core is suitable only for wound core and the transformer core design has to be modified; instead of a three legged core, a three phase amorphous transformer needs four cores to form a five legged core as shown in Figure 11-7.
Figure 11-8: Fully assembled oil immersed amorphous core transformer
11
New Technology
387
11.2.3. Tri-Dimensional Wound Core Transformer The improvement in the transformer design has led to the introduction of the tri-dimensional triangular wound core which has changed the existing configuration of the core and coil assembly of the transformer. The tridimensional wound core comprises of three separate cores which are exactly the same, allowing symmetrical and identical magnetic circuit in each core. Each single core of this tri-dimensional core is wound with several trapezoid shaped grain oriented silicon steel strips continuously in order, avoiding air gap that cause high resistance due to laminating joints. The cross sectional area at any point of the core frame is almost a semicircle and with rounded corners as well as shorter yoke length, high flux density can still be achieved with less utilization of core material.
Figure 11-9: Structure of tri-dimensional wound core
When fully assembled, the joined sections of the laminated cores form three identical columns or limbs which are almost perfectly round in shape with cross sectional filling factor reaching 99%, avoiding magnetic flux distortion at joined sections. All the above factors contribute to the reduction of no-load loss by 15 ~ 20% and noise level improvement by 5 ~ 10 dB for the same silicon steel grade. In addition, for the same cross sectional area of the limb, the average length of the winding can be reduced by 2 ~ 3% as compared to the conventional stack core due to the more circular cross sectional area of the limb as shown in Figure 11-10.
11
388
Substation Design Manual
Figure 11-10: Cross sectional area of a tri-dimensional core limb (left) and conventional stack core limb (right)
Figure 11-11: Complete assembly of oil immersed tri-dimensional wound core transformer showing before tanking (left) and after tanking (right)
11
New Technology
389
11.2.4. Performance Comparison between Amorphous Wound Core and Tri-Dimensional Wound Core Transformers
The Amorphous Wound Core Transformer has higher energy efficiency followed by the 3-D Wound Core Transformer as compared to Conventional Transformer for all loading profiles and sectors as shown in Figure 11-12. The higher energy efficiency of the Amorphous Core Transformer is mainly due to its very low no-load loss even though its load loss is slightly higher than the 3-D Wound Core and the Conventional Transformers as indicated in Table 11-2. The results shows that generally the transformers reach their maximum energy efficiency at 30-50% of their loading capacity. The 3-D Wound Core Transformer has relatively lower material utilization as indicated by its weight for low load loss and noise level performance. The Amorphous Wound Core Transformer demonstrated the highest energy efficiency and reduction for total energy loss and CO 2 emission followed by the 3-D Wound Core Transformer.
Table 11-2: Main Features of 11/0.433 kV Amorphous Core and TriDimensional Core Transformers 300 kVA as compared to Conventional Silicon Steel Core No 1
Transformer TNB Specified Maximum Limit Conventional Silicon Steel Stack Core
No-Load Loss (watts)
Load Loss (watts)
Noise Level (dBA)
Weight (kg)
600
2800
60.0
-
547
2662
58.6
1650
2
Amorphous Wound core
111
2719
44.7
1270
3
Tri-Dimensional Silicon Steel Wound Core
480
2655
42.0
1124
11
390
Substation Design Manual
Figure 11-12: All-day efficiency of Amorphous Core and Tri-Dimensional Core Transformers as compared to Conventional Transformer for all loading profiles and tariff sectors
11.3.
Cast Resin and Synthetic Ester Bio-Degradable Oil Immersed Transformers
11.3.1. Overview
11
TNB has been using oil filled transformers in its system. However there are issues such as fire (flammability) environmental concerns (low biodegradability), leakage and maintenance associated with these transformers. These concerns are magnified for those transformers located in the densely populated areas, public areas, shopping centres, especially when the substations are attached to the building. Hence, the use of cast resin transformers and synthetic ester bio-degradable oil immersed transformers have been approved for use in indoor and outdoor (including pole mounted and mobile) distribution substations respectively for less flammable and more environmental friendly insulation materials.
New Technology
391
11.3.2. Cast Resin Transformer The use of cast resin transformer is recommended in location where the fire risk associated with the use of mineral oil is considered to be unacceptable, for example in substation buildings attached to shopping complexes, offices, apartment buildings, hospitals and the like. The metal parts of a cast resin transformer account for around 90% of its total weight. The insulation materials amount to only about 10%. Of this, less than half can be considered flammable because typically about two-thirds of the resin compound is silicon dioxide filler (quartz powder) and much of the insulation material of the LV winding is glass based. Hence not more than 56% of the total weight of the transformer comprises of flammable substances. In addition, the resin used has typical self ignition temperature of 450 ⁰C at which the material will start to ignite. Some main features of cast resin transformer are as follow:
Uses epoxy resin reinforced with glass fibre which prevents cracking of epoxy compound even under overload conditions. Epoxy resin has excellent electrical properties, low shrinkage, good adhesion to many metals and resistance to moisture, thermal and mechanical shock. By molding process.
Figure 11-13: Typical Cast Resin Transformers
11
392
Substation Design Manual
Table 11-3: Main Difference in Construction and Manufacturing Techniques of Cast Resin Transformers Parts
Main Features
Construction/Manufacturing Methods
Type of Conductor
Type of Insulation Layer
HV Winding
Type Embedding Techniques
Type of Conductor
LV Winding
Type of Insulation Layer Type of Embedding Technique
Note:
11
Cu – Copper Al - Aluminium
Cu or Al round or rectangular shape with or without enamel coating Cu or Al foil Glass fleece layer Non-layer glass mat on inner and outer surface Very thin layer or turn insulation Mylar foil Vacuum cast quartz powder filled resin Epoxy glass vacuum Epoxy quartz + Al(OH)3 Vacuum cast glass fibre laminated Epoxy no vacuum (high risk of bubbles formation)
Cu or Al foil
Layer insulation pre-impregnated (pre-preg); polyester foil with glass resin coating
Polymerized by heat treatment
New Technology
393
Table 11-4: Technical Comparison between Cast Resin Transformer and Hermetically Sealed Oil Immersed Transformer Criteria
Cast Resin Transformer
Hermetically Seal Oil Immersed Transformer
Environmental Effect
Not polluting
Yes (mineral oil leakage which is not biodegradable)
Temperature Rise Limit
100 K
60 K
Flash Ignition Temp/ Flash point (Liquid)
Flash Ignition Temp = 310˚C (Temperature at which gases evolve from the material can be ignited by a spark)
Flash point = 150˚C (Lowest temperature at which it can vaporize to form an ignitable mixture in air)
Self Ignition Temp/ Fire Point (Liquid) (Insulating liquid below ≤ 300°C is considered flammable liquid)
Self Ignition Temp 450˚C (Epoxy Resin) = temp at which the material will spontaneously ignite
Fire point = 170˚C The fire point is the temperature at which lubricant combustion will be sustained
Typical Dimension (L x W x H) mm
1590 x 900 x 1750 (without enclosure)
1700 x 950 x 1525
Weight
3100 kg (Cu); 3400 kg (Al)
3190 kg (Cu)
Ventilation
The current TNB substation ventilation is sufficient based on CFD study
Normal ventilation.
Repair
The replacement of a winding can be done on site
The replacement of a winding can only be done in the factory
Maintenance
CBM
CBM
11
394
Substation Design Manual
11.3.3. Synthetic Ester Bio-Degradable Oil Immersed Transformer Synthetic ester oils have been used in distribution transformers since 1970s in the Europe with no reported problems. For power transformer, the synthetic ester oil has been used in 238 kV power transformer located in Sweden. Synthetic ester oil being completely biodegradable makes it more environmentally friendly and thus harmless to marine life. It is typically manufactured from compounds which are largely sourced from vegetables and it has proved to be of very low toxicity. In certain cases it has been shown to be many times less toxic than highly refined petroleum oil. It has a very high flash point of 310°C and an auto-ignition temperature of 435°C, makes it less flammable and suitable for use in fire hazards environment. The dielectric strength of synthetic ester oil is less affected by moisture than mineral oil. Under normal transformer loading, synthetic ester oil can retain higher moister content as compared to mineral oil and therefore allow more migration of moisture from paper insulation into the oil. This “drying” property can contribute to preserve cellulose life. Furthermore, synthetic ester is highly stable towards oxidation and the by-products as the result of aging of synthetic ester oils are less aggressive than mineral oil and hence less harmful to paper insulation. This property of synthetic ester oils makes it suitable for use in a free breathing transformer. However, the synthetic ester oil has slightly higher viscosity as compared to the mineral oil. This is a disadvantage for efficient cooling and during impregnation process. In addition, the dielectric strength of synthetic ester impregnated paper against rms and impulse breakdown voltage is relatively lower compared to the mineral oil. However, these disadvantages can be remedied through improved design clearance and modification on the cooling fins as well as through longer impregnation under vacuum during manufacturing. DGA can be still used as a condition assessment tool for synthetic ester oil, but the diagnosis criteria and interpretation need to be adjusted.
11
New Technology
395
Table 11-5: Technical Comparison between Synthetic Ester with Other Fluids Fluids/ Criteria
Mineral Oil
Silicone Oil
Synthetic Ester
Natural Ester
BDV (kV) Typical Value
55
50
70
70
Viscosity (Typical Value)
9.24
40
28
33
Design, Manufacturing and Operational
-
Needs modification on cooling fins
Needs modification on cooling fins
Prone to Ageing.
Safety & Fire Classification
O
K3
K3
K2
Environmental & Health
Non-Bio Effect to Health
Non-Bio Effect to Health
Biodegradable No Effect To Health
Biodegradable No Effect To Health
11.4.
RMU CB
11.4.1. Overview The ring main unit with circuit breaker (RMU CB) is RMU with circuit breaker function installed at the outgoing feeders. This tripping of the circuit breaker is controlled by self powered relay. As in a conventional RMU, the incoming feeder still uses load break switch (LBS) and the transformer T-off feeder still uses switch-fuse combination with MV DIN fuse. Features:
Incomer – Load Break Switch Transformer – Switch-Fuse Outgoing – Circuit Breaker Protection – Self Powered Relay
11
396
Substation Design Manual
RMU CB
Figure 11-14: Single Line of RMU CB
11
Figure 11-15: Example of RMU CB (Indkom)
New Technology
397
Figure 11-16: Example of RMU CB (Siemens)
Currently, some RMUs used in TNB have circuit breaker function but only for the transformer T-off feeders. Its tripping function is controlled using time lag fuse. This kind of circuit breaker is usually of the rotating arc type which has very limited number of switching operation at rated short circuit breaking current i.e. 20 kA. Additionally, the integral earth switch in series with this circuit breaker has rated short time withstand current of 2.1 kA, 1 second. Therefore, by design this kind circuit breaker cannot be used for outgoing feeders whereby circuit breaker with more superior performance such as vacuum circuit breaker is required.
11
398
Substation Design Manual
Figure 11-17: Example of RMU with CB for transformer feeder (Clockwise from top: Lucy Sabre VRN2a, Merlin Gerin RN2, Tamco GR1)
11
New Technology
399
11.4.2. Self Powered Relay Self powered relay used in the RMU CB is a numerical relay that has three phase non-directional overcurrent and non directional earth fault protection with selectable inverse time (IDMT) or definite time for low-set and high-set stage. It does not require any auxiliary voltage supply and consequently it can also be used for switchgear without external batteries. It takes its power supply energy from the CT circuits and provides the tripping pulse energy to the circuit breaker. The CTs are installed/mounted on bushings in the cable compartment with fixed mounting brackets. The electrical clearance and voltage stress management are ensured to avoid any partial discharge in the CT and bushing vicinity. The relay is buffered by a battery for feeding the liquid crystal display as well as for memorising fault values and reset of the trip relay. Failure of the battery has no effect on the protective functions of the relay. The battery has a typical service life of more than 10 years. The front portion of the relay is protected by a transparent cover and meets IP54 requirement and hence is suitable for outdoor application.
Figure 11-18: Example of self powered relay (Woodward WIP1)
11.4.3. Configuration of RMU CB As with conventional RMUs, RMU CBs are non-extensible and are available in several configurations to suit network requirement. The notation for the configuration of RMU CB in TNB is given by 3 numerals; first numeral refers to the number of incoming with LBS, second numeral refers to the number of switch-fuse/circuit breaker for transformer T-off feeder and third numeral
11
400
Substation Design Manual
refers to the number of outgoing feeders with circuit breaker controlled by self powered relay. Examples of typical configurations used in TNB are as follow:
RMU CB 101: 1 load break switch + 1 circuit breaker outgoing feeder RMU CB 101M: 1 load break switch + 1 circuit breaker outgoing feeder with energy meter (for border metering) RMU CB 111: 1 load break switch + 1 switch-fuse/circuit breaker + 1 circuit breaker outgoing feeder RMU CB 121: 1 load break switch + 2 switch-fuse/circuit breaker + 1 circuit breaker outgoing feeder RMU CB 112: 1 load break switch + 1 switch-fuse/circuit breaker + 2 circuit breaker outgoing feeder RMU CB 102: 1 load break switch + 2 circuit breaker outgoing feeder RMU CB 122: 1 load break switch + 2 switch-fuse/circuit breaker + 2 circuit breaker outgoing feeder
11.4.4. Advantages of Using RMU CB
SSU
Improved fault sectionalising capability Reduce the time to find the failures and expedite the restoration of supply Reduce the number of effected customers in tripping especially on long feeder and worse performance feeder (WPF). This is because faults occurring downstream of RMU CB will be cleared by the RMU CB instead of the by the CB at the PPU or SSU further upstream. Hence, SAIDI will be improved.
PMU
Sebelum
a)
Figure 11-19: Single Line Diagram before using RMU CB
11
New Technology
401
SSU
PMU
Selepas
RMU-CB
Figure 11-20: Single Line Diagram after using RMU CB b) Does not require substation building RMU CB can be installed in outdoor P/E substation such as existing outdoor conventional RMU as it has degree of protection IP54. Does not require external LV supply because it uses self-powered relay and hence battery and battery charger are not required Economical due the cost of RMU CB installation is lower than SSU construction complete with VCB panels, battery and battery charger However, SSU construction is more relevant for certain cases. In cases when SCADA facility is required, external voltage supply is required for battery and battery charger (DC system) needed for the motorisation devices, RTU etc. To ensure protection coordination is achieved, selection of substation/placement of RMU CB has to be planned together with State Protection Unit.
Figure 11-21: RMU CB installed in Outdoor Substation
11
402
Substation Design Manual
11.5.
Containerised PPU
11.5.1. Overview The containerised PPU uses GIS-type for both 33 kV and 11 kV switchgears. The advantages of this containerised PPU include:
Suitable for limited land size Components are readily installed at the factory, therefore shortening the construction period as compared to conventional PPU. The typical duration for commissioning of conventional PPU is 12 months whereas the duration for the containerised PPU is 6 months.
However, there are several disadvantages such as:
11
Space limitation for extension Cabin lifespan is shorter than conventional PPU building Aesthetically inferior than conventional PPU building
Figure 11-22: Containerised PPU
New Technology
403
Each Containerised Primary Distribution Substation (CPPU) 33/11 kV 7 2 x 30 MVA consists of: (a) 1 x Pre-fabricated container unit complete with external walkway/platform housing of about 17 panels of metal-clad 2000 A 25 kA 3 s 11 kV Single Bus-bar GIS with non-withdrawal circuit breaker. (b) 1 x Pre-fabricated container unit complete with external walkway/platform housing of about 7 panels of metal-clad 2000 A 25 kA 3 s 33 kV Single Bus-bar GIS with non-withdrawal circuit breaker. (c) 1 x Pre-fabricated container unit complete with external walkway/platform housing 11 kV and 33 kV Relay, Control Panels, Charger and 110 volt DC Battery Banks. The DC Battery Banks are located in a separate room with proper ventilation to eliminate the risk of vaporised battery chemicals which may cause corrosion to the equipment. (d) 1 x Compact substation rated at 11/0.433 kV 500 kVA. (e) 1 x 11 kV 1600A 50 Hz 4 Ohm Neutral Earthing Resistor (NER) complying with ANSI/IEEE Std 32-1972 (Reaffirmed 1990)
11.5.2. Engineering Specification The following engineering specifications are for a conventional and standard Switchgear & Control Room. However, designs incorporating tried and tested alternative space saving technology with equivalent or superior performance and reliability compared to conventional designs are encouraged and preferred.
The CPPU shall have the following features:
8
7
Design, fabricate, supply, install and commission containerised primary distribution substation (CPPU) at PPU Jalan Bukit Gambir, for TNB Distribution Pulau Pinang (Volume i)-Part 1: Instruction To Tenderers (ITT)
11
404
Substation Design Manual
(a) 33 kV switchgear container All 33 kV metal-clad switchgears shall be of Single Bus-bar (SBB) GIS and non-withdrawal type. These switchgears shall be housed separately from the 11 kV panels. The total number of panels shall be 7:4 feeder panels, 2 transformer incomer panels, and 1 bus-section panel. The feeder earth shall be integrated into the feeder panels. Bus-bar earth (LHS & RHS) shall be integrated into the bus-section panel. (b) 11 kV switchgear container All 11 kV metal-clad switchgears shall be of Single Bus-bar (SBB) GIS and non-withdrawal type. The total number of panels shall be 17:2 transformer incomer panels, 1 bus-section panel and 14 feeder panels. The feeder earth shall be integrated into the feeder panels. Bus-bar earth (LHS & RHS) shall be integrated into the bus-section panel. (c) Insulation compartment It is mandatory that all busbars, circuit breaker and the cable termination be in gas compartments. It is also mandatory that the main bus bar and the circuit breaker compartments be segregated. However, the circuit breaker and cable termination compartment can be constructed as one. It is preferred that the CT and PT are installed in air.
8
11
Design, fabricate, supply, install and commission containerised primary distribution substation (CPPU) at PPU Jalan Bukit Gambir, for TNB Distribution Pulau pinang (Volume i)-Part 2c: Technical Specifications (CPPU)
New Technology
405
(d) Circuit breaker rating is as per the following table. Table 11-6: Circuit breaker rating for containerised PPU Type
33 kV 25 kA 3 s
11 kV 25 kA 3 s
1.
Feeder
1250 A
630 A
2.
Incomer from transformer
1250 A
2000 A
3.
Bus section
2000 A
2000 A
(e) Switchgear main bus-bar rating is as per the following table. Table 11-7: Switchgear main bus-bar rating for containerised PPU Type
33 kV 25 kA 3 s
11 kV 25 kA 3 s
1.
Feeder
2000 A
2000 A
2.
Incomer from transformer
2000 A
2000 A
3.
Bus section
2000 A
2000 A
11
406
Substation Design Manual
Appendix Appendix A: Metering Calculations The resistance of a conductor (with a constant cross-sectional area) can be calculated from the equation: 𝑅 = 𝜌×𝑙 𝐴
(1) o
Where, 𝜌 = resistivity of the conductor material (given typically at +20 C) 𝑙 = length of the conductor 𝐴 = cross-sectional area Table A-1: Resistivity and temperature coefficient for copper (Cu) o
o
Material
Resistivity 𝝆 (+20 C)
Resistivity 𝝆 (+75 C)
Copper
0.0178 μΩ·m
0.0216 μΩ·m
Temp. Coefficient 𝜶 –1
0.0039 K o
Table A-2: Resistance per one meter cable length (+75 C) for copper 2
Material
2.5 mm
Copper
0.00865 Ω/m
4 mm
2
0.00541 Ω/m
6 mm
2
0.00360 Ω/m
Using the MV wiring connection in Figure 7-20, the worst case scenario is with o resistance per cable length at +75 C, maximum secondary current 5 Amps flowing in the circuit, CT burden is given as 15 VA, while main and check meter burdens are 1 VA each. The conductor is laid from CT (S1 pin) to the main meter, then through the check meter, and back to CT (S2 pin). Thus the total conductor length is 2 x L, where L is the distance from the meter to the CT. 2 With this information, the maximum allowable distance, L, for a 2.5 mm copper cable can be calculated as follows: Cable burden = 𝑆 = 𝐼 2 𝑅 Total CT burden − meter burden = 𝐼 2 × 𝜌 × 𝑙 𝐴 15VA − 2 × 1VA = (5 Amps)2 × 0.0216 μΩ ∙ m × 1m/2.5mm2 × 2𝐿 13 = 0.432 × 𝐿 𝐿 = 13/0.432 𝐿 = 30.09 m
Appendix
Appendix B: CPPU Bukit Gambir Earthing Calculations
B.1
Introduction
The Bukit Gambir Containerised Primary Distribution Substation (CPPU) has been proposed to be constructed next to the existing P/E Bukit Gambir 2. A consultant has been engaged to design the earthing system for the substation. This earthing design report is concerned with the following work: 1. 2. 3. 4. 5. 6.
Soil resistivity measurements and the derivation of the electrical soil model. Calculation of the current carrying capability of the proposed earth electrode. Calculations of the tolerable touch and step potentials. The calculations of earth resistance touch and step potentials based on IEEE Std.80-2000 routines. Presentation of the proposed earthing design. Validation of the earthing design using a specialist earthing software package.
Calculations carried out are earth resistance, touch and step profiles for the whole substation and the surface potential profile of the surrounding area of the substation.
407
408
Substation Design Manual
B.2
Site Resistivity
B.2.1
Introduction
The soil resistivity measurements were carried out using the Wenner method. The measurements were taken on the actual substation site on 1 December 2010. Two measurements traverses were conducted, as shown in Figure B-1. The traverses were chosen based on the best available land area in order to maximize the spacing and minimize the likely interference from buried metallic objects. Both traverses R1 and R2 were conducted using Wenner spacing of up to 13.5 metres.
R1 R2
Figure B-1: Measurement traverse at substation site
Appendix
B.2.2
Soil Resistivity Measurement Procedure
Soil resistivity testing is the process of measuring a volume of soil to determine the conductivity of the soil. The resulting soil resistivity is expressed in ohm-metre (Ω·m) or ohm-centimetre (Ω·cm). The Wenner 4-point Method is by far the most used test method to measure the resistivity of soil. Other methods do exist, such as the General and Schlumberger methods, however they are infrequently used for earthing design applications and vary only slightly in how the probes are spaced when compared to the Wenner Method. A four-terminal earth tester is required, equipped with four short test rods and connecting leads. The test leads should be checked for continuity and condition prior to use. Before carrying out any testing, checks should be made from cable records or by using above-ground detection equipment, for the location of any buried cables, earth conductors or metal pipe work. These would adversely affect the accuracy of the readings taken, particularly if they are parallel to the measurement traverse. Clearly this will not be an issue at most rural locations. The traverse locations chosen should be preferably be free of long buried metal pipes etc., but if this is not possible the measurement traverse should be as near perpendicular to them as possible. The route chosen should not be close and parallel to the overhead line support or route. As the line supports are earthed, then their close presence and the counterpoise will adversely affect the readings. If the soil resistivity measurement leads are long and in parallel with an overhead line, then an induced voltage may occur in the leads should fault current flow through the overhead line. To avoid this, measurement routes should preferably be at right angles to overhead lines. If they must be in parallel, then a separation of 20 metres or more from the line is preferable and the route oriented such as to be at as near rectangular to the line as possible. Figure B-2 shows the general measurement arrangement. The four earth rods should be driven into the ground in a straight line, at distance “a” metres apart and driven to a depth of “d” metres.
409
410
Substation Design Manual Array Centre X 3a a2
a 2 a
a
a Soil Surface
d Probe
C1
P1
P2
C2
EARTH TESTER
Figure B-2: The Wenner Soil Resistivity Measurement Array
The four earth rods should be connected to the tester, with the outer rods connected to the C-1 and C-2 terminals, and the inner rods to the P-1 and P-2 terminals. When the instrument is switched on, there will be an apparent resistance reading on the meter, which is “R” ohm. The meter should be left on to allow the build in filters to operate and the value after about 30 seconds should be fairly constant. The apparent soil resistivity (ρ) is then given by 2πaR Ω·m. If the value is varying significantly, this may be due to interference, high contact resistance at the test rods, a damaged test lead or the reading being at the lower limit of the instruments measuring capability. If, after investigating the above, the reading is still changing by more than 5%, record a series of ten consecutive readings over an interval of few minutes, calculate the average and then proceed with the rest of the measurements. At least two series of measurements, via traverses perpendicular to one another should be taken, to allow interference and small local variation effects to be balanced out. If any readings were unstable, then additional traverses will be necessary, possibly further away from the site.
Appendix
If the surface soil is very dry, the high contact resistance with the rod will restrict the flow of test current. To overcome this it is recommended that a short steel rod, having a smaller radius than the test rod, is driven into the soil to a depth of 150 mm and removed. A weak solution of saline water is poured into the hole and the test rod driven in. If this does not provide a satisfactory reading, the rod may be driven in a little deeper. A better arrangement is a cluster of three to five rods positioned 250 mm apart and connected together. Rod clusters like this are normally only required at long test (“a”) spacings and would introduce an error if used at small spacings. It is very unusual to require rod depth of more than 0.3 metres and precautions will be required to ensure that third party equipment or cables are not damaged if rods are driven to more than 0.2 metres depth. Their installed depth should never exceed one twentieth of “a”. Software programs are available for carrying out detailed calculations, based upon data from the above readings, to provide a “best-fit”, representative soil model for the area, consisting of a number of vertical and horizontal layers having different resistivity values.
B.2.3
Results
The result of the measurements taken and their corresponding apparent resistivities are shown in Table B-3. Table B-3: Soil resistivity measurement data Spacing (m) 1
R1 (Ω) 21.1
ρ(Ω) 132.59
R2 (m) 20
ρ(Ω·m) 125.68
1.5
14.43
136.02
13.96
131.59
2
10.96
137.75
10.07
126.56
3
6.52
122.92
7.27
137.05
4.5
4.55
128.66
4.59
129.80
6
3.370
127.06
3.4
128.19
9
2.480
140.26
2.3
130.08
13.5
1.609
136.50
1.593
135.14
411
412
Substation Design Manual
The plot of apparent resistivity of each traverse against inter-electrode spacing is shown in Figure B-3.
Figure B-3: Plot of apparent resistivity against measurements spacing A specialist earthing software packaging is used to derive the electrical soil model for the measurements data acquired. The plot of the measurements data and the derived electrical soil model is shown in Figure B-4 and the derived multilayer electrical soil resistivity model and its uniform equivalent are shown in Table B-4.
Appendix
Legend Measured result curve Compared result curve Soil model curve
1 2 3
RESAP<Bukit Gambir>
Figure B-4: Plot of the soil resistivity measurements data and the derived electrical soil model Table B-4: Derived electrical soil model and its uniform equivalent
B.3
Layer
Resistivity (Ω·m)
Thickness (m)
Top
130.6
13.4
Bottom
146.0
∞
Uniform equivalent
132.8
∞
Conductor Sizing
The earth electrodes will have to be able to conduct a current of 25 kA magnitude for 3 seconds. The following routine, from IEEE Std.80-2000, is used to calculate the minimum electrode size for the given requirement.
413
414
Substation Design Manual
B.3.1
Input Parameters
I = 25
RMS Current (kA)
Tm = 450
Maximum Allowable Temperature (Degree Celsius)
Ta = 40
Ambient Temperature (Degree Celsius)
Ko = 242
Ko Factor (Table 1, pg42 IEEE Std.80)
αr = 0.00381
Thermal Coefficient of Resistivity at Reference Temperature (Table 1, pg42 IEEE Std.80)
ρr = 1.7774
The Resistivity of the Earth Conductor at Reference Temperature (Ω·m) (Table 1, pg42 IEEE Std.80)
tc = 3
Time of Current Flow (s)
TCAP = 3.422 Thermal Capacity Factor (Table 1, pg42 IEEE Std.80) Equation (minimum cross-sectional area, Ac) I 𝐴𝐶 ∶= −4 𝑇𝐶𝐴𝑃 ∙ 10 𝐾 + 𝑇𝑚 ∙ ln 𝑜 𝑡𝑐 ∙ 𝛼𝑟 ∙ ρ𝑟 𝐾𝑜 + 𝑇𝑎 B.3.2
Results
The minimum allowable conductor cross-sectional area is calculated to be 2 203.31 mm . In the present work, the dimension of the earth electrode to be 2 used in 50 mm x 6 mm (cross-sectional area of 300 mm )
B.4
Tolerable Touch and Step Voltages
The tolerable touch and step voltages are calculated using the IEEE Std.802000 routines. B.4.1
Input Parameters
ts = 0.5
Duration of shock in seconds
ρ = 132.8
Soil resistivity in Ω·m
ρs = 3000.0 Surface layer resistivity in Ω·m (Crushed rock) hs = 0.15
Surface layer thickness in m (Crushed rock)
Appendix
B.4.2
Results
Surface layer resistivity derating factor, ρ ρ𝑠 𝐶𝑠 ∶= 1 − 2 ∙ 𝑠 + 0.09 0.09 1 −
(Eq 27 pg 23 IEEE Std.80) 𝐶𝑠 = 0.78 Tolerable touch voltage for human with 50 kg body weight in V (no footwear), 𝐸𝑡𝑜𝑢𝑐 50 ∶= 1000 + 1.5𝐶𝑠 ∙ ρ𝑠
0.116 𝑡𝑠 (Eq 32 pg 27 IEEE Std.80)
𝐸𝑡𝑜𝑢𝑐 50 = 739.45 V Tolerable step voltage for human with 50 kg body weight in V (no footwear), 𝐸𝑠𝑡𝑒𝑝 50 ∶= 1000 + 6𝐶𝑠 ∙ ρ𝑠
0.116 𝑡𝑠 (Eq 29 pg27 IEEE Std.80)
𝐸𝑠𝑡𝑒𝑝 50 = 2466.0 V
B.5
Earthing Design
The proposed substation earthing design is shown in the Conclusions and Recommendations (Section B.10). The earthing system is designed to control the touch and step potentials, and to link the earth electrodes to the aboveground metallic equipment and any lighting protection system employed. The fence of the substation is designed to be separately earthed from the main earthing system of the substation. For a separately earthed fence, any equipment earthed to the main substation earth will need to have a minimum of 2 metre separation distance to the fence (and any metallic object connected to the fence earth). Also, to protect against touch and step potential hazards, the entire substation will need to be covered with an insulation layer; the minimum being crushed rock.
415
416
Substation Design Manual
The main parameters of the design are shown on Table B-5 below. Table B-5: Earthing design parameters
B.6
2
Substation earthing area
448.2 m
Size of earth electrode
50 x 6 mm (300 mm )
Diameter of rod
16 mm
Length of earth electrode
209.3 m
Length of each rod
5.4 m (3 x 1.8 m)
2
Number of rods
17
Total lengths of rods
91.8 m
Total buried lengths of rods and electrodes
301.1 m
Depth of buried electrodes
0.3 m
Thickness of crushed rock layer
0.15 m
Earth Resistance Calculations
The earth resistance of the substation is calculated based on the IEEE Std.802000 routine. B.6.1
Input Parameters
ρ = 132.8
Soil resistivity (average value taken from measurement) in Ω·m
Lc = 301.1
Total length of all connected grid conductors in m
d1 = 0.036
Diameter of grid conductor in m
b = 0.016
Diameter of earthing rod in m
nR = 17
Number of earth rods placed in area A
Lr = 5.4
Average length of a earth rod in m
h = 0.3
Depth of grid burial in m
a' = (𝑑1 ∙ ) sqrt(a·2h) for conductors buried at depth h, where a is the conductor radius A = 448.2
Area covered by grid
k1 = 1.10
Constant related to the geometry of the system
k2 = 4.8
Constant related to the geometry of the system
Appendix
B.6.2
Results
Resistance of grid conductors, 𝑅1 ∶=
ρ 2𝐿𝑐 𝑘1 ∙ 𝐿𝑐 In + − 𝑘2 ′ 𝜋𝐿𝑐 𝑎 𝐴 (Eq 54 pg 66 IEEE Std.80)
𝑅1 = 2.739 Ω Resistance of all earth rods, 𝑅2 ∶=
ρ 2𝜋. 𝑛𝑅 . 𝐿𝑟
In
4𝐿𝑟 𝑏
−1+
2𝑘1 ∙ 𝐿𝑟 𝐴
𝑛𝑅 − 1
2
(Eq 55 pg 66 IEEE Std.80) 𝑅2 = 2.689 Ω Mutual resistance between the group of grid conductors and group of earth rods, 𝑅𝑚 ∶=
ρ 2𝐿𝑐 𝑘1 ∙ 𝐿𝑐 In + − 𝑘2 + 1 𝜋𝐿𝑐 𝐿𝑟 𝐴 (Eq 56 pg 66 IEEE Std.80)
𝑅𝑚 = 2.325 Ω Total grid resistance, 𝑅𝑔 ∶=
2 𝑅1 𝑅2 − 𝑅𝑚 𝑅1 + 𝑅2 − 2𝑅𝑚
(Eq 53 pg 66 IEEE Std.80) 𝑅𝑔 = 2.519 Ω
417
418
Substation Design Manual
B.7
Calculated Touch (Mesh) Voltage for the Earthing Design
The touch (mesh) voltage is calculated based on the IEEE Std.80-2000 method. B.7.1
Input Parameters
H = 0.3
Depth of grid burial in m
D=6
Spacing between parallel conductors in m
d = 0.036
Diameter of grid conductor in m
ρ = 132.8
Soil resistivity encountered by grid conductors buried in depth h in Ω·m
n=3
Number of parallel conductors in one direction
Lc = 209.3
Total length of horizontal electrode in m
LR = 91.8
Total length of rods in m
IG = 1600
Net fault current in A
LM = 301.1
Effective buried length, where LM := Lc + LR
B.7.1
Results
Corrective weighting factor that adjust the effect of inner conductors on the corner mesh: 𝐾′𝑖𝑖 ∶=
1 2∙𝑛
2 𝑛
(Eq 82 pg 93 IEEE Std.80) 𝐾′𝑖𝑖 = 0.303 𝐾𝑖𝑖 = 1 Note: For grids with earth rods along the perimeter, or for grids with earth rods in the grid corners, as well as both along the perimeter and throughout the grid area, Kii = 1
Appendix
Corrective factor for grid geometry: 𝐾𝑖 ∶= 0.644 + 0.148 ∙ 𝑛 (Eq 89 pg 94 IEEE Std.80) 𝐾𝑖 = 1.088 Corrective weighing factor that emphasises the effects of the grid depth: 𝐾 ∶= 1 +
𝑜
𝑜 = 1 m (grid reference depth) (Eq 83 pg 93 IEEE Std.80) 𝐾 = 1.14 Spacing factor for mesh voltage: 𝐾𝑚 ∶=
1 𝐷2 𝐷 + 2 · In + 2𝜋 16 ∙ 𝐷 8𝑑 ∙ 𝐷
2
−
𝐾𝑖𝑖 8 + + In 4𝑑 𝐾 𝜋 2𝑛 − 1 (Eq 81 pg 93 IEEE Std.80)
𝐾𝑚 = 0.54 Mesh voltage at the centre of the corner mesh, V: 𝐸𝑚 ∶=
ρ ∙ 𝐾𝑚 ∙ 𝐾𝑖 ∙ 𝐼𝐺 𝐿𝑀 (Eq 80 pg 91 IEEE Std.80)
𝐸𝑚 = 415.0 V The mesh voltage is calculated to be lower than the allowable touch voltage limit calculated in Section B.4.2, which is 739.45 V.
419
420
Substation Design Manual
B.8
Calculated Step Voltage for the Earthing Design
The step voltage is calculated based on the IEEE Std.80-2000 method. B.8.1
Input Parameters
H = 0.3
Depth of grid buried in m
D=6
Spacing between parallel conductors in m
ρ = 132.8
Soil resistivity encountered by grid conductors buried in depth h in Ω·m
n=3
Number of parallel conductors in one direction
IG = 1600
Net fault current in A
Lc = 209.3
Total length of horizontal electrode in m
LR = 91.8
Total length of rod in m
B.8.2
Results
The effective buried length of conductors: 𝐿𝑠 ∶= 0.75 · 𝐿𝑐 + 0.85 · 𝐿𝑅 (Eq 93 pg 94 IEEE Std.80) Spacing factor for step voltage: 𝐾𝑠 ∶=
1 1 1 1 + + 1 − 0.5𝑛−2 𝜋 2· 𝐷+ 𝐷 (Eq 94 pg 94 IEEE Std.80)
𝐾𝑠 = 0.608 Corrective factor for grid geometry: 𝐾𝑖 ∶= 0.644 + 0.148 · 𝑛 (Eq 89 pg 94 IEEE Std.80) 𝐾𝑖 = 1.088
Appendix
Step voltage between a point above the outer corner of the grid and a point 1 metre diagonally outside the grid: 𝐸𝑠 ∶=
ρ · 𝐾𝑠 · 𝐾𝑖 · 𝐼𝐺 𝐿𝑠 (Eq 92 pg 94 IEEE Std.80)
𝐸𝑠 = 597.67 V The step voltage is calculated to be lower than the allowable limit, 2466 V, as calculated in Section B.4.2.
B.9
Computer Simulations
The designed earthing system is simulated in a specialist earthing software package to calculate and verify the design parameters. The layout of the modelled earth grid is shown in Figure B-5.
Figure B-5: Earth grid layout for CPPU Bukit Gambir
421
422
Substation Design Manual
B.9.1
Earth Resistant Calculation
The earth resistance of the modelled earth grid has been calculated by the software to be 2.5126 Ω. This value is close to that calculated using the IEEE Std.80-2000 routine shown in Section B.5. The main reason for the slight difference in the results is that the software takes into account the multilayered electrical soil model, whilst the calculations in Section B.5 only utilise the uniform equivalent soil model. The calculations by the software also show that the earth resistance is lower than 5 Ω, which complies with TNB’s requirement. B.9.2
Touch Potential Calculation
The touch potentials are calculated for the whole substation, assuming a net single-phase-to-earth fault current of 1600 A. The touch potential plot is shown in Figure B-6. The minimum touch potential threshold is set at 739.45 V, which is the calculated allowable touch potential limit.
Figure B-6: Touch potential plot for CPPU Bukit Gambir Figure B-6 shows that the touch potentials in the areas where the equipment will be placed do not exceed the allowable limit.
Appendix
For the purpose of calculating touch potentials for different EPR magnitudes, the touch potential plot with respect to the percentage of EPR is produced and is shown in Figure B-7.
Figure B-7: Touch potential plot for CPPU Bukit Gambir (% of EPR)
423
424
Substation Design Manual
B.9.3
Step Potential Calculations
The step potentials are calculated for the whole substation. The step potential plot is shown in Figure B-8, which shows the step potential in the substation as percentages to the substation’s EPR.
Figure B-8: Step potential plot for CPPU Bukit Gambir (% of EPR) As shown in Figure B-8, the maximum step potential that can be experienced in and around the substation is 16.61% of the substation’s EPR. Assuming a net single-phase-to-earth fault current of 1600 A and an EPR of 4020.16 V, the maximum step voltage which can be experienced in and around the substation is therefore 667.75 V, which is smaller than the calculated allowable limit of 2466 V (Section B.4.2). The substation is therefore safe against step potential hazards. B.9.4
Surface Potential Calculations
The surface potentials in and around the substation are calculated as a percentage of the EPR. The resulting contour plot is shown in Figure B-9.
Appendix SINGLE-ELECTRODE/SCALAR POTENTIALS [ID: BUKIT GAMBIR 3] LEGEND MAXIMUM VALUE: 98.28767 MINIMUM VALUE: 7.980539
150
100
Y AXIS (METERS)
LEVEL 3 (60,000)
50
0 LEVEL 2 (25,000)
-50
LEVEL 1 (15,000)
-100 -50
0
50
100
X AXIS (METERS) Potential Profile (% reference PR)
Figure B-9: Surface potential profile for CPPU Bukit Gambir (% of EPR) Figure B-9 shows that surface potentials of up to 15% of the EPR can be experienced up to a distance of 50 m from the edge of the substation earth grid, as shown by contour Level 1. For an EPR of 4020.16 V, the surface potential at this distance is 603.0 V.
B.10
Conclusions and Recommendations
B.10.1
Conclusions
The earthing design for CPPU Bukit Gambir has been produced. The earthing resistance of the substation is calculated to be lower than 5 Ω and the simulations have shown that the design is adequate for handling touch and step potentials for a net single-phase-to-earth fault current of 1600 A.
425
426
Substation Design Manual
Conservative assumptions have been used in the design, where the calculations have not considered the parallel paths of the fault current. During a single-phase-to-earth fault a significant portion of the fault current will flow back to the source via the cable sheath, thus reducing the fault current flowing to earth. This will result in the substation attaining a lower EPR, touch and step potentials than that calculated.
B.10.2
Recommendations
1.
Install the earthing system as shown in Figure B-10.
2.
Cover the whole substation area with insulating material, e.g. crushed rock.
3.
The fence has been designed to be separately earthed from the substation. It is therefore very important to maintain a minimum separation distance of 2 m between metallic objects connected to main substation earth and the fence. These may be in the form of metallic lamp posts and control panels.
4.
The substation has a large prospective EPR which exceeds the ITU limit of 430 V. Precautions will need to be taken against services coming in and going out of the substation, e.g. water rains, LV supplies and telecommunication lines.
5.
For an EPR of 4020.16 V, sufficient potentials up to 603 V can be expected up to 50 m from the substation earth grid. The impact of this high magnitude surface potential in the surrounding areas of the substation will need to be assessed by TNB.
6.
TNB to investigate the suitability of bonding the earthing of CPPU Bukit Gambir to the earthing system of the adjoining P/E Bukit Gambir 2. This will result in a reduction of the overall earth resistance and EPR, but other issues like the possibility of transferred potentials via distribution cable sheaths will need to be considered.
Appendix
Notes: 1. 2. 3. 4. 5. 6. 7.
Conductor for earth Grid is 50 mm x 6 mm copper tape, to be buried at 300 mm below surface level. Base of structures and equipment to be connected to earth grid using 50 mm x 6 mm copper tapes. Connection between copper tapes is by brazing. Earth rod diameter is 16 mm, 3 x 1.8 m long. Connection between electrodes and rods to be carried out in earth pits. Substation area to be covered with crushed rock, 150 mm thick. Minimum 2 m separation required between fence and any earthed equipment.
Figure B-10: Earth grid layout for CPPU Bukit Gambir
427
428
Substation Design Manual
Appendix C: IP – Ingress Protection Ratings Ingress Protection (IP) ratings are developed by the European Committee for Electro Technical Standardization (CENELEC) (NEMA IEC 60529 Degrees of Protection Provided by Enclosures – IP Code), specifying the environmental protection the enclosure provides. The IP rating normally has two numbers: 1. 2.
Protection from solid objects or materials Protection from liquids (water) IP
3
5
Code Letters First Characteristic numeral Second Characteristic numeral
Example – IP35 With the IP rating IP35:
3 – describes the level of protection from solid objects; in this rating, enclosure protects from solid objects of 2.5 mm diameter – e.g. a tool such as a screwdriver. 5 – describes the level of protection from liquids; in this rating, enclosure protects against low pressure jets of water from all directions.
An "X" can use for one of the digits if there is only one class of protection, i.e. IPX1 which addresses protection against vertically falling drops of water e.g. condensation.
Appendix First characteristic numeral Protection against solid foreign objects I.P
X
Tests Protection unspecified (untested)
0
Non protection
1
Full penetration of 50 mm diameter of sphere not allowed. Contact with hazardous parts not permitted
Back of hand
2
Full penetration of 12.5 mm diameter of sphere not allowed. The jointed test finger shall have adequate clearance from hazardous parts
Finger
3
The access probe of 2.5 mm diameter shall not penetrate
Tool
4
The access probe of 1 mm diameter shall not penetrate
Wire
5
Example
Degree of protection for people against access to hazardous parts with:
Limited ingress of dust permitted (no harmful deposit)
Non-protected
Dust protected Wire
6
No ingress of dust
Dust tight
429
430
Substation Design Manual
I.P
X
Second characteristic numeral Protection against harmful ingress of water Example Tests Protection unspecified (untested)
Degree of protection from water -
0
Non protection
1
Protected against vertically falling drops of water
Vertically dripping
2
Protected against vertically falling drops of water with enclosure tilted 15˚ from the vertical.
Dripping up to 15˚ form the vertical
3
Protected against sprays to 60˚ from the vertical.
Limited spraying
4
Protected against water splashed from all directions – limited ingress permitted
Splashing from all directions
5
Protected against low pressure jets of water from all directions – limited ingress permitted
Hosing jets from all directions
6
Protected against strong jets of water e.g. for use on ship decks – limited ingress permitted
Strong hosing jets from all directions
7
Protected against the effects of immersion between 150 mm and 1 m
Temporary immersion
8
Protected against continuous submersion at a specified depth.
Continuous immersion
Non-protected
Appendix
List of Abbreviations ABC
Aerial bundled cables
AC
Alternating Current
AHJ
Authority Having Jurisdiction
AIS
Air Insulated Switchgear
Al
Aluminium
ALF
Accuracy Limit Factor
ASME
American Society of Mechanical Engineers
ASTM
American Society for Testing and Materials
ATS
Automatic Transfer Switch
AVR
Automatic Voltage Regulator
AWG
American Wire Gauge
BS
British Standards
CB
Circuit Breaker
CDG
Circular Disk Gear
CPPU
Containerised Primary Distribution Substation
CRP
Control & Relay Panels
CSU
Compact Substation Units
CT
Current Transformer
CTC
Continuous Transposed Cable
Cu
Cuprum
DC
Direct Current
DID
Drainage and Irrigation Department
DIN DITCM
German Institute for Standardization /Deutches Institut fur Normung Design-Installation-Testing-Commissioning-Maintenance
DMS
Distribution Management Systems
DNP
Distributed Network Protocol
DOE
Department Of Environment
DPC
Damp-Proof Course
EDO
Expulsion Drop-Out
EFI
Earth Fault Indicator
431
432
Substation Design Manual ELCB
Earth Leakage Circuit Breaker
EMF
Electromagnetic Field
ENGR
Engineering
EPA
Environmental Protection Agency
EPR
Earth Potential Rise
ESAH
Electricity Supply Application Handbook
FHA
Functional Hazard Assessment
FM
Factory Mutual
FOP
Fall-of-Potential
FP
Feeder Pillar
G.I Pipe
Galvanized Iron Pipe
GIS
Gas Insulated Switchgear
GPRS
General Packet Radio Service
GWP
Global Warming Potential
HDPE
High Density Polyethylene
HFU
Housing Fuse Unit
HMI
Human Machine Interface
H-Pole
Pole Mounted Substations
HRC
High Rupture Capacity
HV
High Voltage
HX RTC
HX Remote Terminal Controller
ICCP
Inter-Control Centre Protocol
IEC
International Electrotechnical Commission
IED
Intelligent Electronic Device
IEEE
Institute of Electrical and Electronic Engineers
IOM
Interconnection Operation Manual
IP
Ingress Protection
ISO
International Organization for Standardization
LBS
Load Break Switch
LCP
Local control panel
LFI
Line Fault Indicator
LHS
Left Hand Side
LILO
Loop-in, loop-out
LPDC
Loss Prevention Certification Boards
Appendix LV
Low Voltage
LVAC
Low Voltage AC
M&E MCB MDPE
Management and Engineering Miniature Circuit Breaker Medium Density Polyethylene
MDU
Motor Drive Unit
MSB
Main Switch Board
MTB
Meter Test Box
MV
Medium Voltage
NER
Neutral Earth Resistance
NOAEL
No Observable Adverse Effect Level
NTL
Non-Transferable Load
OCEF
Over Current Earth Fault
OCTC
Off-Circuit Tap Changer
ODP
Ozone depletion potential
OLG
Oil Level Gauge
OLTC
On-Load Tap Changer
PAT
Pencawang Atas Tiang / Pole Mounted Substation
PBPK
Physiologically-based Pharmacokinetic
PE
Pencawang Elektrik / Distribution Substation
PECU
Photoelectric Control Unit
PF
Power Factor
PMU
Pencawang Masuk Utama / Main Intake Substation
PN6
Pressure Nominal 6 – max pressure 6 bar
PPU PRD
Pencawang Pembahagian Utama / Primary Distribution Substation Pressure Relief Device
PSI
Process System Improvement
PT
Potential Transformer
PVC
Polyvinyl Chloride
RC
Reinforced Concrete
RCB
Remote Control Box
RCC REF RHS
Regional Control Centre Restricted Earth Fault Right Hand Side
433
434
Substation Design Manual RMU
Ring Main Unit
RMU CB
Ring Main Unit with Circuit Breaker
RTCC
Remote Transformer Control Cubicle
RTU
Remote Terminal Units
S/S
Stesen Suis / Switching Station
SAIDI
System Average Interruption Duration Index
SAVR
Sesalur Atas Voltan Rendah
SBB
Single Bus-Bar
SBEF
Stand by Earth Fault
SCADA
Supervisory Control And Data Acquisition
SF6
Sulphur hexafluoride
SGP
Sijil Guna Pakai
SILFOS
Silver Copper Phosphorus
SIP
SCADA Interface Panel
SPCC
Spill Prevention Control and Countermeasures
SSU
Stesen Suis Utama / Primary Switching Station
SWA
Steel Wire Armoured
SWG
Standard Wire Gauge
TTB
Test Terminal Block
UL
Underwriter Laboratories
uPVC
Unplasticised Polyvinyl Chloride
VA
Volt-Ampere
VAR
Volt-Ampere Reactive
VCB
Vacuum Circuit Breaker
VDC
Voltage Direct Current
VdS
German fire protection institute/Vertrauen durch Sicherheit
VT
Voltage Transformer
WISP+
Wireless Internet Service Provider
XLPE
Cross-link Polyethylene
Appendix
Glossary Annunciators
An indicator showing remotely whether each of several items is in the required position or state or not, e.g. door signal with automatic doors or lamp indicating any of several abnormal conditions
Bio-degradable
Biodegradation or biotic degradation or biotic decomposition is the chemical dissolution of materials by bacteria or other biological means
Busbar
Low-impedance conductor to which several electric circuits can be connected at separate points
Bushing
Device that enables one or several conductors to pass through a partition such as a wall or a tank, and insulate the conductors from it.
Carcinogenic
Any substance, radionuclide, or radiation that is an agent directly involved in causing cancer
Clearance
Shortest distance in air between two conductive parts
Creepage distance
Shortest distance along the surface of a solid insulating material between two conductive parts
Discrepancy Switch
A switched indicator, with an acknowledgement facility, which shows any discrepancy between the actual and indicated state of the equipment being monitored
Double Busbar Substation
A substation in which the lines and transformers are connected via two busbars by means of selectors
Earth Resistance
The resistance existing between the electrically accessible part of a buried electrode and another point of the earth, which is far away
Heat Shrink
Mechanically expanded extruded plastic tube ordinarily made of nylon or polyolefin, which shrinks when heated in an effort to return to the relaxed diameter it originally had when extruded
Incoming Feeder
In a substation a feeder bay which is normally used to receive power from the system
Interlock
A device used to help prevent a machine from harming its operator or damaging itself by stopping the machine when tripped
Internal Arc
The result of a rapid release of energy due to an arcing fault between phases, neutral or a ground
Magnetostriction
Reversible deformation of a body due to magnetization arising from an applied magnetic field
435
436
Substation Design Manual
Main Busbar
In a double busbar substation, any busbar which is used under normal conditions
Mimic Diagram
An arrangement of symbols representing the current state of switchgear and lines of a substation (network) and which may be updateable and may have control functions
Outgoing Feeder
In a substation a feeder bay which is normally used to transmit power to the system
Photoelectric
Applies to electrical phenomena caused by absorption of photons
Plinth
a usually square block serving as a base; broadly: any of various bases or lower parts
Pole-mounted Substation
An outdoor distribution substation mounted on one or more poles
Premix
Something that is mixed or blended from two or more ingredients or elements before being marketed, used, or mixed further
Relay
Relating to, or having the characteristics of, an auxiliary apparatus put into action by a feeble force but itself capable of exerting greater force, used to control a comparatively powerful machine or appliance
Reserve Busbar
In a double busbar substation, any busbar which is used under abnormal conditions. It is generally less well equipped than a main busbar
Ring Substation
A single busbar substation in which the busbar is formed as a closed loop with only disconnectors in series within the loop
Semaphore
Indication of 'Close' and 'Open' position of circuit breakers, isolators and earth switches shall be incorporated in the mimic diagram
Short Circuit
A low-resistance connection established by accident or intention between two points in an electric circuit. The current tends to flow through the area of low resistance, bypassing the rest of the circuit.
Silmalec
Aluminium alloys containing magnesium and silicon, the two latter ingredients acting as hardeners and can be heat-treated.
Single Busbar Substation
A substation in which the lines and transformers are connected to one busbar only
Soil Resistivity
Function of soil moisture and the concentrations of ionic soluble salts and is considered to be most comprehensive indicator of a soil’s corrosivity
Appendix Spur Connection
Feeder to which subscriber's taps or looped system outlets are connected
Step-down Substation
A transformer substation in which the outgoing power from the transformers is at a lower voltage than the incoming power
Step-up Substation
A transformer substation in which the outgoing power from the transformers is at a higher voltage than the incoming power
Substation
The part of a power system, concentrated in a given place, including mainly the terminations of transmission or distribution lines switchgear and housing and which may also include transformers. It generally includes facilities necessary for system security and control (e.g. the protective devices)
Switching Substation
A substation which includes switchgear and usually busbars, but no power transformers
Switchyard
Typically found in AIS PMU and Outdoor PPU, it contains the air insulated switching installations
Tracking
The progressive degradation of the surface of a solid insulating material by local discharges to form conducting or partially conducting paths
Transducer
A device capable of being actuated by one or more input quantities and of supplying output quantities related to the input quantities, but of different physical nature
Vector Group
Indicates the phase difference between the primary and secondary sides, introduced due to that particular configuration of transformer windings connection
Ventricular Fibrillation
Heart rhythm problem that occurs when the heart beats with rapid, erratic electrical impulses
Viscosity
A measure of the resistance of a fluid which is being deformed by either shear stress or tensile stress.
437
Related Documents
Substation Design -manual
January 2021 0
Substation: Design Manual
January 2021 0
Substation Design
January 2021 2
Substation-design-application.pdf
January 2021 0
Substation Structure-design Guide
January 2021 0
Substation Commissioning Engineer Manual
January 2021 0More Documents from "greendragon2009"