Diagnostic Techniques For Condition Monitoring Of Transformers

Diagnostic Techniques for Condition Monitoring of Transformers

ARSEPE 2008

Young Zaidey bin Yang Ghazali Technical Expert (Transformer Performance & Diagnostic) Engineering Department TNB Distribution Division 1

1. INTRODUCTION


Electrical distribution equipment is generally designed for a certain economic service life.




Equipment life is dependent on operating environment, maintenance program and the quality of the original manufacture and installation.




Beyond this service life period they are not expected to render their services up to expectation with desired efficiency.

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1

1. INTRODUCTION


Generally due to poor quality of raw material, workmanship and manufacturing techniques or due to frequent electrical, mechanical and thermal stresses during the operation, many equipment fail much earlier than their expected economic life span.




The concept of simple replacement of failed power equipments in the system either before or after their economic service life, is no more valid in the present scenario of financial constraints.

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1. INTRODUCTION








Explore new approaches/techniques of monitoring, diagnosis, life assessment and condition evaluation, and possibility of extending the life of existing assets (i.e. circuit breaker, cables, transformers, etc.) Minimization of the service life cycle cost is one of the stated tasks of the electrical power system engineers. For electrical utilities this implies for example to fulfill requirements from customers and authorities on reliability in power supply at a minimal total cost. The main goal is therefore to reach a cost effective solution using available resources which is captured by the concept of Asset Management. 4

2

Asset Management Mechanism Operate efficiently

Reasonable returns

High Performance

Low Cost

• SAIFI, SAIDI • Power quality • Power availability • Reduced Loss etc.

ASSET MANAGEMENT

• Investment • O&M • Stocking etc.

Balancing cost, risk, and performance in the context of asset full life cycle

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T&D ASSET MANAGEMENT

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Maintenance Management


With the increasing age of the population of power system equipment utilities are making efforts to assess the internal condition of the equipment while in service before catastrophic failures can take place




Different types of maintenance being done on equipment are:  Breakdown maintenance  Time or Calendar Based maintenance  Condition based maintenance  Reliability centered maintenance 8

Maintenance Management


Today the paradigm has changed from traditional calendar based to condition based maintenance and efforts are being channeled to explore techniques to monitor, diagnose and assess condition of power system equipment




This has led to the development of various on- and off-line non-intrusive tests in recent years that allow diagnosing the integrity of power system equipment to optimize the maintenance effort thereby ensuring maximum availability and reliability 9

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Why ‘Condition Based’?









Ageing asset population Age by itself is not a good predictor of future performance Must be able to fully justify decisions in terms of proven engineering principles Cannot make sound asset management decisions unless you understand asset condition! 10

What is CBM? Combining all available practical and theoretical knowledge and experience of assets to:


Define current condition and use this to estimate future condition and performance  Provide a sound engineering basis for evaluating risks and benefits of potential investment strategies 

Uses a well developed methodology (with practical experience of successful application) Provides a framework for continual improvement (information and definition of condition)


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Why condition based?


Ageing asset population




Pressures to maintain/improve performance and to reduce costs




Age (by itself) is not an acceptable reason to replace assets




Must demonstrate need and consequences, condition and future performance




Cannot make good Asset Management decisions unless you understand asset condition!

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Condition Based Management











Define asset condition (Health Index) Link condition to performance & probability of failure (PoF) Calibrate Health Index/PoF against historic fault rates Estimate future condition and performance Evaluate effect of investment programmes on future condition and performance Provides an ENGINEERING basis to evaluate risk and determine investment requirements

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Defining condition and future performance


Need understanding of: Degradation and failure processes Condition assessment techniques Practical knowledge of assets, Operating context




Everything is related back to physical condition and degradation processes - maximising the value of available experience of the assets

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A health index is:









A consistent and logical means of combining relatively complex information A way to rank assets (on basis of proximity to EOL or probability of failure) Relatively simplistic It is NOT a substitute for engineering expertise and judgement it is an additional aid to engineers

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Health Index Mechanism A Health Index is a means to define proximity to EOL by combining varied and relatively complex condition information as a single number
Define significant condition criteria
Code information numerically,
Apply weightings
Develop a simple algorithm to generate a HI for each asset
Rank and apply calibration 16

Health Index - Ranking Condition

Remnant Life (years)

Probability of failure

Bad

At EOL (<5 years)

High

Poor

5 - 10

Medium

Fair

10 - 20

Good

>20

10

Low Very Low

0

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8

3

5

Serious deterioration significant increase in P(f)

Significant deterioration small increase in P(f)

Measurable deterioration but no significant increase in P(f)

Probability of failure (Pf) 0

10

Health Index

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Information to derive a condition based Health Index



Actual condition information Risk factors with direct condition implications failure rates, specific or generic problems, design issues etc

Other non condition based risk factors can be mapped on later to evaluate overall risk (Criticality, load, obsolescence etc) 19

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Condition based health index








Means of determining probability of failure It does not consider consequences of failure Ultimately require combination of both to evaluate overall risk CBHI is the 1st step (phase 1) Phase 2 use of results in a risk model

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Phase 1 - Condition and Probability of Failure (for each asset group) Review Condition Assessment Techniques

Define EOL Issues

Define Assets

Formulation and Population of HI

HI to Probability of Failure

Documentation Conclusions Report

Data and Information Analysis

Change of HI (PF) with time

CONSEQUENCES Phase 2

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10

Diagnostic Techniques for Condition Monitoring of Transformers

ARSEPE 2008

Young Zaidey bin Yang Ghazali Technical Expert (Transformer Performance & Diagnostic) Engineering Department TNB Distribution Division 1

Transformer Design & Construction

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1

Transformer Design & Construction Types of Transformers
Core Type
Shell Type

Oil-Immersed Type, Dry Type

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Transformer Design & Construction Core Type Transformers

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2

Transformer Design & Construction Shell Type Transformers

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Transformer Design & Construction Typical Winding Connections
Delta – Star
Star - Delta
Star – Star
Delta – Delta

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3

Transformer Design & Construction Other Winding Connections
Zig – Zag Connections
Tertiary Windings
Double Secondary
Scott (T-T) Connections
Autotransformers

Earthing Transformers

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DESIGN CONCEPT The transformer has been designed, manufactured and tested according to IEC 60076 part 1 to 5. Power Transformer It consist of : core, winding, insulation, core and winding assembly, tank.

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4

CORE



Grain Oriented Electrical Steel Type M5 (0.3mm), M4 (0.27mm) and ZDKH (0.23mm)

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WINDING


Are designed to meet three fundamental requirement : 1. Electrical 2. Mechanical 3. Thermal

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5

WINDING • Round, Oval or rectangular in shape and are wound concentrically. • LV winding is wound with foil conductor (Distribution) • HV winding is wound with rectangular strip conductor. • HV winding is wound on LV winding.

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INSULATION








The interlayer insulation are of high quality epoxy coated kraft paper (DDP) Corrugated pressboards are placed within the coil for cooling within the coil. Thickness of layer insulation in accordance with voltage and number of layers.

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6

CORE & WINDING ASSEMBLY


Arrangement of windings with respect to the core : CORE - LV WINDING - HV WINDING




For tapping lead connection normally use stranded copper or round conductor.




Bushing Lead :1. HV - stranded copper 2. LV - copper bar or flexible copper base on LV rated current.

13

TANK






It is hermetically sealed type and full fill with insulation liquid. Oil expansion or contraction due to the change in the transformer load is accommodated by the corrugated finwall of the transformer tank. Corrugated fins are use to provide sufficient cooling surface to dissipate the heat generated by the windings.

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7

TERMINATION



Both HV & LV is open bushing termination. Cable Box

15

MANUFACTURING PROCESS FLOW CHART 1. Rectangular copper

Paper Covering

Core Cutting

Fabrication

2. Foil Sheet

Low Voltage Winding

Core Winding Assembly

High Voltage Winding

Core Building

Drying Process

Tanking Process

Vacuum & Oil Filling

Despatch

Finishing

Testing

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8

Transformer Design & Construction Phasor Relationships
Transformer winding connections produced a Phase Shift between primary & secondary
Angle of phase shift depend upon the winding connection method adopted for primary and secondary

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Transformer Design & Construction Phasor Relationships Eg.
Phase Shift of secondary windings is +30 wrt primary designated with Dyn11
Significant of Phase Shift – Paralleling of Transformer & interconnection of system

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9

Transformer Design & Construction Tapping & Tap Changers

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Transformer Design & Construction Tapping & Tap Changers – Functions








To compensate for changes in the applied voltage on bulk supply To compensate for regulation within the transformer & maintain the output voltage constant To assist in the control of system VArs flows To allow for compensation for factors not accurately known at the time of planning To allow for future changes in system conditions

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Transformer Design & Construction Type of Tap Changers
On-Load Tap Changer (OLTC)
Off Circuit Tap Changer (OCTC) Tap Changer Mounting
Internal (In-tank)
External (Side mounted) 21

Transformer Design & Construction OLTC Technology
Oil Type OLTC
Vacuum Type OLTC (Vacutap)

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11

Transformer Design & Construction OLTC Main Components






Tap Selector Diverter Switch Selector Switch Change-over selector Transition Impedance

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Transformer Design & Construction Motor Drive Mechanism to operate OLTC








Step-by-step control Tap Position Indicator Limiting Devices Parallel Control Devices Emergency Tripping Device Overcurrent Blocking Device Restarting Device

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Transformer Ancillary Equipment Pressure Relief Device

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Transformer Ancillary Equipment Gas & Oil Actuated Relays (Buchholz)

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Transformer Ancillary Equipment Temperature Indicators
Winding HV & LV
Top Oil

Fans Control

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Transformer Ancillary Equipment Oil Level Indicators

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14

Transformer Ancillary Equipment Other Ancillary Equipment
Conservator Tank
Cooling System/Radiators
Bushings
Cable Box
Oil Valves
Thermometer Pockets

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Diagnostic Techniques for Condition Monitoring of Transformers

ARSEPE 2008

Young Zaidey bin Yang Ghazali Technical Expert (Transformer Performance & Diagnostic) Engineering Department TNB Distribution Division 1

Transformer Insulating Oil & Paper Diagnostics

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1

Oil & Paper Tests in Main Tank & OLTC 1. Oil Quality Test


Physical Properties  Visual Appearance  Colour  Flash Point  Viscosity  Density  Pour Point  IFT  Particle Count 3

Oil & Paper Tests in Main Tank & OLTC 1. Oil Quality Test


Chemical Properties  Moisture Content  Acidity  Corrosive Sulphur  Oxidation Stability  Sludge Sediment

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2

Oil & Paper Tests in Main Tank & OLTC 1. Oil Quality Test


Electrical Properties  Breakdown Voltage  Dissipation Power Factor

2. DGA

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Insulation Condition Assessment Life Span of Power Transformers Depends on Integrity of Insulation

Most Commonly Used Insulations for Power Transformers

• • •

OIL Provides overall insulation to the transformers Acts as coolant in extinguishing arcs Provides the means to monitor insulation condition and operation of transformers

PAPER Provides insulation to the conductor in the transformer windings

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Insulation Condition Assessment PRIMARY STRESSES 1. Stresses applied on the transformer due to normal operation: • Thermal • Electrical • Mechanical 2. Application of these stresses can be: • Continuous • Cyclic • Intermittent

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Insulation Condition Assessment SECONDARY STRESSES 1. Factors that can influence the ageing rate when primary stresses are applied 2. Simply known as Ageing Factors Examples of these Ageing Factors can be: 3. Operational factors of the transformers • Environmental factors i.e. radiation, moisture or water, oxidative agents and corrosive materials • Technological factors i.e. type of oil and paper used • Tests done on the transformers that can influence the performance of the insulation system

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Insulation Condition Assessment Oil Insulation Deterioration – Reversible 1. Oil insulation condition can be reversed through on-line filtration 2. Can reduce the effect of the Ageing Factors 3. Can prolong serviceability of the oil insulation

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Insulation Condition Assessment Paper Insulation Degradation – Irreversible • Paper insulation degradation is irreversible • Oil filtration has negligible effect on reversibility of paper degradation • Ageing of paper directly linked to its mechanical strength • Loss of mechanical strength eventually leads to loss of dielectric strength • Once paper loses its dielectric strength, the transformer is deemed to have reached the end of its service life • Thus, the life of a transformer can be effectively determined by the life of its paper insulation 10

5

Insulation Condition Assessment Three most common degradation factors of cellulose: Thermal 1. When exposed to heat up to 220ºC, the glycosidic bond tend to break and open the glucose molecule rings 2. By-products: • Free glucose • H 20 • CO • CO2 • Organic acids

Heat

H O

OH

H20

CO

Glycosidic bonds broken and glucose rings opened Generates the following: CO2

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Insulation Condition Assessment Three most common degradation factors of cellulose: Oxidative 1. 2. 3. 4.

Presence of oxygen promotes oxidation Glycosidic bond weakens Causes scission to the cellulose chain By-products include H20

CH2OH

O2

COOH

COOH

Glycosidic bonds weakened and moisture produced

CHO

Hydrolytic H20 or acids

1. 2. 3. 4.

Presence of water and acids Glycosidic bond exposed to slicing Causes scission to the cellulose chain By-products include free glucose

CH2OH HO

OH

Free glucose produced

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6

Insulation Condition Assessment Degradation By-Products 1. It can be observed that by-products related to paper degradation can include the followings: • • • • •

CO CO2 H 2O Organic acids Free glucose molecules

2. With H2O and organic acids present in the oil, the free glucose molecules can degrade to 5-hydroxymethyl-2-furfuryl or 5H2F

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Insulation Condition Assessment Degradation By-Products 3. 5H2F is an unstable free glucose molecule and can decompose further to other furaldehyde as follows: • • • •

2-furfuryl alcohol (2FOL) 2-furaldehyde (2FAL) 2-acetyl furan (2ACF) 5-methyl-2-furfuryl (5M2F)

4. All these 5 compounds of glucose or degradation of glucose are known as Furans. 5. 2FAL is the most stable in the group 6. Furan generation is exclusively due to paper degradation unlike CO, CO2, H2O or acids which can also be produced through oil oxidation or breakdown. 14

7

Insulation Condition Assessment


When taking an oil sample from a sealed tank transformer, ensure that the transformer is not under vacuum by checking the vacuum/pressure gauge




Use a clean glass syringe/beaker (provided by the laboratory) and follow the proper sampling procedure – ASTM D923 & D3613 (IEC 60475 & IEC 60567)




Interpret the quantified results to help determine the relative health of the transformer, offer clues to the origin of potential problems and develop a strategy to avoid catastrophic failure – IEEE C57.106 15

Insulation Condition Assessment Important factors to be considered prior to taking a sample: 1. Sample Containers 2. Sampling Technique 3. Weather condition 4. Sample storage and transport

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8

Insulation Condition Assessment













Characteristic of Sample Containers:
500 ml or 1 liter (Duplicate)
Syringe – DGA Seal the sample from external contamination Store samples in the dark to prevent from photodegradation Cleaning and preparation of valves Avoid liquid spillage, some oil may still contains PCBs Identification of the sample and apparatus information Sampling outdoors in rain, strong wind and night time should be avoided Should not be stored longer than a few days before sending to the laboratory for analysis 17

Insulation Condition Assessment Adaptor Valve Transformer

Use correct vessel (good cap and seal) Plastic tube

Cap Seal

Filled Sample bottle

Dark Brown Bottle 500 mL

Waste Vessel

Sufficient sample

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9

Insulation Condition Assessment

Adaptor Valve

Plastic tube

Transformer

Syringe

Sufficient sample Waste Vessel

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Insulation Condition Assessment


To effectively interpret DGA results requires insights in the characteristics of dissolved gas in oil evolution, an understanding of transformer design, and knowledge of materials used by transformer manufacturer and operating conditions – ASTM D3612




ASTM D3612 Test methods for analysis of dissolved gases by gas chromatography




IEEE C57.104 Guide for interpretation of gases

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Insulation Condition Assessment On-Line Assessment of Insulation Condition 1. Oil Quality Tests – to assess the physical, electrical and chemical properties of the oil 2. Dissolved Gas-in-oil Analysis – to detect and identify incipient faults 3. Furan Compound Analysis – to detect and identify degradation of paper insulation (on-line test) 4. Degree of Polymerization Test – to measure degradation of paper insulation (intrusive mechanism) 21

Insulation Condition Assessment Oil Screening Tests 1. Colour – serious contamination 2. IFT – moisture in oil (> 15 mN/ m) 3. Neutralization Number – level of acidity (< 0.2 mg KOH / gm) 4. Dielectric Strength – contaminants (water & conducting particles) ( > 30 kV) 5. 5. Water Content – amount of dissolved water in ppm (< 30 ppm)

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Insulation Condition Assessment IEEE C57.106 Limits – Oil Quality Tests


Colour – 0.5




IFT – > 25 mN/ m for ≤ 69 kV




Neutralization Number – < 0.2 mg KOH / gm




Dielectric Strength – > 20 kV for ≤ 69 kV for 1 mm gap




Water Content – < 27 ppm for ≤ 69 kV at 50 0C 23

Insulation Condition Assessment Other Oil Quality Tests • • • • • • • •

Specific Gravity Viscosity Power Factor Resistivity Flash Point Visual PCB Content Inhibitor Content

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Oil Quality Screening Tests


Water Content (D 1533 / IEC 733) A low water content is necessary to obtain and maintain acceptable electrical strength and low dielectric losses in insulation systems.




Color (D 1500) The color of a new oil is generally accepted as an index of the degree of refinement. For oils in service, an increasing or high color number is an indication of contamination, deterioration, or both.




Dielectric Breakdown (D 877 / D 1816 / IEC 156) It is a measure of the ability of an oil to withstand electrical stress at power frequencies without failure. A low value for the dielectric-breakdown voltage generally serves to indicate the presence of contaminants such as water, dirt, or other conducting particles in the oil. 25

Oil Quality Screening Tests


Neutralization Number, NN (D 664) A used oil having a high neutralization number indicates that the oil is either oxidized or contaminated with materials such as varnish, paint, or other foreign matter.




Interfacial Tension, IFT (D 971) The interfacial tension of an oil is the force in dynes per centimeter or millinewton per meter required to rupture the oil film existing at an oil-water interface. When certain contaminants such as soaps, paints, varnishes, and oxidation products are present in the oil, the film strength of the oil is weakened, thus requiring less force to rupture. For oils in service, a decreasing value indicates the accumulation of contaminants, oxidation products, or both.

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13

Oil Quality Screening Tests


Index = IFT/NN. This index provides a more sensitive and reliable guide in determining the remaining useful life of a transformer oil. A Index below 100 indicates that the oil is significantly oxidized and that the oil needs to be replaced in the near future.

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Insulation Condition Assessment


Non-fault gases - Oxygen (O2) & Nitrogen (N2) Note: If the ratio O2/N2 is less than 0.3 then it indicates overheating of oil. This is not a standard, use with caution.




Fault gases - Hydrogen (H2), Acetylene (C2H2) Carbon Monoxide (CO), Carbon Dioxide (CO2) Ethylene (C2H4), Ethane (C2H6) Methane (CH4)

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14

Insulation Condition Assessment

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Insulation Condition Assessment

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Insulation Condition Assessment Dissolved Gas-in-oil Analysis Fault Condition

Key Gases

Overheated Oil

Methane, Ethane & Ethylene

Partial Discharge

Hydrogen & Acetylene

Overheated Cellulose

Carbon Monoxide & Carbon Dioxide

Non-Fault Gases are Oxygen & Nitrogen

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Insulation Condition Assessment Dissolved Gas-in-oil Analysis

Fault Condition

Key Gases




Thermal Oil

Major – Ethylene & Methane Minor – Ethane & Hydrogen




Electrical – low energy Major – Hydrogen & Methane Minor – Ethane & Ethylene




Electrical – high energy Major – Acetylene & Hydrogen Minor – Ethylene & Methane




Thermal Cellulose

Major – Carbon monoxide & Carbon dioxide Minor – Methane & Ethylene

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Insulation Condition Assessment

IEEE Limit










Hydrogen (H2) Oxygen (O2) Nitrogen (N2) Carbon Monoxide (CO) Methane (CH4) Carbon Dioxide (CO2) Ethylene (C2H4) Ethane (C2H6) Acetylene (C2H2)

100 ppm N/A N/A 350 120 2500 50 65 35 33

Insulation Condition Assessment Dissolved Gas-in-oil Analysis Ratio Method is used for fault analyzing, not for fault detection. Ratio Method

Ratios

Roger’s

C2H2/C2H4 , CH4/H2 & C2H4/ C2H6

IEEE

CH4/H2, C2H2/C2H4, C2H2/ CH4, C2H6/ C2H2, C2H4/ C2H6

Never make a decision based on only ratio. Take into consideration the gas generation rates and amount of total combustible gases.

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Insulation Condition Assessment


Roger’s Ratio comparison methods look at pairs of gases, and develop a coding system to help define potential fault conditions

Roger’s Ratio Code C2H2 / C2H4 < 0.1 0 0.1 -<1.0 1 1.0 - <=3.0 1 > 3.0 2




CH4 / H2 1 0 2 2

C2 H4 / C2H6 0 0 1 2

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Insulation Condition Assessment IEC DGA Ratios C2H2 CH4 C2H4 Case C2H4

H2 C2H6

0

0

0

0

No Fault, Normal

1

0

1

0

Partial discharges of low energy

2

1

1

0

Partial discharges of high energy density

3

1

0

1

Discharges of low energy, Arcing

3

2

0

1

Discharges of low energy, Arcing

3

2

0

2

Discharges of low energy, Arcing

4

1

0

2

Discharges of high energy, Arcing

5

0

0

1

Thermal Fault, 150 C, Conductor Overheating

6

0

2

0

Thermal Fault, 150 - 300 C, Oil Overheating, Mild

7

0

2

1

Thermal Fault, 300 - 700 C, Oil Overheating, Moderate

8

0

2

2

Thermal Fault, 700 C, Oil Overheating, Severe

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Insulation Condition Assessment TDCG (ppm)

Status

Remark

≤ 720

Condition 1

Transformer working satisfactorily. Look for individual gas exceeding respective limit.

721-1920

Condition 2

Faults may be present. Additional investigation required based on individual gas exceeding respective limit.

1921-4630

Condition 3

Faults probably present. Additional investigation required based on individual gas exceeding respective limit.

> 4630

Condition 4

Continued operation could result in failure of the transformer As per IEEE C57.104 37

Insulation Condition Assessment


CO2/ CO ratio indicates cellulose degradation CO2 / CO ratio <3 3 -<5 5 - <=11 > 11

Condition of Cellulose Severe Arcing & Short circuit damage Indicates concern Normal Indicates damage due to general overheating

According to IEEE C57.104 the normal value is 7 38

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Exercise (Oil Condition) Transformer Gas Analysis Component HYDROGEN (H2) OXYGEN (O2) NITROGEN (N2) CARBON MONOXIDE (CO) METHANE (CH4) CARBON DIOXIDE (CO2) ETHYLENE (C2H4) ETHANE (C2H6) ACETYLENE (C2H2)

ppm in oil 10 26200 48500 41 5 570 2 2 1 39

Exercise (Oil Condition) Transformer Gas Analysis Component

ppm in oil

HYDROGEN (H2) OXYGEN & ARGON (O2 + A) NITROGEN (N2) CARBON MONOXIDE (CO) METHANE (CH4) CARBON DIOXIDE (CO2) ETHYLENE (C2H4) ETHANE (C2H6) ACETYLENE (C2H2)

720 17000 45400 405 1310 6050 5200 1810 256 40

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Exercise (Paper Condition) Transformer Gas Analysis Component HYDROGEN (H2) OXYGEN & ARGON (O2) NITROGEN (N2) CARBON MONOXIDE (CO) METHANE (CH4) CARBON DIOXIDE (CO2) ETHYLENE (C2H4) ETHANE (C2H6) ACETYLENE (C2H2) 2FAL

ppm in oil 105 18000 33400 870 400 12,100 260 28 52 ppb in oil 195 41

Exercise (Oil + Paper Condition) Transformer Gas Analysis Component HYDROGEN (H2) OXYGEN & ARGON (O2 + A) NITROGEN (N2) CARBON MONOXIDE (CO) METHANE (CH4) CARBON DIOXIDE (CO2) ETHYLENE (C2H4) ETHANE (C2H6) ACETYLENE (C2H2) 2FAL

ppm in oil 103 16762 20458 0 814 1816 109 75 118 ppb in oil 225 42

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Insulation Condition Assessment Furanic Compound Analysis Fault Condition

Furan Compound

Overheating or Short circuit

2FAL

Excessive Moisture

2FOL

Lightning Strikes

2ACF

Intense Overheating

5M2F

Oxidation

5H2F

Concentration limits of furan compounds must be supported by CO2/CO Ratio to assess paper degradation 43

Insulation Condition Assessment

2FAL limits (ppb in oil): 58 – 292 – Normal Aging 654 – 2021 – Accelerated Aging 2374 – 3277 – Excessive Aging 3851 – 4524 – High Risk of Failure

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Insulation Condition Assessment Criteria to select transformers for further investigation

•

Transformer Age

•

Operational Criterion – number of faults, switching, lightning, etc.

•

DGA Criterion (oil) – Individual concentrations of CH4, C2H2, C2H4, C2H6 & H2 in ppm & Roger’s/IEEE Ratio

•

DGA Criterion (paper) – Individual concentrations of CO2 & CO in ppm & CO2/CO Ratio

•

Furan Criterion – 2FAL concentration in ppb & others if detected 45

Insulation Condition Assessment Correlation between TS, DP and Furan • Ageing of paper insulation is related to the decrease in TS. • TS is directly related to DP – ASTM D 4243. • Decrease in DP is directly related to the increase in Furan. • Thus, as paper aged, it loses its TS. Loss of TS indicates decrease of DP. Decrease of DP causes increase in Furan in the insulating oil. It can be deduced that as paper aged towards its end of service life, the level of Furan content increases. 46

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Insulation Condition Assessment Degree of Polymerization • One of the most dependable means of determining paper deterioration and remaining life of the cellulose. • The cellulose molecules is made up of a long chain of glucose rings which form the mechanical strength of the molecule and the paper. • DP is the average number of these rings in the molecule. • As paper ages or deteriorates from heat, acids, oxygen and water the number of these rings decrease. 47

Insulation Condition Assessment Degree of Polymerization Following Table has been developed by EPRI to estimate remaining paper life 1. New insulation

1000 DP to 1400 DP

2. 60% to 66% life remaining

500 DP

3. 30% life remaining

300 DP

4. 0 life remaining

200 DP 48

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Insulation Condition Assessment •

The life of a transformer can be effectively determined by the life of its paper insulation.

•

DP is considered direct approach to determine the paper insulation condition but it is intrusive. Some are skeptical since integrity of paper insulation may be disturbed and may further damage the paper insulation.

•

Alternatively, it can be achieved through the use of paper degradation byproducts e.g. CO, CO2, CO2/CO, 2 FAL, H2 as indicators. It is non-intrusive and requires only samples of the transformer oil which can be obtained without any shutdown.

•

The challenge is to develop a Mathematical Model to Estimate DP Value of Paper Insulation based on the Paper Degradation By-Products i.e. DP = f (CO, CO2, CO2/CO, 2 FAL, H2) 49

LTC – OIL ANALYSIS


By plotting the relative percentages of methane, ethylene and acetylene onto a special triangular coordinate system, a graphical output of the likely cause of gassing is generated.




The causes are categorized as follows. • D1 – Discharges of low energy • D2 – Discharges of high energy • T1 – Thermal faults < 300°C • T2 – Thermal faults 300°C to 700°C • T3 - Thermal faults > 700°C • DT – Mixture of thermal and electrical faults • PD – Partial discharge (No samples indicated this type of fault) 50

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Case Study


The following gas levels were detected via DGA on the oil from the load tap changer: – 42 ppm of methane – 17 ppm of Ethylene – 0 ppm of acetylene




Calculate percentages of each gas and use Duval’s triangle approach to find the cause

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LTC – OIL ANALYSIS

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LTC – OIL ANALYSIS Guideline set by an US Utility


When the acetylene or hydrogen reaches a threshold level of 500ppm the unit is put to monthly DGA testing schedule




DGA monthly testing schedule

Hydrogen > 1500 ppm Acetylene > 1000 ppm Ethylene > 1000 ppm


When Ethylene level exceeds the maximum value the unit is removed from service

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Exercise


The following gas levels were detected via DGA on the oil from the load tap changer: – 319 ppm of methane – 181 ppm of Ethylene – 1351 ppm of acetylene




Calculate percentages of each gas and use Duval’s triangle approach to find the cause

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Diagnostic Techniques for Condition Monitoring of Transformers

ARSEPE 2008

Young Zaidey bin Yang Ghazali Technical Expert (Transformer Performance & Diagnostic) Engineering Department TNB Distribution Division 1

Transformer Basic On-Site & Off Line Diagnostic Testing

2

1

Electrical Tests 1.

Basic Electrical Tests Insulation Resistance




•

Traditional Polarization Index (PI) test to detect moisture content

Tan Delta




•

Insulation Condition Assessment

To detect water in cellulose and chemical contamination

Winding Resistance




•

To detect open or short circuits or poor electrical connection in the windings

Turns Ratio


•

To detect Shorted Turns 3

Electrical Tests 2.

Advanced DiagnosticTests




Frequency Response Analysis (FRA) Recovery Voltage Measurement (RVM) Polarization Depolarization (PDC) Frequency Dielectric Spectroscopy (FDS) Partial Discharge (PD) OLTC Motor Current Signature Analysis (MCSA) OLTC Vibration Signature Analysis (VSA)









4

2

On-site Testing Categorization of On-site Tests






Destructive off-line tests are “go/no go” tests Non destructive off-line tests are diagnostic tests Non destructive on-line tests are condition monitoring tests

5

On-site Testing


These on-site tests are performed individually or in combination : 

 

Before energizing a new equipment as a commissioning test After maintenance After network alteration

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3

Damaging Factors of Insulation

7

Fig 4-4

8

4

Thermal Withstandibility of Insulation Medium According to Classes Insulation Classes by Degrees Centigrade 250

240

240+

Class S

Class C

220

225 200 200 180

Degrees Centigrade

175 155 150 130 125 105 100 Class A

Class B

Class F

Class H

Class N

Class R

9

Insulation Condition Assessment






Insulation resistance test (a) Insulation current test (b) Power factor (c) DC voltage withstand (d) AC voltage with-stand (e)

10

5

Insulation Condition Assessment










Method (e) is primarily used in factory tests Method (d) is primarily used as commissioning test Practically all routine field tests are made using nondestructive methods (a), (b) and (c) Methods (a) and (c) must also be used as commissioning test No single test method can be relied upon for indicating all conditions of weakened insulation

11

Basic Electrical Tests Insulation Resistance Reading corrected to 20oC












Insulation resistance varies inversely with temperature for most insulting materials To properly compare periodic measurements of insulation resistance, it is necessary either to take each measurement at the same temperature, or to convert each measurement to the same base temperature i.e. 200C Polarisation Index is the ratio of the IR reading after 10 minutes to the IR reading after 1minute PI is used as an index of dryness Discharge the winding after a Polarisation Index Test for sufficient time before handling or performing other tests 12

6

Basic Electrical Tests Polarization Index Interpretation of Polarization Index (PI) Measurements

PI Value > 4.0 4.0 – 2.0 2.0 – 1.5 1.5 – 1.0 < 1.0

Interpretation Healthy OK Marginal Pass Deteriorated condition Failure

13

Basic Electrical Tests

14

7

Insulation Resistance Test

15

Insulation Resistance Test Volume Current

Insulation Resistance Tester

Surface leakage current

16

8

Insulation Resistance Test Dielectric Absorption Current

Capacitive Current Conduction Current

Total current

µA

Time

17

Insulation Resistance Test

18

9

Guard Connections

19

3 Terminal Insulation Resistance Tester

20

10

Spot Any Difference? Why?

21

Inaccuracies can occur during IR measurement due to the following





Effect of Previous Charge Effect of Temperature Effect of Moisture Effect of Age and Curing

22

11

Test procedures


Hot resistance test - at least 4 hours after shutdown from full-load operation, or until temperature is stabilized:   

  




Disconnect the equipment to be tested from other equipment Ground the winding to be tested for at least 10 minutes Remove the ground connection and connect the insulation resistance tester Take readings at 1 -minute and at 10 minutes Record the temperature of equipment being tested Ground the winding again for at least 10 minutes

Cold resistance test - Four to eight hours after the hot resistance test or when equipment has cooled to approximately ambient temperature 

Use same procedure as outlined for the hot resistance test

23

Spot Reading

24

12

Temperature Correction







Dry type insulation 40ºC ambient Liquid type insulation 20ºC ambient Insulating materials have negative resistance characteristics Spot test reading must be corrected to a base temperature

25

Conversion Factors For Converting Insulation Resistance Test Temperature to 20°° C Temperature

Multiplier Apparatus Containing Solid Insulations

°C

°F

Apparatus Containing Immersed Oil Insulations

0

32

0.25

0.40

5

41

0.36

0.45

10

50

0.50

0.50

15

59

0.75

0.75

20

68

1.00

1.00

25

77

1.40

1.30

30

86

1.98

1.60

35

95

2.80

2.05

40

104

3.95

2.50

45

113

5.60

3.25

50

122

7.85

4.00

55

131

11.20

5.20

60

140

15.85

6.40

65

149

22.40

8.70

70

158

31.75

10.00

75

167

44.70

13.00

80

176

63.50

16.00 26

13

27

Polarization Index


Polarization index = R10/R1 = I1/I10 (keeping voltage constant) where: R10 = megohms insulation resistance at 10 minutes R1 = megohms insulation resistanceI at 1 minute I1 = insulation current at 1 minute I10 = insulation current at 10 minutes

28

14

Polarization Index

29

Interpretation INSULATION CONDITION

60/30 SECOND RATIO Dielectric Absorption Ratio

10/1 MINUTE RATIO Polarization Index

Dangerous

Less than 1

Less than 1

Poor

Less than 1.1

Less than 1.5

Questionable

1.1 to 1.25

1.5 to 2

Fair

1.25 to 1.4

2 to 3

Good

1.4 to 1.6

3 to 4

Excellent

Above 1.6

Above 4 30

15

Step Voltage Test

31

Step Voltage Test

32

16

Basic Electrical Tests PI & DLF PI If a PI falls by 30% or more from the previous value then remedial action such as cleaning, oil-filtering or further investigation should be considered. Tan Delta If the IFT and oil moisture content exceed their respective limits then Tan Delta test is recommended. This is a good complement to PI test and as remedial action drying is usually performed. Field test results must be corrected to 20o C before comparison.

33

Basic Electrical Tests

Tan Delta (DLF) test

•

In on site tan delta measurement there are two modes namely Grounded Specimen Test (GST) and Ungrounded Specimen Test (UST). During GST mode, the dielectric loss of insulation between one of the windings to ground will be measured depending on the winding that is being excited. Under UST mode, dielectric loss of insulation between the two windings will be measured irrespective of the winding being excited.

•

The ratio obtained from the field test should agree with nameplate value within 0.2% for the insulation system between the high voltage and low voltage winding at all taps. Otherwise, winding repair is recommended.

•

The ratio obtained from the field test should be within the limit of 0.5% for the insulation system between the high voltage winding and ground. Otherwise, winding repair is recommended. 34

17

Power Factor Test

Power Factor = cos θ = ir / it 900 – θ = δ Dissipation Factor = tan δ = ir / ic

35

Power Factor Test


For small δ, Cos (90 – δ) = tan δ




tan δ = ir / ic




ic = ωCV




ir = ωCV tan δ




Power loss (dielectric loss) = V ir = ωCV2 tan δ watt




Dielectric loss is dependent on voltage and frequency




Variation of tan δ with voltage is an important diagnostic method and will be part of this course

36

18

Power Factor Test







Power factor or dissipation factor is a measure of insulation dielectric power loss Not a direct measure of dielectric strength Power-factor values are independent of insulation area or thickness Increase in dielectric loss may accelerate insulation deterioration because of the increased heating Insulation power factor increases directly with temperature Temperature corrections to a base temperature must be made, usually to 20 degree C

37

Power Factor Test







Windings not at test potential should be grounded Refer to IEEE Standard No. 262, 1973 Test sets consist of a completely shielded, high-voltage, 50-Hz power supply which applies up to 10 kV to the equipment being tested Much simpler and less expensive tester is also available which applies about 80 volts to the equipment being tested but not sufficiently shielded against induced voltages

38

19

39

Power Factor Test Set up

40

20

Temperature

correction factors for the power factor of power transformer windings




From IEEE Standard No. 262, 1973

where: FP20 = power factor corrected to 20 degree C FPT = power factor measured at T degree C T = test temperature K = correction factor from table

41

Temperature correction factors for the power factor of power transformer windings

42

21

Power Factor of Some Common Materials Material

Power Factor approx.)

Bakelite

2 - 10%

Vulcanized Fibre

5%

Varnished Cambric

6 - 8%

Mica

2%

Polyethylene

0.03%

New Insulating Oil

0.01-0.2%

43

Insulation Current Test High Voltage DC/AC Test






The voltage is slowly raised in discrete steps, allowing the leakage current to stabilize for a predetermined time A plot of the leakage current as a function of test voltage yields information on the condition of the insulation If the curve is a straight line, it indicates good condition of the cable If the current begins to increase at a rapid rate, indicates degradation / defects in the cable insulation After the completion of the test, the cable under test is grounded for sufficient time to discharge the voltage build up due to effects of absorption currents 44

22

45

Insulation Current Test HVDC 120 100 Indicates Concern

80

Healthy

µA 60 40 20

20

40

60

80

100

Applied Voltage (% of Maximum Voltage)

46

23

47

HIGH-VOLTAGE, DC/AC TESTS








Very little supply power is required to operate the DC test set The DC test set is portable and smaller than an ac, highvoltage tester Disconnect the buswork from the unit The dc breakdown voltage may range from 1.41 times the rms ac breakdown voltage to 2.5 times the rms ac puncture voltage Cases have indicated that on winding insulation with some deterioration, the application of overpotential tests may cause further deterioration, even though the insulation may not puncture 48

24

Test Procedure






The machine winding should be grounded for at least 1 hour before conducting the test The phases should be separated and tested individually Lightning arresters and capacitors must be disconnected Cables and/or buswork should be disconnected if it is convenient to do so If the separation of phases is difficult then separation is needed once for the benchmark tests, and thereafter the phases may be tested together until deviation from normal is detected

49

Test procedure







The voltage should be raised abruptly to the first voltage level with the start of timing for the test. The ratio of the 1-minute to the l0-minute reading of insulation current will afford useful indication of polarization index This gives the test engineer an idea of insulation dryness early in the test The test schedules are arranged to include a minimum of three points up to and including the maximum voltage

50

25

Test procedure















If the insulation microampere versus voltage plots are straight lines, the test may be continued to the maximum test voltages The quality of the insulation may be judged by the position of any curvature or knee in the plot of insulation current versus test voltage If curvature or knee appears, the test should be stopped Upon completion of the dc, high- voltage test, the winding should be discharged through the special discharge resistor usually provided with the test set The winding may be solidly grounded when the voltage has dropped to zero or after a few minutes of discharge have occurred A winding should remain solidly grounded long enough before restoring the machine to service 51

HIGH-VOLTAGE, DC TESTS - RAMPED VOLTAGE METHOD


The ramped technique of insulation testing uses a programmable dc, high-voltage test set and automatically ramps the high voltage at a preselected rate (usually 1 kV/min)




Insulation current versus applied voltage is plotted on an x-y recorder providing continuous observation and analysis of insulation current response as the test progresses




The principal advantages of the ramp test over the conventional step method is the elimination of the human factor which makes it much more accurate and repeatable 52

26

Destructive “go/no go” tests High Voltage DC/AC







Less capable of revealing voids or cavities left inside the accessories Useful in detecting the defects related to contamination along the interface between the different components of the insulation system Voltage applied is usually three to four times the nominal phase-to earth voltage for 15 minutes or more This is destructive test

53

Basic Electrical Tests Turns Ratio test •

This test only needs to be performed if a problem is suspected from the DGA.

•

It indicates shorted turns.

•

Shorted turns may result from short circuits or dielectric (insulation) failures.

•

The ratio obtained from the field test should agree with the factory within 0.5%. Otherwise winding repair is recommended.

54

27

Basic Electrical Tests Turns Ratio test

55

Basic Electrical Tests Turns Ratio test

56

28

Basic Electrical Tests Winding Resistance test •

This test only needs to be performed if there is a high rate of generation of ethylene and ethane.

•

Turns ratio test give indications that winding resistance testing is warranted.

•

Resistances measured in the field can be compared to the original factory measurements or to sister transformers.

•

Agreement within 5% for any of the above comparisons is considered satisfactory.

•

If winding resistances are to be compared to factory values, resistances measurements will have to be converted to the reference temperature used at the factory. 57

Basic Electrical Tests Winding Resistance test •

Since the winding resistance changes with temperature, the winding and oil temperatures must be recorded at the time of measurement and all test readings must be converted to common temperature to give meaningful results. Most factory test data are converted to 75°C which has become the most commonly used temperature.

Rs

=

Rm Ts Tm Tk

= = = =

Resistance at the factory reference temperature (found in the transformer manual) Resistance you actually measured Factory reference temperature (usually 75 °C) Temperature at which you took the measurements A constant for the particular metal the winding is made from: • 234.5 °C for copper • 225 °C for aluminum

58

29

Basic Electrical Tests Winding Resistance test Four terminal testing set up C1

P1

P2

C2

V

I

Measured Resistance (R) = V/I

59

30

Diagnostic Techniques for Condition Monitoring of Transformers

ARSEPE 2008

Young Zaidey bin Yang Ghazali Technical Expert (Transformer Performance & Diagnostic) Engineering Department TNB Distribution Division 1

Transformer Advanced Off-Line Diagnostic Testing

2

1

Advanced Diagnostic Testing









Most of the techniques, whether chemical or electrical methods, or destructive or non-destructive methods, only provide partial information about the state of the insulation condition of power transformers. More advanced condition monitoring or condition assessment techniques have been developed and are now starting to come into more general use. They have been developed in response to the need for new materials assessment methods. However, in some advanced diagnotics tools are still in the developmental stage, either in the technical development or, more likely, in the methods of analysis and interpretation of the test data. 3

Advanced Diagnostic Testing









Recovery Voltage Measurement (RVM) Polarization and Depolarization Current Measurement (PDC) Frequency Domain Dielectric Spectroscopy (FDS) Frequency Response Analysis (FRA) Partial Discharge (PD) Measurement RVM, PDC & FDS are based on the used of the dielectric response of insulating materials to the application of electric fields – Conductivity, Polarization & Dielectric Response

4

2

Advanced Diagnostic Testing Recovery Voltage Measurement (RVM)








When a dielectric material with polar molecular structure is subjected to a DC voltage, the electric dipoles are oriented within the material in response to the applied electric field. There is thus a polarization charge induced by the dipole movement and realignment and this will effectively give a voltage across the capacitance. When the dielectric is short circuited, the stored charge in the dielectric capacitance is dissipated by a current discharge with a time constant determined by the effective intrinsic resistance and capacitance. During the short circuit the voltage across the dielectric is zero, but when the short circuit is removed before total charge to equilibrium occurs, then a voltage will appear across the dielectric. This measured voltage is known as the recovery voltage. 5

Advanced Diagnostic Testing Recovery Voltage Measurement (RVM)

6

3

Advanced Diagnostic Testing Recovery Voltage Measurement (RVM) - TETTEX 5461

7

Advanced Diagnostic Testing Polarization & Depolarization Current (PDC)








A dielectric material becomes polarized when exposed to an electric field. Polarization is proportional to the intensity of the electric field and by measuring the current, polarization process can be observed. The current density is the sum of the conduction current and the displacement current. When the insulating material is exposed to a step voltage, polarization current is obtained. If the step voltage is removed, a reverse polarity current known as depolarization current is obtained. These two currents can be used to determine the response function and the conductivity of the dielectric material. The PDC is a DC testing method which determining the polarization spectrum in time constant domain between 10e-3 – 10e3 seconds in which the interface polarization phenomena of long time constant are active. The range of polarization is strongly influenced by the absorbed moisture and the deterioration by –product content of the paper insulation. It applies a 500V step of DC voltage to the high or low voltage winding insulations of transformers. Time of voltage application is typically up to 10000 seconds. Both the polarization and depolarization times are performed for the same period of time.

8

4

Advanced Diagnostic Testing Polarization & Depolarization Current (PDC)





The polarization current pulse has a peak magnitude, a final steady state level and a time constant and duration that are determined by the quality of the oil including both the moisture level and the electrical conductivity. In genera the electrical conductivity affects the peak current in the first 100 seconds or so of the current pulse. The moisture in the insulation affects the longer term polarization current level after about 1000 seconds. [Figure 8.6] Polarization and depolarization current measurement method gives general information about the state of insulation condition. This technique is proved to be a useful testing method in predicting of moisture and development of ageing phenomena.

9

Advanced Diagnostic Testing Polarization & Depolarization Current (PDC)


Effect of moisture in oil and cellulose paper on the polarization depolarization current measurement

10

5

Advanced Diagnostic Testing Frequency Dielectric Spectroscopy Measurement (FDS)





In the FDS technique, a known sinusoidal voltage is applied and measured together with the current passing across the insulation material. The measurement is repeated for several frequency sweeps from high frequency to low frequency for minimizing the memory effects. 




Advantage - the complete diagnostic on the property change in the material can be discerned

By dividing the current by the voltage and comparing the phase difference, both the capacitance and the loss at the particular frequency and amplitude can be calculated.

11

Advanced Diagnostic Testing Frequency Dielectric Spectroscopy Measurement (FDS)


The advantage of an analysis of the dissipation factor frequency as compare at fixed frequency:  

Behaviour of insulation caused by moisture affects can be evaluated. At higher frequencies the pressboard and the oil volume determine the dielectric loss, at medium frequencies the oil conductivity is the dominant factor and the lower frequency range is dominated by the pressboard dielectric loss.

12

6

Advanced Diagnostic Testing Frequency Dielectric Spectroscopy Measurement (FDS)


Example on how moisture affects the dissipation factor of kraft paper at 20°C

13

Advanced Diagnostic Testing Frequency Dielectric Spectroscopy Measurement (FDS)


Measurement results of the insulation between primary and secondary to tertiary windings on a power transformer.

14

7

Advanced Diagnostic Testing Frequency Dielectric Spectroscopy Measurement (FDS) PROGRAMMA IDA 200

15

Frequency Response Analysis

How do you know whether you can energize A TRANSFORMER after transportation to site or after a protection trip? Check Mechanical Integrity

16

8

Frequency Response Analysis When does Mechanical Integrity matter?    

Re-location Short Circuit Lightning Tap-changer fault

Transportation damage can occur if the clamping and restraints are inadequate; such damage may lead to core and winding movement. Radial buckling or axial deformation may occur due to excessive short circuit forces while in service. 17

Frequency Response Analysis What you can identify by checking mechanical integrity?








Core Movement Winding Deformation Faulty Core Grounds Partial Winding Collapse Hoop Buckling Broken or Loosened Clamping Structures Shorted Turns and Open Windings

18

9

Frequency Response Analysis

What Test can be Done? Frequency response analysis (FRA) using a low voltage AC wave of varying frequency to identify changes in natural resonance

19

Frequency Response Analysis

Why FRA?


FRA Technique: The technique covers the full dynamic range and maintains the same energy level for each frequency, providing results that are repeatable and accurate.




Impulse Technique: This technique requires high sampling rates and high resolution to obtain a valid measurement. The applied impulse does not produce constant energy across the specified frequency, which can cause poor repeatability that is influenced by the non-linear properties of the test specimen.

20

10

Frequency Response Analysis What is FRA ?


FRA is a tool that can give an indication of core or winding movement in transformers.




This is done by performing a measurement to look at how well a transformer winding transmits a low voltage signal that varies in frequency.




Transformer does this in relation to its impedance, the capacitive and inductive elements which are intimately related to the physical construction of the transformer.




Changes in frequency response as measured by FRA techniques may indicate a physical change inside the transformer, the cause of which then needs to be identified and investigated. 21

Frequency Response Analysis

22

11

Frequency Response Analysis

23

Frequency Response Analysis


Test Equipment

24

12

Frequency Response Analysis

25

Frequency Response Analysis

26

13

Frequency Response Analysis

27

Frequency Response Analysis What is the frequency range?


The measured frequency range is normally very large, which can be from 5Hz up to 10MHz




This frequency range covers the most important diagnostic areas:  Core and Magnetic Properties  Winding Movement and Deformation  Interconnections-Leads and Load Tap Changer 28

14

Frequency Response Analysis

29

Frequency Response Analysis


The magnitude and the angle of the complex transfer function can be obtained using a network-analyzer




The resulting amplitude of the measurement can be expressed as, H (dB) = 20 log10 [(ZS)/(ZS+ZT)]




The resulting phase is defined by H (φ) = tan-1 [(ZS)/(ZS+ZT)]

30

15

Frequency Response Analysis

31

Frequency Response Analysis

32

16

Frequency Response Analysis What are the ANALYZING TECHNIQUES?    

Signature Difference Transfer Function Statistical

FRA Signatures are analyzed based on 3 band methods 33

Frequency Response Analysis

What do the 3 Bands mean?








5Hz up to 10KHz – defect in core and magnetic circuit 10KHz up to 600KHz – deformation in winding geometry 600KHz up to 10MHz – abnormalities in the inter-connection and test system

34

17

Frequency Response Analysis SIGNATURE TECHNIQUE

35

Frequency Response Analysis SIGNATURE TECHNIQUE

36

18

Frequency Response Analysis SIGNATURE TECHNIQUE

37

Frequency Response Analysis DIFFERENCE TECHNIQUE (Phase A before)

38

19

Frequency Response Analysis DIFFERENCE TECHNIQUE (Phase A after)

39

Frequency Response Analysis DIFFERENCE TECHNIQUE This technique can analyze the windings phase by phase, which is not possible in the signature technique

40

20

Frequency Response Analysis




Historical data or Baseline Reference are, undoubtedly, the best reference to be used for FRA analysis




However, it is not practically easy to get historical data due to constraints of outages




Criteria to choose reference FRA measurements in the absence of historical data or baseline reference

41

Frequency Response Analysis

CATEGORY

KV RATIO

MVA RATING

MANUFACTURER

S/S LOCATION

Twin

Same

Same

Same

Same

Sister

Same

Same

Same

Different

Peer

Same

Same

Different

Different

42

21

Partial Discharge



What is PD – Electric discharge that do not completely bridge the electrodes Discharge magnitude is usually small but can cause progressive deterioration and lead to failure    




Overeating of dielectric boundary Charges trapped in the surface Attack by ultraviolet rays & soft X-rays Formation of chemicals such as nitric acid & ozone

Therefore presence of PD need to be detected in a non-destructive test

43

Partial Discharge


PD Classification

44

22

Partial Discharge


PD Classification

45

Partial Discharge


Occurrence of PD – Inception Voltage

46

23

Partial Discharge


Occurrence of PD – Inception Voltage

47

Partial Discharge






Occurrence & Recognition Detection Measurement Location Evaluation

48

24

Partial Discharge


Evaluation   

Amplitude in dB Energy or charge in pC Duration in ms

49

Partial Discharge


On-line acoustic PD Detection - Physical Acoustic DISP-24

50

25

Frequency Response Analysis

Why SFRA in a factory environment? • Quality

assurance • Baseline reference • Relocation and commissioning preparation

Manufacturers are using SFRA as part of their quality program to ensure transformer production is identical between units in a batch

51

Frequency Response Analysis Why SFRA in a field environment?

• Relocation and commissioning validation • Post incident: lightning, fault, short circuit, seismic event etc Once a transformer arrives on site after relocation it must be tested immediately, to gain confidence in the mechanical integrity of the unit prior to commissioning

52

26

Frequency Response Analysis








Frequency Response Analysis is a very effective tool for diagnosing transformer mechanical integrity both in the factory and in the field, which cannot always be detected using other means The best way to obtain baseline reference results is, undoubtedly, on completion of the manufacturing process at the factory However, in the absence of baseline reference the proposed criterion of twin, sister, and peer transformers can be used as references with reasonable degree of accuracy 53

Transformer Maintenance (Dry Type)


Electrical Tests 

Perform insulation-resistance tests winding-to-winding and each winding-to-ground



Perform turns ratio tests at the designated tap position



Perform power-factor or dissipation-factor tests





Measure the resistance of each winding at the designated tap position Measure core insulation-resistance at 500 volts dc if core is insulated 54

27

Insulator Maintenance








Inspection - look for cracks, dirt etc., tracking, copper wash, mechanical damage Cleaning - Wash, dry wipe Repairs - Usually replace except special cases Testing - Megger & Power Factor test Do not climb on or use for personal support!

55

Transformer Maintenance (Liquid filled)


Visual inspection 

Inspect physical condition for evidence of moisture and corona



Verify operation of cooling fans



Verify operation of temperature and level indicators, pressure relief device, and gas relay



Verify correct liquid level in all tanks and bushings



Verify correct equipment grounding



Verify the presence of transformer surge arresters



Test load tap-changer



Inspect all bolted electrical connections for high resistance using one of the following methods: 1. Use of low-resistance ohmmeter 2. Perform thermographic survey 56

28

Transformer Maintenance (Liquid filled)


Electrical Tests 

Perform turns ratio tests at all tap positions



Perform power-factor or dissipation-factor tests



Measure the resistance of each winding at all tap positions



Perform insulation-resistance tests winding-to-winding and each winding-to-ground



If core ground strap is accessible, measure core insulation resistance at 500 volts dc



Remove a sample of insulating liquid in accordance with ASTM D923



Test for Oil Quality, DGA and Furan 57

Conclusion • Diagnostic Testing provides a powerful tool for the complete and economic assessment of the transformer condition • There is nevertheless still a lack on how to integrate the information obtained by the on-line monitoring into the actions taken onto the service of the transformer • The supplementary information obtained by the off-line diagnostic after the detection of an abnormal condition is a worth-full information to be integrated into future on-line monitoring systems 58

29

Diagnostic Techniques for Condition Monitoring of Transformers

ARSEPE 2008

Young Zaidey bin Yang Ghazali Technical Expert (Transformer Performance & Diagnostic) Engineering Department TNB Distribution Division 1

Test Results Interpretation

2

1

1. Scoring








Scoring can be applied to test results to indicate acceptable condition level of transformers. Transformer condition indicator scoring is somewhat subjective, relying on transformer condition experts. Relative terms are used and compared to industry accepted levels; or to baseline or previous (acceptable) levels on this transformer; or to transformers of similar design, construction, or age operating in a similar environment.

3

2. Weighting Factors





Weighting factors is used to recognize that some condition indicators, affects the Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among transformer design and maintenance personnel with extensive experience.

4

2

3. Mitigating Factors








Every transformer is unique and, therefore cannot quantify all factors that affect individual transformer condition. It is important that the Transformer Condition Index arrived at be scrutinized by experts. Mitigating factors specific to the utility may determine the final Transformer Condition Index and the final decision on transformer replacement or rehabilitation. 5

1. Tan Delta for Main Tank This test is done on the transformer at regular interval under normal condition. This test results are considered for condition assessment of an in-service transformer. Results

Score

Action

%tan δ < 2

3

Normal. The monitoring frequency of 24 months can be maintained.

2 <% tan δ < 4

2

The monitoring frequency should be revised to 6 months.

4 <% tan δ < 5

1

The monitoring frequency should be revised to 3 months. Make arrangement for advanced electrical tests tests.

% tan δ > 5

0

Perform appropriate advanced electrical tests tests as recommended by the expert or internal inspection of main tank immediately. 6

3

2. Turns-Ratio Test This test is done on transformer at regular interval of 24 months under normal condition. This test results are considered for condition assessment of an in-service transformer. Results

Score

Action

% deviation < 0.2

3

Normal. The monitoring frequency of 24 months can be maintained.

0.2 <% deviation < 0.3

2

The monitoring frequency should be revised to 6 months.

0.3 <% deviation < 0.5

1

The monitoring frequency should be revised to 3 months. Make arrangement for advanced electrical tests tests.

% deviation >0.5

0

Perform appropriate advanced electrical tests tests as recommended by the expert or internal inspection of main tank and OLTC tank immediately. 7

3. Winding Resistance Test This test is done on transformer at regular interval of 24 months under normal condition. This test results are considered for condition assessment of an in-service transformer. Results

Score

Action

No more than 5% difference between phases or from factory tests

3

Normal. The monitoring frequency of 24 months can be maintained.

5 to 7% difference between phases or from factory tests

2

The monitoring frequency should be revised to 6 months.

7 to 10% difference between phases or from factory tests

1

The monitoring frequency should be revised to 3 months. Make arrangement for advanced electrical tests tests.

More than 10% difference between phases or from factory tests

0

Perform appropriate advanced electrical tests tests as recommended by the expert or internal inspection of main tank immediately.

8

4

4. Main Winding Insulation Resistance Test This test is done on transformer tail at regular interval of 24 months under normal condition. This test results are considered for condition assessment of an in-service transformer. Results

Score

Action

PI value ≥ 3.0

3

Normal. The monitoring periodicity of 24 months can be maintained.

1.0< PI value < 3.0

2

The monitoring periodicity should be revised to 6 months.

1.0< PI value < 1.5

1

The monitoring periodicity should be revised to 3 months. Make arrangement for advanced electrical tests tests.

PI value < 1.0

0

Perform appropriate advanced electrical tests tests as recommended by the expert or internal inspection of main tank immediately. 9

5(i). Oil Quality Test No

Criteria

Weightage

1

Moisture

0.3

2

BDV

0.1

3

Acidity

0.4

4

Power factor

0.2

10

5

5(ii).

Oil Quality Test

Moisture (ppm)

BDV (kV)

Acidity

IFT

Condition Indicator Score

0-10

>56

<0.01

< 0.010

10

11-15

51-55

0.02-0.04

0.01 – 0.03

9

16-20

46-50

0.05-0.06

0.031 – 0.05

8

21-25

41-45

0.07-0.09

0.051 – 0.07

7

26-30

36-40

0.1-0.12

0.071 – 0.09

6

31-35

30-35

0.13-0.16

0.091 – 0.1

5

36-40

25-29

0.17-0.20

0.11 – 0.2

4

41-45

20-24

0.21-0.24

0.21 – 0.3

3

46-50

15-19

0.25-0.3

0.31 – 0.5

2

>50

<15

>0.31

> 0.5

1 11

6. Fault Gases Limit Status

H2

C2H2

C2H4

C2H6

CH4

CO

TDCG

Condition 1

100

35

50

65

120

350

720

66 100

121 400

351 570

721 1915

Condition 2

101 – 700

36 - 45 51 - 100

Condition 3

701 – 1420

46 - 80

101 150

101 150

401 800

571 1400

1916 4000

Condition 4

> 1420

> 80

> 150

> 150

> 800

> 1400

> 4000

12

6

7. Key Gases Analysis Individual fault gases exceed limit

Per unit exceeded

Condition Indicator Score

Condition 1

0

10

Condition 2

<2

9

3-4

8

5-6

8

7

7

Condition 3

Condition 4

<2

6

3-4

5

5-6

5

7

4

<2

3

3-4

2

5-6

2

7

1 13

8. Furanic Analysis Furanic

Estimated DP

Condition Indicator Score

0-200

646-1300

10

201-400

560-645

9

401-600

510-559

8

601-800

475-509

7

801-1000

447-474

6

1001-1200

424-446

5

1201-1400

405-423

4

1401-1600

388-404

3

1601-1800

374-387

2

>1800

<373

1

14

7

9. Oil Quality, Key Gases & Furan Analysis Score This test is done on transformer at regular interval under normal condition. This test results are considered for condition assessment of an in-service transformer. Score

Action

7.5 ≤ Overall ranking ≤ 10

Results

3

Normal. The monitoring periodicity of 12 months can be maintained.

4.0 ≤ Overall ranking ≤ 7.5

2

The monitoring periodicity should be revised to 6 months.

1.5 ≤ Overall ranking ≤ 4.0

1

The monitoring periodicity should be revised to 3 months. Make arrangement for advanced electrical tests.

Overall ranking ≤ 1.5

0

Seek immediate advice from the expert to perform advanced electrical test or internal inspection 15

10. FRA Results

Score Adjustment

Action

No deviation Comparison between phases (using Crosscorrelation Index, CCI): •CCI at low freq zone >2.0 •CCI at mid freq zone > 1.0 •CCI at high freq zone > 0.6

Subtract 0

The monitoring periodicity of all basic electrical tests tests should be maintained at 6 months. Practice FRA test if necessary.

Minor deviation Comparison between phases (using Crosscorrelation Index): •1.0
Subtract 0.5

Retest the transformer for FRA after 6 months. The monitoring periodicity of all basic electrical tests tests should be maintained at 6 months.

Moderate deviation Comparison between phases (using Crosscorrelation Index): •0.6
Subtract 1.0

Retest the transformer for FRA after 3 months. Arrange for replacement of defective section(s).

Significant deviation Comparison between phases (using Crosscorrelation Index): •CCI at low freq zone <0.6

Subtract 1.5

Indicates serious problem requiring immediate evaluation, additional testing (if applicable) and immediate consultation with experts 16

8

11. FDS Score Adjustment

Action

Subtract 0

The monitoring periodicity of all basic electrical tests tests should be maintained at 6 months. Practice FDS test if necessary.

1.5 < % moisture in paper < 2

Subtract 0.5

Retest the transformer for FDS after 6 months. The monitoring periodicity of all basic electrical tests tests should be maintained at 6 months.

2 < % moisture in paper < 4

Subtract 1.0

Retest the transformer for FDS after 3 months. Arrange for replacement of defective section(s).

% moisture in paper > 4

Subtract 1.5

Indicates serious problem requiring immediate evaluation, additional testing (if applicable) and immediate consultation with experts

Results % moisture in paper < 1.5

17

12. PD Results*

Score Adjustment

Action

Amplitude 40-60 dB Energy 1-200 Duration 100 ms-2000 ms

Subtract 0

The monitoring periodicity of all basic electrical tests tests should be maintained at 6 months. Practice PD test if necessary.

Amplitude 60-70 dB Energy 200-300 Duration 200 ms-3000 ms

Subtract 0.5

Retest the transformer for PD after 6 months. The monitoring periodicity of all basic electrical tests tests should be maintained at 6 months.

Amplitude 70-80 dB Energy 200-400 Duration 3000 ms-4000 ms

Subtract 1.0

Retest the transformer for PD after 3 months. Arrange for replacement of defective section(s).

Amplitude 80-90 dB Energy 400-500 Duration 4000 ms-5000 ms

Subtract 1.5

Indicates serious problem requiring immediate evaluation, additional testing and immediate consultation with expert. Recommendation is to remove the transformer from service immediately. 18

9

19

10