Tanega Nasional Condition Monitoring Method

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Diagnostic Techniques for Diagnostic Techniques for Condition Monitoring Condition Monitoring

of Transformersof Transformers

Young Zaidey bin Yang GhazaliYoung Zaidey bin Yang GhazaliTechnical ExpertTechnical Expert

(Transformer Performance & Diagnostic)(Transformer Performance & Diagnostic)Engineering DepartmentEngineering Department

TNB Distribution DivisionTNB Distribution DivisionARSEPE 2008ARSEPE 2008

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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. 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.

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ASSET MANAGEMENT

Operate Operate Operate Operate

efficientlyefficientlyefficientlyefficiently

High PerformanceHigh PerformanceHigh PerformanceHigh Performance

Reasonable Reasonable Reasonable Reasonable

returnsreturnsreturnsreturns

Low CostLow CostLow CostLow Cost

• SAIFI, SAIDI

• Power quality

• Power availability

• Reduced Loss etc.

• Investment

• O&M

• Stocking etc.

Balancing cost, risk,

and performance in

the context of asset

full life cycle

Asset Management Mechanism

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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

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� 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

Maintenance Management

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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!

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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

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Health Index - Ranking

Condition Remnant Life (years) Probability of

failure

5 - 10Poor

Fair

Good

At EOL (<5 years)Bad

10 - 20

>20

High

Medium

Low

Very Low

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0

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0 3 5 10

MMeeaass uurraabbll ee ddee tt eerrii oorraatt iioonn bbuutt nnoo

ss iiggnnii ffii ccaanntt ii nnccrreeaass ee iinn PP(( ff))

SSii ggnnii ffii ccaanntt ddeett eerrii oorraatt iioonn ssmmaall ll

ii nnccrreeaass ee iinn PP(( ff))

SSeerrii oouuss ddeett eerrii oorraatt iioonn ssii ggnnii ffii ccaanntt

ii nnccrr ee aass ee iinn PP(( ff))

Probability of failure (Pf)

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)

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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)

Define

Assets

Define

EOL

Issues

Review

Condition

Assessment

Techniques

Data and

Information

Analysis

Formulation

and Population

of HI

HI to

Probability

of Failure

Change of

HI (PF) with

time

Documentation

Conclusions

Report

CONSEQUENCES

Phase 2

Define

Assets

Define

EOL

Issues

Review

Condition

Assessment

Techniques

Data and

Information

Analysis

Formulation

and Population

of HI

HI to

Probability

of Failure

Change of

HI (PF) with

time

Documentation

Conclusions

Report

CONSEQUENCES

Phase 2

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Transformer Design& Construction

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Transformer Design & Construction

Types of Transformers

� Core Type

� Shell Type

Oil-Immersed Type,

Dry Type

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Core Type Transformers

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Shell Type Transformers

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Typical Winding Connections

� Delta – Star

� Star - Delta

� Star – Star

� Delta – Delta

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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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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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• 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.

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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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.

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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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TERMINATION

� Both HV & LV is open bushing termination.

� Cable Box

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MANUFACTURING PROCESS FLOW CHART

Core Cutting

Core

Building

Tanking

Process

Despatch Finishing Testing

Paper Covering

High Voltage

Winding

Drying

Process

1. Rectangular copper

2. Foil Sheet

Fabrication

Vacuum & Oil

Filling

Low Voltage

Winding

Core Winding

Assembly

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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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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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Tapping & Tap Changers

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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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Type of Tap Changers

� On-Load Tap Changer (OLTC)

� Off Circuit Tap Changer (OCTC)

Tap Changer Mounting

� Internal (In-tank)

� External (Side mounted)

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OLTC Technology

� Oil Type OLTC

� Vacuum Type OLTC (Vacutap)

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OLTC Main Components

� Tap Selector

� Diverter Switch

� Selector Switch

� Change-over selector

� Transition Impedance

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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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Gas & Oil Actuated Relays (Buchholz)

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Temperature Indicators

� Winding HV & LV

� Top Oil

Fans Control

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Oil Level Indicators

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Other Ancillary Equipment

� Conservator Tank

� Cooling System/Radiators

� Bushings

� Cable Box

� Oil Valves

� Thermometer Pockets

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Transformer Insulating Oil

& Paper Diagnostics

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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

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1. Oil Quality Test

� Chemical Properties

� Moisture Content

� Acidity

� Corrosive Sulphur

� Oxidation Stability

� Sludge Sediment

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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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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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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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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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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


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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

• H20

• CO

• CO2

• Organic acids

Glycosidic

bonds broken

and glucose

rings opened

Generates the

following:

H20 CO CO2

H

O

OH

Heat


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Three most common degradation factors of cellulose:

Oxidative

1. Presence of oxygen promotes oxidation

2. Glycosidic bond weakens

3. Causes scission to the cellulose chain

4. By-products include H20

Hydrolytic

1. Presence of water and acids

2. Glycosidic bond exposed to slicing

3. Causes scission to the cellulose chain

4. By-products include free glucose

Glycosidic

bonds

weakened

and

moisture

produced

CH2OH

COOH COOH

CHO

O2

Free glucose

produced

HO OH

CH2OH

H20 or acids


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Degradation By-Products

1. It can be observed that by-products related to paper degradation

can include the followings:

• CO

• CO2

• H2O

• 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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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.


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� 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

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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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� 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 photo-degradation

� 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

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Dark Brown

Bottle

500 mL

Valve

Adaptor

Plastic

tube Cap

Transformer

Seal

Waste

Vessel

Filled

Sample

bottle

Use correct vessel (good cap and seal)

Sufficient sample

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Valve

Adaptor

Plastic

tubeSyringeTransformer

Waste

Vessel

Sufficient sample

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� 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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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)


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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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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

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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.

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� 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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� 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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� 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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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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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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IEEE Limit

� Hydrogen (H2) 100 ppm

� Oxygen (O2) N/A

� Nitrogen (N2) N/A

� Carbon Monoxide (CO) 350

� Methane (CH4) 120

� Carbon Dioxide (CO2) 2500

� Ethylene (C2H4) 50

� Ethane (C2H6) 65

� Acetylene (C2H2) 35

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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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� 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 CH4 / H2 C2 H4 / C2H6

< 0.1 0 1 0

0.1 -<1.0 1 0 0

1.0 - <=3.0 1 2 1

> 3.0 2 2 2

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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



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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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

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� CO2/ CO ratio indicates cellulose degradation

CO2 / CO ratio Condition of Cellulose

< 3 Severe Arcing & Short circuit damage

3 -<5 Indicates concern

5 - <=11 Normal

> 11 Indicates damage due to general

overheating

According to IEEE C57.104 the normal value is 7

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Exercise (Oil Condition)

Transformer Gas Analysis

Component ppm in oil

HYDROGEN (H2) 10

OXYGEN (O2) 26200

NITROGEN (N2) 48500

CARBON MONOXIDE (CO) 41

METHANE (CH4) 5

CARBON DIOXIDE (CO2) 570

ETHYLENE (C2H4) 2

ETHANE (C2H6) 2

ACETYLENE (C2H2) 1

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HYDROGEN (H2) 720

OXYGEN & ARGON (O2 + A) 17000

NITROGEN (N2) 45400


METHANE (CH4) 1310


ETHYLENE (C2H4) 5200

ETHANE (C2H6) 1810

ACETYLENE (C2H2) 256

Exercise (Oil Condition)

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HYDROGEN (H2) 105

OXYGEN & ARGON (O2) 18000

NITROGEN (N2) 33400


METHANE (CH4) 400

CARBON DIOXIDE (CO2) 12,100

ETHYLENE (C2H4) 260

ETHANE (C2H6) 28

ACETYLENE (C2H2) 52

ppb in oil

2FAL 195

Exercise (Paper Condition)

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HYDROGEN (H2) 103

OXYGEN & ARGON (O2 + A) 16762

NITROGEN (N2) 20458


METHANE (CH4) 814


ETHYLENE (C2H4) 109

ETHANE (C2H6) 75

ACETYLENE (C2H2) 118

ppb in oil

2FAL 225

Exercise (Oil + Paper Condition)

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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


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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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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


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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.


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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.


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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


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• 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 by-

products 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)


50

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)

26

51

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

52

LTC – OIL ANALYSIS

27

53

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

54

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

1

1






2

Transformer Basic On-Site & Off Line Diagnostic Testing

2

3

Electrical Tests

1. Basic Electrical Tests

� Insulation Resistance• Traditional Polarization Index (PI) test

to detect moisture content

� Tan Delta• 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

Insulation Condition

Assessment

4

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)

3

5

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

On-site Testing

6

� These on-site tests are performed individually or in

combination :

� Before energizing a new equipment as a

commissioning test

� After maintenance

� After network alteration

On-site Testing

4

7

Damaging Factors of Insulation

8

Fig 4-4

5

9

105

130

155

180

220

Class A Class B Class F Class H Class C100

125

150

175

200

225

250

Degrees C

entigrade

Insulation Classes by Degrees Centigrade

Class SClass R

240 240+

Class N

200

Thermal Withstandibility of Insulation Medium According to Classes

10


� Insulation resistance test (a)

� Insulation current test (b)

� Power factor (c)

� DC voltage withstand (d)

� AC voltage with-stand (e)

6

11


� 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

12

Basic Electrical TestsInsulation 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

7

13

Basic Electrical TestsPolarization Index

Interpretation of Polarization Index (PI) Measurements

PI Value Interpretation

> 4.0 Healthy

4.0 – 2.0 OK

2.0 – 1.5 Marginal Pass

1.5 – 1.0 Deteriorated condition

< 1.0 Failure

14

Basic Electrical Tests

8

15

Insulation Resistance Test

16


Volume Current

Insulation Resistance

Tester

Surface leakage

current

9

17


Capacitive

Current

Dielectric

Absorption

Current

Conduction

Current

Total

current

Time

µA

18


10

19

Guard Connections

20

3 Terminal Insulation Resistance Tester

11

21

Spot Any Difference? Why?

22

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

12

23

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

24

Spot Reading

13

25

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

26

Conversion Factors For Converting

Insulation Resistance Test Temperature to 20°°°°C

Temperature Multiplier

°°°°C °°°°F

Apparatus

Containing Immersed

Oil Insulations

Apparatus

Containing Solid

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

14

27

28

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

15

29

Polarization Index

30

INSULATION 60/30 SECOND RATIO 10/1 MINUTE RATIO

CONDITION Dielectric Absorption 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

Interpretation

16

31

Step Voltage Test

32

Step Voltage Test

17

33

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.


34

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.


18

35

Power Factor Test

Power Factor = cos θ = ir / it

900 – θ = δ

Dissipation Factor = tan δ = ir / ic

36

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

19

37

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

38

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

20

39

40

Power Factor Test Set up

21

41

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

42

Temperature correction factors for the power factor of power transformer windings

22

43

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%

Power Factor of Some Common Materials

44

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

23

45

46

Insulation Current Test

HVDC

µA

Applied Voltage (% of Maximum Voltage)

20 40 60 80 100

20

40

60

80

100

120

HealthyIndicates

Concern

24

47

48

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, high-voltage 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

25

49

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

50

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

26

51

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

52

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 preselectedrate (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

27

53

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

54

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.


28

55

Turns Ratio test


56

Turns Ratio test


29

57

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.


58

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 = Resistance at the factory reference temperature (found in the transformer

manual)

Rm = Resistance you actually measured

Ts = Factory reference temperature (usually 75 °C)

Tm = Temperature at which you took the measurements

Tk = A constant for the particular metal the winding is made from:

• 234.5 °C for copper

• 225 °C for aluminum

30

59

Basic Electrical TestsWinding Resistance test

Four terminal testing set up

V

I

P1 P2C1 C2

Measured Resistance (R) = V/I

1

1






2

Transformer Advanced Off-Line Diagnostic Testing

2

3

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.

4


� 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

3

5


� 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.

Recovery Voltage Measurement (RVM)

6

Advanced Diagnostic TestingRecovery Voltage Measurement (RVM)

4

7


Recovery Voltage Measurement (RVM) - TETTEX 5461

8


� 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.

Polarization & Depolarization Current (PDC)

5

9


� 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 moisturelevel 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.


10


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


6

11


� In the FDS technique, a known sinusoidal voltage is applied and measured together with the current passing across the insulationmaterial.

� 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.

Frequency Dielectric Spectroscopy Measurement (FDS)

12


� The advantage of an analysis of the dissipation factor frequencyas 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.


7

13


� Example on how moisture affects the dissipation factor of kraftpaper at 20°C


14


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


8

15


PROGRAMMA IDA 200


16

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

9

17


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.

18


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

10

19


What Test can be Done?

Frequency response analysis (FRA) using a

low voltage AC wave of varying frequency to

identify changes in natural resonance

20


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.

11

21


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 variesin 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.

22


12

23


24


� Test Equipment

13

25


26


14

27


28


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

15

29


30


� 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)]

16

31


32


17

33


What are the ANALYZING TECHNIQUES?

� Signature

� Difference

� Transfer Function

� Statistical

FRA Signatures are analyzed based on 3 band methods

34


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

18

35


SIGNATURE TECHNIQUE

36


SIGNATURE TECHNIQUE

19

37


SIGNATURE TECHNIQUE

38


DIFFERENCE TECHNIQUE

(Phase A before)

20

39


DIFFERENCE TECHNIQUE

(Phase A after)

40


DIFFERENCE TECHNIQUEThis technique can analyze the windings phase by phase, which is not

possible in the signature technique

21

41


� 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

42


Different Different Same Same Peer

Different Same Same Same Sister

Same Same Same Same Twin

S/S

LOCATION

MANU-

FACTURER

MVA

RATING

KV RATIOCATEGORY

22

43

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

44

Partial Discharge� PD Classification

23

45

Partial Discharge� PD Classification

46

Partial Discharge� Occurrence of PD – Inception Voltage

24

47

Partial Discharge� Occurrence of PD – Inception Voltage

48

Partial Discharge

� Occurrence & Recognition

� Detection

� Measurement

� Location

� Evaluation

25

49

Partial Discharge

� Evaluation

� Amplitude in dB

� Energy or charge in pC

� Duration in ms

50

Partial Discharge� On-line acoustic PD Detection - Physical Acoustic DISP-24

26

51


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

52


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

27

53


� 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

54

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

28

55

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!

56

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

29

57

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

58

• 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

Conclusion

1

1






2

Test Results Interpretation

2

3

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.

4

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.

3

5

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.

6

1. Tan Delta for Main Tank

Perform appropriate advanced

electrical tests tests as recommended

by the expert or internal inspection of

main tank immediately.

0% tan δ > 5

The monitoring frequency should be

revised to 3 months. Make arrangement

for advanced electrical tests tests.

14 <% tan δ < 5


revised to 6 months.

22 <% tan δ < 4

Normal. The monitoring frequency of

24 months can be maintained.

3%tan δ < 2

ActionScoreResults

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.

4

7

2. Turns-Ratio Test

Perform appropriate advanced

electrical tests tests as recommended

by the expert or internal inspection of

main tank and OLTC tank

immediately.

0% deviation >0.5


revised to 3 months. Make

arrangement for advanced electrical

tests tests.

10.3 <% deviation < 0.5



20.2 <% deviation < 0.3

Normal. The monitoring frequency of


3% deviation < 0.2

ActionScoreResults

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.

8

3. Winding Resistance Test

Perform appropriate

advanced electrical tests tests

as recommended by the

expert or internal inspection

of main tank immediately.

0More than 10% difference

between phases or from

factory tests

The monitoring frequency

should be revised to 3

months. Make arrangement

for advanced electrical tests

tests.

17 to 10% difference between

phases or from factory tests

The monitoring frequency

should be revised to 6

months.

25 to 7% difference between

phases or from factory tests

Normal. The monitoring

frequency of 24 months can

be maintained.

3No more than 5% difference

between phases or from

factory tests

ActionScoreResults

This test is done on transformer at regular interval of 24 months under normal condition. This


5

9

4. Main Winding Insulation Resistance Test

Perform appropriate advanced electrical tests

tests as recommended by the expert or

internal inspection of main tank

immediately.

0PI value < 1.0

The monitoring periodicity should be revised

to 3 months. Make arrangement for

advanced electrical tests tests.

11.0< PI value < 1.5

The monitoring periodicity should be revised

to 6 months.

21.0< PI value < 3.0

Normal. The monitoring periodicity of 24

months can be maintained.

3PI value ≥ 3.0

ActionScoreResults

This test is done on transformer tail at regular interval of 24 months under normal condition. This


10

5(i). Oil Quality Test

0.2

0.4

0.1

0.3

Weightage

Power factor4

Acidity3

BDV2

Moisture1

CriteriaNo

6

11

5(ii). Oil Quality Test

> 0.5

0.31 – 0.5

0.21 – 0.3

0.11 – 0.2

0.091 – 0.1

0.071 – 0.09

0.051 – 0.07

0.031 – 0.05

0.01 – 0.03

< 0.010

IFT

>0.31

0.25-0.3

0.21-0.24

0.17-0.20

0.13-0.16

0.1-0.12

0.07-0.09

0.05-0.06

0.02-0.04

<0.01

Acidity

<15

15-19

20-24

25-29

30-35

36-40

41-45

46-50

51-55

>56

BDV

(kV)

1>50

246-50

341-45

436-40

531-35

626-30

721-25

816-20

911-15

100-10

Condition Indicator

Score

Moisture

(ppm)

12

6. Fault Gases Limit

> 4000> 1400> 800> 150> 150> 80> 1420Condition 4

1916 -

4000

571 -

1400

401 -

800

101 -

150

101 -

150

46 - 80701 –

1420

Condition 3

721 -

1915

351 -

570

121 -

400

66 -

100

51 - 10036 - 45101 –

700

Condition 2

720350120655035100Condition 1

TDCGCOCH4C2H6C2H4C2H2H2Status

7

13

7. Key Gases Analysis

1

2

2

3

4

5

5

6

7

8

8

9

10

Condition

Indicator Score

7

5-6

3-4

<2Condition 4

7

5-6

3-4

<2Condition 3

7

5-6

3-4

<2Condition 2

0Condition 1

Per unit exceededIndividual fault gases exceed

limit

14

8. Furanic Analysis

1<373>1800

2374-3871601-1800

3388-4041401-1600

4405-4231201-1400

5424-4461001-1200

6447-474801-1000

7475-509601-800

8510-559401-600

9560-645201-400

10646-13000-200

Condition Indicator ScoreEstimated DPFuranic

8

15

9. Oil Quality, Key Gases & Furan Analysis Score

Seek immediate advice from the expert

to perform advanced electrical test or

internal inspection

0Overall ranking ≤ 1.5

The monitoring periodicity should be

revised to 3 months. Make

arrangement for advanced electrical

tests.

11.5 ≤ Overall ranking ≤ 4.0

The monitoring periodicity should be


24.0 ≤ Overall ranking ≤ 7.5

Normal. The monitoring periodicity of


37.5 ≤ Overall ranking ≤ 10

ActionScoreResults

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.

16

10. FRA

Indicates serious problem requiring immediate

evaluation, additional testing (if applicable)

and immediate consultation with experts

Subtract 1.5Significant deviation

Comparison between phases (using Cross-

correlation Index):

•CCI at low freq zone <0.6

Retest the transformer for FRA after 3

months. Arrange for replacement of defective

section(s).

Subtract 1.0Moderate deviation


correlation Index):

•0.6<CCI at low freq zone <1.0

•CCI at mid freq zone < 0.6

Retest the transformer for FRA after 6

months. The monitoring periodicity of all

basic electrical tests tests should be

maintained at 6 months.

Subtract 0.5Minor deviation


correlation Index):

•1.0<CCI at low freq zone <2.0

•0.6<CCI at mid freq zone < 1.0

The monitoring periodicity of all basic

electrical tests tests should be maintained at 6

months. Practice FRA test if necessary.

Subtract 0No deviation


correlation Index, CCI):

•CCI at low freq zone >2.0

•CCI at mid freq zone > 1.0

•CCI at high freq zone > 0.6

ActionScore

Adjustment

Results

9

17

11. FDS

Indicates serious problem requiring

immediate evaluation, additional

testing (if applicable) and immediate

consultation with experts

Subtract 1.5% moisture in paper > 4

Retest the transformer for FDS after 3

months. Arrange for replacement of

defective section(s).

Subtract 1.02 < % moisture in paper < 4

Retest the transformer for FDS after 6

months. The monitoring periodicity of

all basic electrical tests tests should be

maintained at 6 months.

Subtract 0.51.5 < % moisture in paper < 2

The monitoring periodicity of all basic

electrical tests tests should be

maintained at 6 months. Practice FDS

test if necessary.

Subtract 0% moisture in paper < 1.5

ActionScore

AdjustmentResults

18

12. PD

Indicates serious problem requiring

immediate evaluation, additional

testing and immediate consultation

with expert. Recommendation is to

remove the transformer from service

immediately.

Subtract 1.5Amplitude 80-90 dB

Energy 400-500

Duration 4000 ms-5000 ms

Retest the transformer for PD after 3

months. Arrange for replacement of

defective section(s).


Energy 200-400


Retest the transformer for PD after 6

months. The monitoring periodicity

of all basic electrical tests tests should

be maintained at 6 months.


Energy 200-300


The monitoring periodicity of all

basic electrical tests tests should be

maintained at 6 months. Practice PD

test if necessary.

Subtract 0Amplitude 40-60 dB

Energy 1-200


ActionScore

AdjustmentResults*

10

19

Documents

Tanega Nasional Condition Monitoring Method