diagnostic techniques for condition monitoring of transformers

8/13/2019 Diagnostic Techniques for Condition Monitoring of Transformers

1/121

1

( & )( & )

00 00

2

1.

Electrical distribution equipment is generallydesigned for a certain economic service life.

Equipment life is dependent on operatingenvironment, maintenance program and the qualityof the original manufacture and installation.

Beyond this service life period they are not expectedto render their services up to expectation withdesired efficiency.


2/121

3

1. Generally due to poor quality of raw material,

workmanship and manufacturing techniques or dueto frequent electrical, mechanical and thermalstresses during the operation, many equipment failmuch earlier than their expected economic life span.

The concept of simple replacement of failed powerequipments in the system either before or after theireconomic service life, is no more valid in the presentscenario of financial constraints.

1.

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 ofthe stated tasks of the electrical power systemengineers. For electrical utilities this implies forexample to fulfill requirements from customers andauthorities on reliability in power supply at a minimaltotal cost.

The main goal is therefore to reach a cost effectivesolution using available resources which is capturedby the concept ofAsset Management.


3/121

ASSETMANAGEMENT

OperateOperateOperateOperate

efficientlyefficientlyefficientlyefficiently

High PerformanceHigh PerformanceHigh PerformanceHigh Performance

ReasonableReasonableReasonableReasonable

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

&


4/121

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

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 allowdiagnosing the integrity of power system equipment

to optimize the maintenance effort thereby ensuring

maximum availability and reliability


5/121

10

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!

11

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)


6/121

12

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!

13

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


7/121

1

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

1

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 toengineers


8/121

1

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

1

Condition Remnant Life (years) Probability of

failure

5 - 10Poor

Fair

Good

At EOL (20

High

Medium

Low

Very Low

10

0


9/121

1

0 3 5 10

MMeeaassuurraabblleeddeetteerriioorraattiioonnbbuuttnnoo

ssiiggnniiffiiccaannttiinnccrreeaasseeiinnPP((ff))

SSiiggnniiffiiccaannttddeetteerriioorraattiioonnssmmaallll

iinnccrreeaasseeiinnPP((ff))

SSeerriioouussddeetteerriioorraattiioonnssiiggnniiffiiccaa

nntt

iinnccrreeaasseeiinnPP((ff))

ProbabilityoffailurePf)

Health Index

1

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 bemapped on later to evaluate overall risk

(Criticality, load, obsolescence etc)


10/121

20

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

21

1 ( )

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


11/121

( & )( & )

200 200

&


12/121

&

Types of Transformers

Core Type

Shell Type

Oil-Immersed Type,

Dry Type

&

Core Type Transformers


13/121

&

Shell Type Transformers

&

Typical Winding Connections

Delta Star

Star - Delta

Star Star

Delta Delta


14/121

&

Other Winding Connections

Zig Zag Connections

Tertiary Windings

Double Secondary

Scott (T-T) Connections

Autotransformers

Earthing Transformers

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.


15/121

Grain Oriented Electrical Steel

Type M5 (0.3mm), M4 (0.27mm) and ZDKH

(0.23mm)

Are designed to meet three fundamental requirement :

1. Electrical

2. Mechanical

3. Thermal


16/121

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.

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.


17/121

& 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 ratedcurrent.

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.


18/121

Both HV & LV is open bushing termination.

Cable Box

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


19/121

&

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

&

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


20/121

&

Tapping & Tap Changers

&

Tapping & Tap Changers Functions

To compensate for changes in the appliedvoltage on bulk supply

To compensate for regulation within thetransformer & maintain the output voltageconstant

To assist in the control of system VArs flows

To allow for compensation for factors notaccurately known at the time of planning

To allow for future changes in system conditions


21/121

& Type of Tap Changers

On-Load Tap Changer (OLTC)

Off Circuit Tap Changer (OCTC)

Tap Changer Mounting

Internal (In-tank)

External (Side mounted)

&

OLTC Technology

Oil Type OLTC

Vacuum Type OLTC (Vacutap)


22/121

& OLTC Main Components

Tap Selector

Diverter Switch

Selector Switch

Change-over selector

Transition Impedance

&

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


23/121

Pressure Relief Device

Gas & Oil Actuated Relays (Buchholz)


24/121

Temperature Indicators

Winding HV & LV

Top Oil

Fans Control

Oil Level Indicators


25/121

Other Ancillary Equipment

Conservator Tank

Cooling System/Radiators

Bushings

Cable Box

Oil Valves

Thermometer Pockets


26/121

( & )( & )

200 200

Transformer Insulating Oil

& Paper Diagnostics


27/121

& &

1. Oil Quality Test

Physical Properties

Visual Appearance

Colour

Flash Point

Viscosity

Density

Pour Point

IFT

Particle Count

& &

1. Oil Quality Test

Chemical Properties

Moisture Content

Acidity

Corrosive Sulphur

Oxidation Stability

Sludge Sediment


28/121

& &

1. Oil Quality Test

Electrical Properties

Breakdown Voltage

Dissipation Power Factor

2. DGA

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


29/121

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

SECONDARY STRESSES

1. Factors that can influence the ageing rate when primary

stresses are applied

2. Simply known asAgeing 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


30/121

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

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


31/121

Three most common degradation factors of cellulose:

Thermal

1. When exposed to heat up to 220C, the glycosidic bond tend to

break and open the glucose molecule rings

2. By-products:

Free glucose

H20

CO

CO2

Organic acids

Glycosidicbonds broken

and glucose

rings opened

Generates the

following:

H20 CO CO2

H

O

OH

Heat

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 glucoseproduced

HO OH

CH2OH

H20 or acids


32/121

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

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.


33/121

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

Use a clean glass syringe/beaker (provided by thelaboratory) and follow the proper sampling procedure

ASTM D923 & D3613 (IEC 60475 & IEC 60567)

Interpret the quantified results to help determine therelative health of the transformer, offer clues to the origin

of potential problems and develop a strategy to avoidcatastrophic failure IEEE C57.106

Important factors to be considered prior to taking asample:

1. Sample Containers

2. Sampling Technique

3. Weather condition

4. Sample storage and transport


34/121

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 beforesending to the laboratory for analysis

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


35/121

Valve

Adaptor

Plastic

tubeSyringeTransformer

Waste

Vessel

Sufficient sample

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


36/121

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)

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)


37/121

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

Other Oil Quality Tests

Specific Gravity

Viscosity

Power Factor

Resistivity

Flash Point

Visual PCB Content

Inhibitor Content


38/121

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

Color (D 1500) The color of a new oil is generallyaccepted as an index of the degree of refinement. Foroils in service, an increasing or high color number is anindication of contamination, deterioration, or both.

Dielectric Breakdown (D 877 / D 1816 / IEC 156) It is ameasure of the ability of an oil to withstand electricalstress at power frequencies without failure. A low value

for the dielectric-breakdown voltage generally serves toindicate the presence of contaminants such as water,dirt, or other conducting particles in the oil.

Neutralization Number, NN (D 664)A used oil having a highneutralization number indicates that theoil is either oxidizedor contaminated with materials such as varnish, paint, or otherforeign matter.

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


39/121

Index = IFT/NN. This index provides a more sensitive andreliable guide in determining the remaining useful life of atransformer oil. A Index below 100 indicates that theoil issignificantly oxidized and that theoil needs to be replaced inthe near future.

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)


40/121


41/121

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


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


42/121

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


Ratio Method is used for fault analyzing, not for fault detection.

Ratio Method Ratios

Rogers 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.


43/121

Rogers Ratio comparison methods look at pairs of gases, anddevelop a coding system to help define potential fault conditions

Rogers Ratio Code

C2H2 / C2H4 CH4 / H2 C2 H4 / C2H6

< 0.1 0 1 0

0.1 -


44/121

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

CO2/ CO ratio indicates cellulose degradation

CO2 / CO ratio Condition of Cellulose

< 3 Severe Arcing & Short circuit damage

3 -


45/121

( )

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) 2ACETYLENE (C2H2) 1



HYDROGEN (H2) 720

OXYGEN & ARGON (O2 + A) 17000

NITROGEN (N2) 45400


METHANE (CH4) 1310


ETHYLENE (C2H4) 5200

ETHANE (C2H6) 1810

ACETYLENE (C2H2) 256

( )


46/121

Transformer Gas AnalysisComponent ppm in oil

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) 52ppb in oil

2FAL 195

( )



HYDROGEN (H2) 103

OXYGEN & ARGON (O2 + A) 16762

NITROGEN (N2) 20458


METHANE (CH4) 814


ETHYLENE (C2H4) 109ETHANE (C2H6) 75

ACETYLENE (C2H2) 118

ppb in oil

2FAL 225

( + )


47/121

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

2FAL limits (ppb in oil):

58 292 Normal Aging

654 2021 Accelerated Aging

2374 3277 Excessive Aging

3851 4524 High Risk of Failure


48/121

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 & Rogers/IEEE Ratio

DGA Criterion (paper) Individual concentrations of CO2 & CO in

ppm & CO2/CO Ratio

Furan Criterion 2FAL concentration in ppb & others if detected

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.


49/121

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.

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


50/121

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)

By plotting the relative percentages of methane, ethylene

and acetylene onto a special triangular coordinatesystem, a graphical output of the likely cause of gassingis generated.

The causes are categorized as follows.

D1 Discharges of low energy

D2 Discharges of high energy

T1 Thermal faults < 300C

T2 Thermal faults 300C to 700C

T3 - Thermal faults > 700C

DT Mixture of thermal and electrical faults

PD Partial discharge (No samples indicated this typeof fault)


51/121

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 Duvals

triangle approach to find the cause


52/121


53/121

( & )( & )

2008 2008

Transformer Basic On-Site &Off Line Diagnostic Testing


54/121

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

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)


55/121

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

These on-site tests are performed individually or in

combination :

Before energizing a new equipment as a

commissioning test

After maintenance After network alteration


56/121


57/121

105

130

155

180

220

Class A Class B Class F Class H Class C100

125

150

175

200

225

250

De

greesCentigrade

Insulation Classes by Degrees Centigrade

Class SClass R

240 240+

Class N

200

Insulation resistance test (a)

Insulation current test (b)

Power factor (c)

DC voltage withstand (d)

AC voltage with-stand (e)


58/121

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

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


59/121

Polarization 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


60/121

Volume Current

Insulation Resistance

Tester

Surface leakagecurrent


61/121

Capacitive

Current

DielectricAbsorption

Current

Conduction

Current

Total

current

Time

A


62/121

3


63/121

Effect of Previous Charge

Effect of Temperature

Effect of Moisture

Effect of Age and Curing


64/121

Hot resistance test - at least 4 hours after shutdown from full-loadoperation, 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 insulationresistance 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


65/121

Dry type insulation 40C ambient

Liquid type insulation 20C ambient

Insulating materials have negative resistance

characteristics

Spot test reading must be corrected to a base

temperature

Conversion Factors For ConvertingInsulation 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


66/121

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


67/121

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


68/121


69/121

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.

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.


70/121

Power Factor = cos = ir / it

900 =

Dissipation Factor = tan = ir / ic

For small , Cos (90 ) = tan

tan = ir / ic

ic = CV

ir = CV tan

Power loss (dielectric loss) = V ir= CV2 tan watt

Dielectric loss is dependent on voltage and frequency Variation of tan with voltage is an important diagnostic method

and will be part of this course


71/121

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 orthickness

Increase in dielectric loss may accelerate insulationdeterioration because of the increased heating

Insulation power factor increases directly with temperature

Temperature corrections to a base temperature must bemade, usually to 20 degree C

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 theequipment being tested

Much simpler and less expensive tester is also availablewhich applies about 80 volts to the equipment being

tested but not sufficiently shielded against inducedvoltages


72/121


73/121

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


74/121

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%

High Voltage DC/AC Test

The voltage is slowly raised in discrete steps, allowingthe leakage current to stabilize for a predetermined time

A plot of the leakage current as a function of test voltageyields information on the condition of the insulation

If the curve is a straight line, it indicates good conditionof the cable

If the current begins to increase at a rapid rate, indicatesdegradation / defects in the cable insulation

After the completion of the test, the cable under test isgrounded for sufficient time to discharge the voltagebuild up due to effects of absorption currents


75/121

HVDC

A

Applied Voltage (% of Maximum Voltage)

20 40 60 80 100

20

40

60

80

100

120

HealthyIndicates

Concern


76/121

, /

Very little supply power is required to operate the DCtest 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 timesthe rms ac breakdown voltage to 2.5 times the rms acpuncture voltage

Cases have indicated that on winding insulation withsome deterioration, the application of overpotential testsmay cause further deterioration, even though theinsulation may not puncture


77/121

The machine winding should be grounded for at least 1hour 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 isconvenient to do so

If the separation of phases is difficult then separation isneeded once for the benchmark tests, and thereafter thephases may be tested together until deviation from normalis detected

The voltage should be raised abruptly to the first voltagelevel with the start of timing for the test.

The ratio of the 1-minute to the l0-minute reading ofinsulation current will afford useful indication ofpolarization index

This gives the test engineer an idea of insulation drynessearly in the test

The test schedules are arranged to include a minimum ofthree points up to and including the maximum voltage


78/121

If the insulation microampere versus voltage plots arestraight lines, the test may be continued to the maximumtest voltages

The quality of the insulation may be judged by theposition of any curvature or knee in the plot of insulationcurrent versus test voltage

If curvature or knee appears, the test should be stopped

Upon completion of the dc, high- voltage test, thewinding should be discharged through the specialdischarge resistor usually provided with the test set

The winding may be solidly grounded when the voltagehas 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

,

The ramped technique of insulation testing uses aprogrammable dc, high-voltage test set andautomatically ramps the high voltage at a preselectedrate (usually 1 kV/min)

Insulation current versus applied voltage is plotted on anx-y recorder providing continuous observation andanalysis of insulation current response as the testprogresses

The principal advantages of the ramp test over theconventional step method is the elimination of the humanfactor which makes it much more accurate andrepeatable


79/121

/

High Voltage DC/AC

Less capable of revealing voids or cavities left inside theaccessories

Useful in detecting the defects related to contaminationalong the interface between the different components ofthe insulation system

Voltage applied is usually three to four times the nominalphase-to earth voltage for 15 minutes or more

This is destructive test

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.


80/121

Turns Ratio test

Turns Ratio test


81/121

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.

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 75C which has become the most

commonly used temperature.

Rs = Resistance at the factory reference temperature (found in t he 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


82/121

Four terminal testing set up

V

I

P1 P2C1 C2

Measured Resistance (R) = V/I


83/121

( & )( & )

00 00

Transformer Advanced Off-LineDiagnostic Testing


84/121

Most of the techniques, whether chemical or electricalmethods, or destructive or non-destructive methods, onlyprovide partial information about the state of theinsulation condition of power transformers.

More advanced condition monitoring or conditionassessment techniques have been developed and arenow starting to come into more general use.

They have been developed in response to the need fornew materials assessment methods.

However, in some advanced diagnotics tools are still in

the developmental stage, either in the technicaldevelopment or, more likely, in the methods of analysisand interpretation of the test data.

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 dielectricresponse of insulating materials to the application of electricfields Conductivity, Polarization & Dielectric Response


85/121

When a dielectric material with polar molecular structure issubjected to a DC voltage, the electric dipoles are oriented withinthe material in response to the applied electric field.

There is thus a polarization charge induced by the dipolemovement and realignment and this will effectively give a voltageacross the capacitance. When the dielectric is short circuited, thestored charge in the dielectric capacitance is dissipated by acurrent discharge with a time constant determined by theeffective 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 thedielectric. This measured voltage is known as the recoveryvoltage.

()

()


86/121

()

A dielectric material becomes polarized when exposed to an electric field.Polarization is proportional to the intensity of the electric field and bymeasuring the current, polarization process can be observed. The currentdensity is the sum of the conduction current and the displacement current.

When the insulating material is exposed to a step voltage, polarizationcurrent is obtained. If the step voltage is removed, a reverse polarity currentknown as depolarization current is obtained. These two currents can beused to determine the response function and the conductivity of thedielectric material.

The PDC is a DC testing method which determining the polarizationspectrum in time constant domain between 10e-3 10e3 seconds in whichthe interface polarization phenomena of long time constant are active. The

range of polarization is strongly influenced by the absorbed moisture andthe deterioration by product content of the paper insulation. It applies a500V step of DC voltage to the high or low voltage winding insulations oftransformers. Time of voltage application is typically up to 10000 seconds.Both the polarization and depolarization times are performed for the sameperiod of time.

& ()


87/121

The polarization current pulse has a peak magnitude, a finalsteady state level and a time constant and duration that aredetermined by the quality of the oil including both the moisturelevel and the electrical conductivity. In genera the electricalconductivity affects the peak current in the first 100 seconds orso of the current pulse. The moisture in the insulation affects thelonger term polarization current level after about 1000 seconds.[Figure 8.6]

Polarization and depolarization current measurement methodgives general information about the state of insulation condition.This technique is proved to be a useful testing method inpredicting of moisture and development of ageing phenomena.

& ()

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

& ()


88/121

In the FDS technique, a known sinusoidal voltage is applied andmeasured 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 memoryeffects.

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

By dividing the current by the voltage and comparing the phasedifference, both the capacitance and the loss at the particularfrequency and amplitude can be calculated.

()

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 determinethe dielectric loss, at medium frequencies the oil conductivity is thedominant factor and the lower frequency range is dominated by thepressboard dielectric loss.

()


89/121

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

()

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

()


90/121

PROGRAMMA IDA 200 ()

How do you know whether you can energize A

TRANSFORMER after transportation to site or

after a protection trip?

Check Mechanical Integrity


91/121

When does Mechanical Integrity matter?

Re-location

Short Circuit

Lightning

Tap-changer fault

Transportation damage can occur if the clamping andrestraints are inadequate; such damage may lead to coreand winding movement.

Radial buckling or axial deformation may occur due toexcessive short circuit forces while in service.

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


92/121

What Test can be Done?

Frequency response analysis (FRA) using a

low voltage AC wave of varying frequency to

identify changes in natural resonance

Why FRA?

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

Impulse Technique: This technique requires high sampling rates andhigh resolution to obtain a valid measurement. The applied impulse does

not produce constant energy across the specified frequency, which cancause poor repeatability that is influenced by the non-linear properties ofthe test specimen.


93/121

What is FRA ?

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

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

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

Changes in frequency response as measured by FRA

techniques may indicate a physical change inside thetransformer, the cause of which then needs to be identified andinvestigated.


94/121

Test Equipment


95/121


96/121

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


97/121

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

The resulting amplitude of the measurement can be expressedas,

H (dB) = 20 log10 [(ZS)/(ZS+ZT)]

The resulting phase is defined by

H () = tan-1 [(ZS)/(ZS+ZT)]


98/121


99/121

What are the ANALYZING TECHNIQUES?

Signature

Difference

Transfer Function

Statistical

FRA Signatures are analyzed based on 3 bandmethods

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 theinter-connection and test

system


100/121

SIGNATURE TECHNIQUE

SIGNATURE TECHNIQUE


101/121

SIGNATURE TECHNIQUE

DIFFERENCE TECHNIQUE

(Phase A before)


102/121

DIFFERENCE TECHNIQUE

(Phase A after)

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

possible in the signature technique


103/121

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 dueto constraints of outages

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

DifferentDifferentSameSamePeer

DifferentSameSameSameSister

SameSameSameSameTwin

S/S

LOCATION

MANU-

FACTURER

MVA

RATING

KV RATIOCATEGORY


104/121

What is PD Electric discharge that do not completelybridge the electrodes

Discharge magnitude is usually small but can causeprogressive 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

PD Classification


105/121

PD Classification

Occurrence of PD Inception Voltage


106/121

Occurrence of PD Inception Voltage

Occurrence & Recognition

Detection

Measurement

Location

Evaluation


107/121

Evaluation

Amplitude in dB

Energy or charge in pC

Duration in ms

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


108/121

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

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 theunit prior to commissioning


109/121

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 ofaccuracy

( ) Electrical Tests

Perform insulation-resistance tests winding-to-windingand 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 thedesignated tap position

Measure core insulation-resistance at 500 volts dc ifcore is insulated


110/121

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!

( ) Visual inspection

Inspect physical condition for evidence of moisture and corona

Verify operation of cooling fans

Verify operation of temperature and level indicators, pressurerelief 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 usingone of the following methods:

1. Use of low-resistance ohmmeter

2. Perform thermographic survey


111/121

( )

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 eachwinding-to-ground

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

Remove a sample of insulating liquid in accordance with ASTMD923

Test for Oil Quality, DGA and Furan

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-linediagnostic after the detection of an abnormal condition is a

worth-full information to be integrated into future on-line

monitoring systems


112/121

( & )( & )

2008 2008


113/121

1. Scoring can be applied to test results to indicate

acceptable condition level of transformers.

Transformer condition indicator scoring is somewhatsubjective, relying on transformer condition experts.

Relative terms are used and compared to industryaccepted levels; or to baseline or previous(acceptable) levels on this transformer; or totransformers of similar design, construction, or age

operating in a similar environment.

2.

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.


114/121

3. 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.

1.

Perform appropriate advanced

electrical tests tests as recommended

by the expert or internal inspection of

main tank immediately.

0% tan > 5

The monitoring frequency should be

revised to 3 months. Make arrangement

for advanced electrical tests tests.

14


115/121

2.

Perform appropriate advanced

electrical tests tests as recommendedby the expert or internal inspection of

main tank and OLTC tank

immediately.

0% deviation >0.5

The monitoring frequency should be

revised to 3 months. Make

arrangement for advanced electrical

tests tests.

10.3


116/121

4.

Perform appropriate advanced electrical teststests 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

test results are considered for condition assessment of an in-service transformer.

5().

0.2

0.4

0.1

0.3

Weightage

Power factor4

Acidity3

BDV2

Moisture1

CriteriaNo


117/121

5().

> 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

50

246-50

341-45

436-40

531-35

626-30

721-25

816-20

911-15

100-10

Condition Indicator

Score

Moisture

(ppm)

6.

> 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


118/121

7.

1

2

23

4

5

5

6

7

8

8

9

10

ConditionIndicator Score

7

5-6

3-4


119/121

9. , &

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

revised to 6 months.

24.0 Overall ranking 7.5

Normal. The monitoring periodicity of

12 months can be maintained.

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.

10.

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


120/121

11.

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

12.

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*


121/121

diagnostic techniques for condition monitoring of transformers

Documents