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Why Transformers Fail

By

Hongzhi DingRichard Heywood

John LapworthSimon Ryder

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WHY TRANSFORMERS FAIL

Hongzhi Ding, Richard Heywood(hding@doble.com) (rheywood@doble.com)

John Lapworth and Simon Ryder(jlapworth@doble.com) (sryder@doble.com )

Doble PowerTest Ltd.5 Weyvern Park, Peasmarsh, Guildford, Surrey, GU3 1NA, United Kingdom

Abstract

Knowledge from the tear down investigation of faults and failures in power transformers is ofvital importance in understanding the results from the dissolved gas analysis (DGA) andelectrical condition assessment measurements and preventing further incidents. This technicalarticle discusses with examples the common failure modes observed in the scrapped powertransformers. The review will also outline what we can do that is effective in preventingpower transformer failures, with examples, too, showing how the developing failures couldbe saved through continually Transformer Asset Health Review by effective DGA analysiscombining with effective condition assessment.

Introduction

While assisting in the investigation of unexpected transformer failures is an important aspectof the work, there are many examples of transformer component defects and faults that weredetected well before an unexpected failure could occur, i.e. during routine dissolved gasanalysis (DGA), electrical condition assessment and maintenance operations. Many in-service power transformers are now required to operate beyond their original design life,mainly as a consequence of missing-match between the large number of ageing transformersand the limited resources available to source replacements for them; and also because theseageing transformers are still in reasonably good working condition although their conditionand ability to carry peak loads are usually unknown. As part of the transformer asset healthreview and life extension program, over the years Doble PowerTest have records of detailedforensic teardown inspection of more than hundred large power transformers. This involveswitnessing the process of scrapping and making a thorough inspection of each component toassess its condition. This teardown of power transformers has enabled the conditionassessment of components that would not normally be addressed during routine maintenancebecause of their inaccessibility. Knowledge of the causes of transformer in-service failures,together with assessments made during strip downs of transformers removed due to high riskexposure, have given significant insight into modes of deterioration/failure in particulardesign groups. This has been translated firstly into a diagnostic strategy for assessing thecondition of power transformers nearing the end of their life and then integrated into assethealth and asset risk reviews and finally utilized in aged transformer replacement planning.

Doble PowerTest’s experiences thus far reveal most transformer failures are not due to oldage, but localised damage or ageing due to some limitations in design and manufacture,application and maintenance [1-4]. Sometimes a power transformer does fail without any

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warning notice. In most cases, however, the symptoms of developing fault and failure can bedetected, prevented or eliminated.

Transformer Design and Construction

As electrical devices that transfer energy from one electrical circuit to another byelectromagnetic coupling without moving parts, power transformers are normally regarded ashighly reliable assets because they are designed and constructed by time-proven technologyand materials. It is generally believed that the transformer designed and built at the turn of the20th century was already a mature product as the essential features of the device remainunchanged to date, although the transformer continues to evolve [5, 6].

The principles that govern the function of all electrical transformers are the same regardlessof size or application [5]. The typical power transformer is submerged in mineral oil forinsulation and cooling and is sealed in an airtight metallic tank. Low- and high- voltagepower lines lead to and from the coils through bushings. Inside the transformer tank, core andcoils are packed close together to minimise electrical losses and material costs. The mineraloil coolant circulates by convection through external radiators. Figure 1 shows three windingassembly on core viewed from the HV side and after the tank being removed.

Figure 1Three winding assemblies on core, HV side view

The essential parameters that characterise the ideal transformer depend, to a large extent, onthe properties of the core. The properties that are critically important in transformer corematerials are permeability, saturation, resistivity and hysteresis loss. It is generally believedthat it is in the core that the most significant advances in power transformer design andconstruction have been made [6].

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The performance of power transformers depends on dielectric insulation and cooling systems.These two systems are intimately related, because it is the amount of heat both the core andwinding conductors generate that determines the permanence and durability of the insulation,and the dielectric insulation system itself is designed to service to carry off some of the heat.

It is vital that the insulation utilised in a power transformer must be able to separate thedifferent circuits; isolate the winding core and outer case from the circuits; providemechanical support for the electrical coils and withstand the mechanical forces imposed bypower system surges and short circuits. Generally Kraft paper has been utilised for windingconductor insulation, high density pressboard for inter-winding and inter-phase insulation,and crêpe paper for lead insulation. The critical properties that determine the functional lifeof dielectric oil/paper insulation are chemical purity, thermal stability, mechanical anddielectric strengths.

What Causes a Power Transformer to Fail?

It is generally believed that failure occurs when a transformer component or structure is nolonger able to withstand the stresses imposed on it during operation.

During the course of its life, the power transformer as a whole has been suffering the impactof thermal, mechanical, chemical, electrical and electromagnetic stresses during normal andtransient loading conditions. The condition of the transformer deteriorates gradually rightfrom the start, resulting in

Reduction in dielectric strength (i.e., the ability to withstand lightening and switchingimpulses);

Reduction in mechanical strength (i.e., the ability to withstand any through faults); Reduction in thermal integrity of the current carrying circuit (i.e., the ability to

withstand overloads); Reduction in electromagnetic integrity (i.e., the ability to transfer electromagnetic

energy at specified conditions including over-excitation and overloading).

A failure ultimately occurs when the withstand strength of the transformer with respect to oneof the above key properties is exceeded by operating stresses.

A useful way of thinking about failure of a power transformer could be illustrated in Figure 2,as proposed by CIGRE WG 12.18 [7, 8]. In its early life of service, the power transformer hasa sufficient spare safety margin between the various types of transient service stress andcapability. Here “strength” and “stress” are used generically to cover any kind of incident-thermal, mechanical or electrical events. However, after a period of general ageing this maynot be the case. At some point in the deterioration process, probably long before the usefullife is run out, one or more parts of the transformer may well have changed just enough oreven failed such that the transformer no longer performs as required, e. g. even if a transient,such as an overvoltage or close-up short circuit has been successfully withstood failure couldoccur at the next transient.

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Mechanisms of failure that are involved in a large transformer are often complex. Typicaltransformer functional failure mechanisms are summarised in Table 1, as per the CIGREWG12.18. Note this is a functional failure model only for transformer core and coil assembly,not including on load tap changers (OLTC) and bushings.

It is also important to distinguish the fault and the failure. A fault is mainly attributed topermanent and irreversible change in transformer condition. The risk of a failure occurrencedepends not only on the stage of the fault developing but also the transformer functionalcomponent involved. The failure could be repairable on site, depending on the type of fault aswell as the severity of the failure.

Table 1Transformer functional failure model [7,8]

System, Component Possible Defect Fault and Failure ModeDielectric system

Major insulation Minor insulation Leads insulation Electrostatic screens

Abnormal oil ageing Abnormal paper ageing Partial discharges Excessive water Oil contamination Surface contamination

Flashover due to:

Excessive paper ageing Destructive partial discharges Creeping discharges Localised surface tracking

Mechanical system Clamping Windings Leads support

Loosing winding clamping Loosing winding

Failure of solid insulation due to:

Failure of leads support Winding displacement (radial,

axial, twisting)Electromagnetic circuit Core Windings Structure insulation Clamping structure Magnetic shields Grounding circuit

Circulating current Leakage flux Ageing laminations Loosing core clamping Floating potential Short-circuit (open circuit) in

grounding circuit

Excessive gassing due to:

General overheating Localised overheating Arcing/sparking discharges Short-circuited turns in winding

conductors

Current-carrying circuit Leads Winding conductors

Bad joint(s) Bad contacts Contact deterioration

Short-circuit due to:

Localised overheating

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Increasing AgeNew Old

Insulation Strength

IncidentsInsulationStress

InsulationSpareMargin

Reducing Strength withtime and after incidents

Failure

Increasing AgeNew Old

Insulation Strength

IncidentsInsulationStress

InsulationSpareMargin

Reducing Strength withtime and after incidents

Failure

Figure 2A conceptual failure model proposed by CIGRE WG 12.18 [7,8]

From our records and case histories data, failures of power transformers are commonlyassociated with localised stress concentrations (faults), which can occur for several reasonsincluding:

Design and manufacture weakness, e.g. poor design of conductor sizing andtranspositions, poor joints, poor stress shield and shunts, poor design of clamping,inadequate local cooling, high leakage flux, poor workmanship, etc.;

The microstructure of the material utilised may be defective right from the start, e.g.containing micro-voids, micro-cracks etc.;

Corrosive attack of the material, e.g. sulphur corrosion on paper and conductor can alsogenerate a local stress concentration.

Weakness in transformer design, construction and materials could be covered by low loading.However, increasing loading and extended periods of in-service usage will uncover theseweaknesses.

Common Failure Modes

Failure modes of large power transformers are not always straightforward. But purely froman assumption of the failure experienced in a large power transformer, most transformerfailures can be classified into either one or a combination of more than one of the followingthree modes:

Breakdown of insulation as a whole, due to severe solid insulation ageing; Breakdown of insulation by part, due to premature ageing by localised high temperature

overheating; Mechanical failure of windings.

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Common among many of the transformer failure modes is a shorted turn. The shorted turnwas developed as a result of breakdown of the solid insulation which causes windingtemperature shoot-up. The breakdown of solid insulation could be due to the natural wear ofinsulation or repeated overloading or cooling system deficiency, which often result in severeageing of winding insulation. This type of failure (shorted turns without any prior warning orobvious system cause) is a typical ‘end of life’ failure mode. If the transformer runsabnormally hot and/or develops less than its normal out voltage, one can safely assume thepossibility of shorted turns.

Electrical breakdown is a common failure mode for power transformers, too. The electricalbreakdown could be developed by a number of reasons such as ageing of insulation,excessive moisture content, deformed windings etc. Moisture reduces the dielectric strengthof insulation and can promote the occurrence of surface creeping discharges on thepressboard barriers and lead to a flashover. Deformed windings indicate not only a high levelof force that may have broken or abraded the winding conductor insulation, but also areduction in electrical clearance. This mechanical failure of windings will then manifest itselfas an electrical breakdown which actually causes failure of transformer.

Poor design and overheating are very much interrelated and make for high failure modes. Inthe bottom end, lack of cooling causes either general or localised high temperatureoverheating, resulting in rapid insulation deterioration and damage progression. Breakdownof insulation between the core and main tank may lead to circulating currents in thecore/frame/tank and result in local overheating. Circulating current in the tank can producehotspots in the tank and across gasket joints, resulting in partial discharges emanation fromthe ground potential surfaces of the tank and parts mounted on the tank. Note localoverheating in current carrying circuit, if not extremely severe, often will not itself causedirect failure of the transformer, but will reduce the mechanical strength of the insulation sothat when the transformer is subjected to a system fault close to the terminals, it will then fail[5]. This is similarly true for winding movement.

Poor design and loose clamping are very much interrelated and make for high failure modes,too. The most well-known design problem with loose clamping is arcing/sparking fault at theloose clamping bolts, which compromises the mechanical strength of the transformer andmakes diagnosis of dielectric faults using DGA difficult. The arcing/sparking discharges alsolead to deterioration of the oil and the production of fine carbon, which compromises thedielectric integrity of the transformer.

Three Case Studies on Transformer Failures

Case 1: Transformer Failure Due to Shorted Turns

In April 2009, a 30 year old 750MVA 400/275/13kV autotransformer tripped on Buchholz.Analysis of a subsequent DGA sample from the Buchholz clearly indicated a fault. Electricalprotection had shown unusual waveforms on the middle phase immediately before the trip.Condition assessment tests after the trip are shown in Table 2 (turns ratios) and Table 3(winding resistances). Measured ratio for the middle phase differs from expected value bythree times more than allowed (0.5%), indicating lost turns, and lower than expected value

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indicates the fault is in series winding. Winding resistance measurements confirm fault in themiddle series winding, which was unlikely to be unlikely to be economically repairable.

During the scrapping, after the wraps of the middle phase series winding were removed, theshorted turns in the 2nd and 3rd discs of series winding was found and these seemed to beparticularly severe. Figure 3 shows a picture of failure by shorted turns. There was extensiveloss of conductor and conductor insulation in the upper part of the series winding, which isunlikely to be economically repairable.

Table 2Turns ratios measurement on a 750MVA autotransformer after Buchholz trip

Measured RatiosExpected ratio Applied HV-N voltage, kVA phase B phase C phase

0.3 1.435 1.4521.455 12.0 1.456 1.455

Notes: Measurements made at 0.3 and 12 kV, using Doble M4000 Insulation Analyser and Doble TTRcapacitor.

Table 3Winding resistances on a 750MVA autotransformer after Buchholz trip

Winding A phase B phase C phaseSeries (400 to 275 kV) 0.1783 0.3296 0.1778

Common (275 kV to neutral) 0.5236 0.5222 0.5236Notes: Measurements made at 5A using Tinsley 5896 Transformer Microhmeter.According to WTI’s, transformer was at 15°C.

Figure 3Failure of transformer by shorted turns

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Figure 4Comparison in colour of conductors in A/red phase series winding top disc: from left to right

is outermost strand, middle strand and innermost strand

The worst degree of polymerisation (DP) measurement obtained was 142/146 (average 144)from the middle strand of top disc of the middle phase series winding. The next worst resultwas 151/161 (average 156) from the middle strand of top disc of A/red phase series winding.The DP results on paper samples showed that apparently the insulation condition of the serieswinding had reached the end of its life. The DP analysis on paper samples also showed thatthe winding hotspot was located in the middle strand of the upper part of series winding.Figure 4 shows a visual comparison of conductors taken from A/red phase series winding topdisc, from left to right is the outermost strand, middle strand and innermost strand,respectively. Note the severe discoloration of the middle strand conductor which implies notonly the location of series winding hotspot, but also the inadequate cooling design in theseries winding.

The learning point from this case study is that the short turn was developed as a result ofsevere winding conductor insulation ageing which was partly a function of the age of thetransformer and the loading to which it had been subjected. The thermal design of the serieswinding, however, led to localised overheating of certain areas, including the point of failure.

Case 2: Transformer Failure Due to a Flashover

In the middle of 2006, a 42 year old 30MVA 132/11kV station transformer failed releasingoil to the ground from the busting discs. It was believed the transformer might have beensubjected to through fault before its failure.

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Figure 5Failure of transformer by a flashover in the main tank

Figure 6Close-up of the middle phase winding bottom end-blocks

from HV side (left) and LV side (right)

During the strip down it was found that the failure actually involved one severearcing/sparking fault in the main tank, which was located between the bare copper stripconnected to the middle phase LV winding line end and the middle phase top steel clampingplatform in the LV side, where the arcing seemed to be particularly severe so that both thebare copper strip and the corner of the steel clamping platform had been damaged. Figure 5shows a picture of failure by flashover in the main tank.

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Further inspection of the core and windings during scrapping found direct evidence ofmechanical deformation of all windings from three phases particularly in middle phase.Figure 6 shows the severe displacement of the middle phase winding bottom end-blocks.Note that the missing end-blocks on the LV side had been found on the tank floor. It wastherefore believed that all windings from three phases particularly the middle phase windingshad been subjected to very significant circumferential forces and had significantly twistedand relaxed as a result. It was further thought that the relaxed winding clamping had causedthe downward movement of the middle phase LV winding line end, which reduced electricalclearance between the bare copper strip and the steel clamping platform corner andeventually caused a flashover in main tank.

The learning point from this case study is that the flashover was developed as a result ofreduced electrical clearance which was due to winding mechanical deformation caused byshort circuits, and poor design of having no physical support to the middle phase LV windingline lead that connected to the bus-bar.

Case 3: Transformer Failure Due to Axial Collapse of Winding

In late 2004 the decision was made to scrap a 50 year old 120MVA 275/132/11kVautotransformer which had suffered a serious tap changer fault.

The fault was first noted during planned maintenance, and it appeared that the middle/Bphase tap selector became misaligned by one tap compared with the A and C phase tapselectors. After the transformer was returned to service, the voltage control schemeeventually sent the transformer to the end of the tap range. At the end position the B phasediverter was required to switch the entire tap winding, rather than one tap step as it wasdesigned to. This resulted in serious damage to the B phase tap changer and large currentsflowing in B phase of the transformer. Fault investigation tests were made on the transformerand results of additional winding capacitance and power factor measurements are listed inTable 4. The results from B phase clearly indicated a serious problem. The large reduction incapacitance between the series and common and tap windings seemed to indicate axialcollapse of the tap winding.

During the strip down it was found that the transformer failed due to axial collapse of the Bphase tap winding, following a fault in the B phase tap changer. This would have beenimpractical to repair.

Figure 7 shows a picture of failure by axial collapse of the tap winding. Note there had beenno serious design defects or unusual design features found during the scrapping. Thetransformer seemed to have no faults other than with the B phase tap winding. The degree ofpolymerisation analysis on paper samples were in the age 450-750, which indicates littleageing and considerable useful life remaining.

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Table 4Fault investigation on a 120MVA autotransformer

Figure 7Collapsed B phase tap winding

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What Can We Do That Is Effective in Preventing Transformer Failures in OurSubstation?

Why transformers fail is easy to understand. However, getting more transformer engineers todo their part in preventing failures is the hard part. So, what can we do that is effective inpreventing transformer failures in our substations?

The simple answer is that a power transformer must be replaced when it no longer meets therequirement of system reliability and before it fails [4]. In order to be able to replace thetransformer before it fails, it is considered necessary to have a transformer asset health reviewmethodology to analysis and prevent in-service failure [1-3]. This involves using informationfrom a wide range of sources, including oil tests, on-line and off-line condition assessmenttests and visual inspections. However, knowledge of transformer designs and of theirstrengths and weaknesses is essential to understanding the other information. Given the ageof many of the transformers, such information is now in many cases only obtainable throughwitnessing the scrapping of transformers.

The following three case examples illustrate how developing failures could be managed andeven saved by effective DGA analysis combining with effective condition assessment tests.

Case 4: Developing Failure Due to Loose Clamping and Leakage Flux

In early 2009 a 43 year old 240MVA 275/132/13kV autotransformer was taken out of theservice as per the planned replacement. This transformer had been suffering from the knownloose clamping for many years, and the strip down inspection of a sister transformer one yearbefore it was removed from the system had provided valuable information about the likelycondition of this transformer believed to be significantly in risk of failure.

During the scrapping it was found that approximately one third of the clamping bolts showedsigns of having been loose in the past. Certain clamping bolt bosses showed signs either ofspark erosion or of hammering (elongated slots). Overall the winding clamping was in a verypoor condition and looks much worse than what was seen from the scrapped sistertransformer a year before. The loose clamping had resulted in severe arcing/sparkingdischarges developing at a large number of the clamping bolts/bosses, producing fine carboncontamination everywhere particularly on the top frame surfaces. The loose clamping hadalso resulted in relaxed coil assembly leading to the development of partial discharges andfine carbon contaminations produced inside the windings. Figure 8 close-up shows the severeloosing clamping fault. Note how one of the missing clamping bolts had become embeddedin the insulation above the tertiary winding, as shown clearly in the picture on the right handside. Here it was electrically shielded by steel clamping ring. The same picture also shows abent clamping bolt.

During scrapping the possibly burned electrostatic shields were also noted and those seemedto be extremely severe. Figure 9 shows a picture of the copper foil having become severelyoverheated by the leakage flux, resulting in damage to the bottom end clamping platforms aswell as to the adjacent insulation. This was not particularly apparent from dissolved gasresults.

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In conclusion, the findings of the severe loose clamping plus the burned electrostatic shieldsprovided conclusive evidence to confirm that this transformer had reached the end of its lifeand certainly was not capable of continuing service.

Figure 8Loose clamping faults from LV side (left) and A phase end (right)

Figure 9The burned electrostatic shields: general view (left) and close up (right)

Case 5: Developing Failure Due to Localised Overheating

In early 2009 the decision was made to scrap a 1996-made 240MVA 400/132kV (no tertiary)autotransformer, believed to be significantly in risk of failure from localised high temperatureoverheating in current carrying circuit.

This transformer had been suffering from a thermal fault in the main tank before it wasremoved from service. Fitting a frame earth resistor had not stopped the development of thefault. It was believed, therefore, that the thermal fault had not been caused by a circulatingcurrent in the core/frame/tank.

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The dissolved gas levels in the main tank had been typical of the larger transformerpopulation until a year before the transformer was removed from the system. There was thena rapid rise in the ethylene level, accompanied by rises in the hydrogen, methane and ethanelevels. The last sample before the transformer was removed from service contained 324 ppmof ethylene, 302 ppm of methane, 144 ppm of hydrogen and 123 ppm of ethane. Thedissolved gas signature clearly indicates a serious thermal fault in the main tank whichdeveloped through 2008. The rate of deterioration seems to have increased during the year.The carbon monoxide level had been less than 500 ppm for much of the service years but theratio of carbon dioxide to carbon monoxide varied between 2 and 45. These both seemed tosuggest little to moderate solid insulation ageing only. However, the relative proportions ofgases suggested a localised high temperature overheating fault involving solid insulation(relatively high hydrogen and methane, low acetylene, ethylene/ethane ratio < 4).

Based on winding resistance measurements, it was suspected that there was likely a bad jointin the C phase LV current carrying circuit, but internal investigation inspected all joints andconnections around the C phase LV terminal and there was no clear indication of anyproblem. It was finally concluded that the fault must be inside the C phase common winding.

During scrapping, after the C phase common winding was pushed out, it was found that alljoints were shown to be healthy and there was no clear indication of any problem. Figure 10shows a picture of a developing failure point within the common winding due to localisedoverheating. The localised high temperature thermal fault had caused extensive loss ofconductors and insulations but had not led to a short-circuited turn developing yet.

Figure 10Developing failure point within common winding due to local overheating

The learning point from this case study is that this developing failure does not seem to havebeen caused or exacerbated by the design of the transformer, although the root cause of the

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thermal fault was not actually known. It could, however, be caused by any one of thefollowing reasons: microscopic conductor damage from new; weak joint in conductor; slackdamping/fretting which resulted in the loss of insulation; and a system transient.

Case 6: Developing Failure in a Transformer Saved by DGA Analysis

This is the case of a 750MVA 400/275/13kV autotransformer built in 1967 and currently stillin service. Over the last few years this transformer has developed severe thermal fault twicebut all saved by effective DGA analysis.

In late 2005, the transformer was removed from service because of rapidly increasingdissolved gas results which indicated a bare metal fault inside the main tank (high ethylene asthe dominant gas). The following electrical tests, including winding resistance measurements,pointed to a winding joint problem associated with the tertiary winding, most likely involvingconnections to the tertiary bushings. An internal inspection revealed faulty joints in theinternal connection between one of the main tank tertiary bus-bars and the left hand tertiaryterminal (3C2) in the tertiary loading box at the A phase end of the tank. This was originallya multi-part single aluminium bar, whereas the 3B2 and 3A2 leads were double copper bus-bars. The fault appeared to be due to a poorly bolted connection in the cranked part of theconnection where it left the tertiary loading box to rise up towards the top of the main tank toconnect to the tertiary bus-bars. As part of the repair a second parallel copper bus-bar wasadded to the 3C2 lead.

Unfortunately, after the transformer was returned to service and tertiary loading (by a shuntreactor) resumed, further gassing was observed. Analysis of tertiary winding resistancemeasurements made after the 2005 repair suggested another high resistance joint problemwith the 3A2 connection. During a planned outage in 2008 these resistance measurementswere repeated and confirmed. After the oil was drained a visual inspection took place and alarge carbon deposit was found at the base of 3A2 bushing on the joint between the flexibleand the bushing.

Figure 11Developing failure point due to local overheating: bus-bar joint in tertiary connections (left)

and bushing joint (right)

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Figure 11 shows a developing failure point in the main tank due to local overheating. Notethe left picture shows an overheated bus-bar joint in tertiary connections and the right pictureshows overheated bushing joint.

Figure 12Tertiary winding connections in the studied 750MVA autotransformer

Table 5Tertiary winding resistance measurements before and after repair

Measured resistance, mΩ

Measurement Before repair11/6/08

21.6ºC, 41% RH

After repair3/7/08

17.4ºC, 56% RH

After repair17/7/08

16ºC, 89% RH

(1) TA to 3A2 11.023 8.211 7.802(2) TA to 3B2 15.732 15.874 15.836(3) 3A2 to 3B2 10.783 7.624 7.745(4) 3B2 to 3C2 8.085 8.032 8.010(5) 3C2 to 3A2 18.650 15.354 15.590(6) TC to 3B2 8.124 8.112 8.046(7) TC to 3C2 0.4281 0.4273 0.3722

Notes: Measurements made with Tinsley resistance meter

After the repair the winding resistances were measured again, and these confirmed that therewere no further tertiary resistance anomalies. Note that in Figure 12, the tertiary windingconnections in this transformer are somewhat unusual in that all three corners of the tertiaryare brought out to the A phase end of the transformer for tertiary loading, while the originalarrangement of bringing out one corner (TA and TC leads) for closing and earthing externallyis retained out at the C phase end. Table 5 summarises the tertiary winding resistancemeasurements before and after repair.

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The learning point from this case study is that developing failures due to bad joints in maintanks of transformers could be saved just by effective DGA analysis combining with effectivecondition assessment tests.

Conclusions

Fault and failure investigations on power transformer components have an important role inimproving reliability and managing the risk of transformer failure. The identification of theprimary cause of failure and the subsequent analysis enable recommendations for correctiveaction to be made that hopefully will prevent similar failures from occurring in the future.

Most unexpected power transformer failures happen because of maintenance oversights andover loadings. Couple your understanding of how power transformer components aresupposed to function with a careful look at tell-tale damage, and you can prevent recurrences.

When design error and/or weaknesses developing over time are uncovered, enhancedmonitoring/investigation on sister units built by same manufacturer will help in preventingfuture failures and therefore aid in managing the risk of unexpected failure.

References

[1] R. Heywood, J. Lapworth, L. Hall, and Z. Richardson, “Transformer lifetimeperformance: Managing the risks”, 3rd IEE International Conference on Reliability ofTransmission and Distribution Networks, London; February 2005.

[2] R. Heywood and A. Wilson, “Managing reliability risks-Ongoing use of ageing systempower transformers”, Doble Israel Conference 2007.

[3] A. Wilson, R. Heywood and Z. Richardson, “The life time of power transformers”,Insucon 2006, 24-26 May 2006, Birmingham, UK.

[4] H. Ding and S. Ryder, “When to replace aged transformers? Experiences from forensictear downs and research”, Euro TechCon 2008. Liverpool, 18-20 November 2008.

[5] M. J. Heathcote, J & P Transformer Book, 13th edition, Elsevier 2007.

[6] J. W. Coltman, “The transformer”, IEEE Industry Applications Magazine, pp. 8-12,Jan/Feb 2002.

[7] CIGRÉ Working Group 12.18, “Guide for life management techniques for powertransformers”, CIGRÉ Brochure No. 227, 20 January 2003.

[8] CIGRE WG 12.18 “Life management of transformers, draft interim report”, July 1999.