IEEE Review of Condition Assessment of Power Transformers in Service (Powertech Labs)

8/2/2019 IEEE Review of Condition Assessment of Power Transformers in Service (Powertech Labs)

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F T uA R A c EI LR

Review of Condition Assessmentof Power Transformers in ServiceK e y W o r d s : T r a n s fo rm e r in s u la t io n , c o n d it io n a s s e s s m e n t , f a i lu r e s ta t is t ic s , o i l t e s t in g , d is s o lv e d g a sa n a ly s is , p a r t ia l d is c h a rg e ( P O ) , p o w e r fa c to r , d ie le c tr ic s p e c t r o s co p y , r e c o ve ry v o lt a g e ,w i n d in g m o v e m e n t d e te c t io n

Transformers are required throughout modern in-terconnected power systems. The size of thesetransformers ranges from as low as a few kVA toover a few hundred MVA, with replacement costs rangingfrom a few hundred dollars tomillions of dollars. Powertransformers are usually very reliable, with a 20-35 yeardesign life. In practice, the life of a transformer can be aslong as 60 years with appropriate maintenance. How-ever, the in-service failure of a transformer is potentiallydangerous to utility personnel through explosions andfire, potentially damaging to the environment through oilleakage, is costly to repair or replace, and may result insignificant loss of revenue. In a large public power utility,the number of transformers in the subtransmission andtransmission network (excluding the lower-voltage dis-tribution network) can be from a few hundred to overone thousand (69 kV to 500 kV).

As transformers age, their internal condition degrades,which increases the risk of failure. Failures are usually trig-gered by severe conditions, such as lightning strikes, switch-ing transients, short-circuits, or other incidents. When thetransformer is new, it has sufficient electrical and mechani-cal strength to withstand unusual system conditions. Astransformers age, their insulation strength can degrade tothe point that they cannot withstand system events such asshort-circuit faults or transient overvoltages.

To prevent these failures and to maintain transformers ingood operating condition is a very important issue forutilities. Traditionally, routine preventative maintenanceprograms combined with regular testing were used. Withderegulation, it has become increasingly necessary to reducemaintenance costs and equipment inventories. This has ledto reductions in routine maintenance. The need to reducecosts has also resulted in reductions in spare transformer ca-pacity and increases in average loading. There is also a trendin the industry to move from traditional time-based mainte-nance programs to condition-based maintenance. These

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M. Wang and A.J. VandermaarPowertech Labs Inc.Surrey, B.c., CanadaK.D. SrivastavaThe University of British ColumbiaVancouver, Canada

There is an increasing need for bettern on in tru siv e d ia gnos tic a nd monito rin gtools to assess the internal condition oftransformers.

changes occur at a time when the average age of the trans-formers in service is increasing and approaching the end ofnominal design life.

The change to condition-based maintenance has resultedin the reduction, or even elimination, of routine time-basedmaintenance. Instead of doing maintenance at a regular in-terval, maintenance is only carried out if the condition ofthe equipment requires it. Hence, there is an increasingneed for better nonintrusive diagnostic and monitoringtools to assess the internal condition of the transformers. Ifthere is a problem, the transformer can then be repaired orreplaced before it fails.

Many testing and monitoring techniques have been usedby utilities. This article reviews the existing monitoring anddiagnostic methods and future trends.

Power Transformer Failures and ProblemsTransformer failure can occur as a result of different

causes and conditions. Generally, transformer failurescan be defined as follows [1]-[2]:

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T a b l e I.T yp ic a l C a u se s o f T ra n s fo rm e r F a ilu re sI n t e r n a l E x t e r n a l

I n s u la t io n d e te r io r a t io n L ig h tn in g s t r ik e sL o ss o f w in d in g c la m p in g S y s te m s w itc h in g o p e ra tio n sO v e r 1 l e a t i n g S y s te m o v er lo a dO x y g e n S y s te m fa u ~ s ( s h o r t c i r c u it )M o i s t u r eS o lid c o nta m in a tio n in th e in s u la tin g o ilP a r t i a l d i s c h a r g eD e s i g n & m a n u f a c tu r e d e fe c tsW i n d in g r e so n a n c e

any forced outage due to transformer damage in service(e.g., winding damage, tap-changer failure)

trouble that requires removal of the transformer for re-turn to a repair facility,or which requires extensive fieldrepair (e.g., excessive gas production, high moisture lev-els).

Transformer failures can be broadly categorized as elec-trical, mechanical, or thermal. The cause of a failure canbe internal or external. Table I lists typical causes of fail-ures. In addition to failures in the main tank, failures canalso occur in the bushings, in the tap changers, or in thetransformer accessories.

The failure pattern of transformers follows a "bath-tub" curve, as shown in Fig. 1.The first part of the curve isfailure due to infant mortality; the second part of thecurve is the constant failure rate; and the last part of thecurve is failure due to old age.

In addition to normal aging, a transformer may de-velop a fault that results in faster-than-normal aging, re-sulting in a higher probability of failure.

Power transformers have proven to be reliable in nor-mal operation with a global failure rate of 1 - 2 percentper year. The large investment in generating capacity af-ter the Second World War that continued into the early1970s has resulted in a transformer population that, intheory, is fast approaching the end of life [3]. The end oflife of a transformer is typically defined as the loss of me-chanical strength of the solid insulation in the windings.These power transformers are at the last stage of the"bathtub" curve. They are expected to have an increasingfailure rate in the next few years.

A survey [4] reports that the main causes (51 percentof transformer failures in a five-year period) were due tothe following problems:

moisture, contamination and aging which caused thetransformer's internal dielectric strength to decrease,

damage to the winding or decompression of the wind-ing under short circuit forces, or

November/December 2002 - Vol. 18, No.6

damage to the transformer bushings caused by loss of di-electric strength of the internal insulation.

An American utility reported four single-phase EHVautotransformer failures due to transformer winding res-onance [5]. All of the failures involved the breakdown ofthe no-load tap changers immediately after the transmis-sion system was energized. The utility also experiencedthree 25/765 kY, 500 MVA generator step-up trans-former failures and two 765 kY, 80 MVA reserve auxil-iary transformer failures; all of the failures were dielectricin nature l6j.

Another survey done by a CIGRE working group onfailures in large power transformers [1] found that about41 percent of failures were due to on-load tap changers(OLTC) and about 19 percent were due to the windings.The failure origins were 53 percent mechanical and 31percent dielectric. On transformers without on-load tapchangers, 26.6 percent of failures were due to the wind-ings, 6.4 percent were due to the magnetic circuit, 33.3percent were due to terminals, 17.4 percent were due tothe tank and dielectric fluid, 11 percent were due to otheraccessories, and 4.6 percent were due to the tap changer.Figure 2 shows the percentage failure distribution forpower transformers with on-load tap changers.

Another report presents transformer failure data inSouth Africa [7]. This failure analysis was based on 188

Typical Transformer Failure Pattern

Years in ServiceFigure 1. Bathtub failure curve.

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power transformers in the voltage range of 88 kV to 765kV with ratings from 20 to 800 MVA. The failure modesare shown in Fig. 3.

Failure statistics for large transformers that had beenin service between 15 and 25 years are shown in Fig. 4 [4].

The above surveys and research results indicate thatload tap changers, windings, insulation aging, and con-tamination are the key sources of transformer failures.

Another paper [8] indicates that the average numberof failures over a four-year period (1975 to 1979) was 2.6failures per year per 100 transformers.

The cost and time to repair and replace a power trans-former is very substantial. The repair and replacement ofa 345/138 kV transformer normally requires about 12 -15 months. If a spare is available, the time needed for re-placement of a failed unit is in the range of 8 - 12 weeks.Transformer Life Management

Transformer life management has gained an increas-ing acceptance in the past 10 - 15 years, due to economicand technical reasons. The fundamental objective is to

Core

On Load TapChangersAccessories

WindingsFigure 2. Percentage failure of power transformers(CIGRE survey) [1/.

Lightning/SwitchingTransients

Figure 3. Percentage of failures of power transformers(South Africa) [7J.

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promote the longest possible service life and to mini-mize lifetime operating costs. The importance of this is-sue [9]-[15] has led to a lot of research in this area. Ingeneral, transformer life is equal to the insulation life,which depends on mechanical strength and electrical in-tegrity. Insulation degradation consists of hydrolytic,oxidative, and thermal degradation. The aging and lifeof a transformer has been defined as the life of the paperinsulation [10]. Several aging mechanisms were identi-fied as follows:

applied mechanical forces thermal aging (chemical reactions) voltage stresses contamination.The transformer is subjected to mechanical forces due

to transportation, electromagnetic forces caused by sys-tem short circuits, and inrush current. Vibration and ther-mal forces generated by different thermal expansion ratesin different materials cause long-term degradation of thepaper. The eventual dielectric failure may occur when themechanical forces rupture the insulation. The compres-sive mechanical forces on the cellulose paper can causematerial flow and cause clamping pressure to reduce.Thus the aging of paper insulation determines the ulti-mate life of the transformer, although other factors maycontribute to earlier failure.

Thermal aging of transformer insulating materials isassociated with the chemical reactions occurring withinthe materials. These chemical reactions are caused by py-rolysis oxidation and hydrolysis, and are accelerated byincreased levels of temperature and of the oxygen andmoisture contents. Associated with the chemical reactionof the cellulose paper is a reduction in the mechanicalproperties. The paper insulation becomes brittle to thepoint of almost falling apart, but it still retains an accept-able level of dielectric strength.

The temperature of a transformer has a major impacton the life of the insulation. Continuous on-line monitor-ing of the transformer oil temperature along with a ther-mal model of the transformer can give an estimate of theloss of life of the transformer due to overheating. Currentindustry standards limit maximum allowable hot spot tem-peratures in transformers to 140C with conventionaloil/paper insulation.

End of life may be dictated by anyone factor or by acombination of factors. Much attention has been givento paper aging as a cause of transformer failure. While itis undoubtedly a factor in reducing life, it does not auto-matically lead to failure; some other influence is nor-mally required, such as mechanical shock. In industryloading guides (e.g., lEC, ANSI, and IEEE) the princi-pal factor for end of life relates only to the trans-former's thermal factor. A classical method ofcalculating the remaining life of a transformer has beenthe Arhennius-Dakin formula:

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Remaining life = A eB1 Twhere A = initial life; B = constant, depending on theproperties of the material studied; and T = absolute tem-perature in "K.

A more comprehensive approach is clearly needed toevaluate the remaining life of a transformer as a whole.The other factors affecting the probability of failure arenot as easily quantified as thermal aging. To assess theoverall condition of a transformer reliably, several moni-toring techniques are used and are under investigation.The most common monitoring/testing methods used fortransformer condition assessment are given in [11],[16]-[76].

The traditional routine tests are: transformer ratiomeasurement, winding resistance, short-circuit imped-ance and loss, excitation impedance, and loss dissipationfactor and capacitance, aswell as applied and induced po-tential tests. These tests usually give information on faultsin windings, winding conductor and joint problems,winding deformation, oil moisture and contamination,and dielectric problems. Special tests include partial dis-charge measurement, frequency response analysis, vibra-tion analysis, infrared examination, voltage recovery, anddegree of polymerization. These detect problems such aslocal partial discharge, winding looseness and displace-ment, slack winding and mechanical faults, hot spot onconnection, moisture in paper and aging of paper, as wellas insulation degradation.

Oil tests are used extensively. They consist of dissolvedgas analysis (DGA) with ratio analysis, furan analysis, wa-ter content, resistivity, acidity, interfacial tension (1FT),and dissipation factor (DF). These detect oil incipientfaults, overheating, aging of paper, dryness of oil-paper,and aging of oil.

Life assessment of large transformers may be per-formed for the following reasons [12]: to monitor the condition of transformers and providean earlywarning of faults to diagnoseproblemswhen transformers exhibit signsof distress or following the operation of protectionequipment to determine whether a transformer isin a suitablecon-dition to cope with unusual operating conditions to obtain reference results to assistin the interpretationof subsequent tests to assistinplanning the replacement strategyfor apopu-lation of transformers to satisfythe requirements for insurance coverage.Testing and monitoring methods are reviewed in detail inthe next section.

Monitoring and Diagnostic MethodsGenerally speaking, the term "monitoring" describes abasic parameter measurement with threshold alarms. Theterm "diagnostics" indicates the addition of sophisticatedNovember/December 2002 - Vol. 18, NO.6

WindingDeformationDue toShort CircuitForces

CoreInsulationFailure

Figure 4. Failure of transformers 15 to 25 years old [4J.analysis, such as an expert system capable of providing anassessment of equipment condition and suggested ac-tions.

There are a variety of tools available to evaluate thecondition of transformers [25], [55], [64]-[65],[77]-[81]. They can be separated into traditional diagnos-tic methods that have seen widespread use for many yearsand nontraditional methods that range from methodsthat are starting to be used to methods that are still in theresearch stage.Traditional Diagnostic MethodsOIL TESTINGTesting of the winding insulating oil is one of the mostcommon tests used to evaluate the condition of transform-ers in service. Thermal and electrical faults in the oil lead todegradation of the oil.Dissolved Gas Analysis

Insulating oils under abnormal electrical or thermalstressesbreak down to liberate smallquantities of gases.Thecomposition of these gases is dependent upon the type offault. Bymeans of dissolved gasanalysis (DGA), it ispossibleto distinguish faults such aspartial discharge (corona), over-heating, and arcing in a great variety of oil filled equipment.Anumber of samplesmust be taken over a period oftime todiscern trends and to determine the severity and progres-sion of incipient faults. The gases in oil tests commonlyevaluate the concentration of hydrogen, methane, acety-lene, ethylene, ethane, carbon monoxide, carbon diox-ide, nitrogen, and oxygen. The relative ratios and theamount of gas detected in the sample are used to detectproblems with the insulation structure [82]-[90].CellulosicDecomposition-The thermal decompositionof oil-impregnated cellulose insulation produces carbon ox-ides (CO, CO2 ) and some hydrogen and methane (H2' CH4)due to the oil.Oil Decomposition-Mineral transformer oils are mix-

tures of many different hydrocarbon molecules, and the de-

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composition processes for these hydrocarbons in thermal orelectrical faults are complex. Heating the oil produces eth-ylene (C2H4) as the principal gas.Information from the analysis of gasses dissolved in in-sulating oil is one of the most valuable tools in evaluatingthe health of a transformer and has become an integralpart of preventive maintenance programs. Data fromDGA can provide:

advanced warning of developing faults monitoring the rate of fault development confirm the presence of faults a means for conveniently scheduling repairs monitoring of condition during overload.DGA data by itself does not always provide sufficient in-

formation on which to evaluate the integrity of a trans-former system. Information about its manufacture and thehistory of a transformer in terms of maintenance, loadingpractice, previous faults, and so on are an integral part of theinformation required to make an evaluation.

Generally, there are three steps involved. The first step isto establish whether or not a fault exists. In-service trans-formers always have some fault gases dissolved in their oil.Only when these levels exceed some threshold value is afault suspected. Several recommended safe values have beenpublished. Some of these are listed Table II.

The second step is to determine the type of fault. Twomethods most commonly used are the key gases and gasratios [17]-[18], [21]-[23], [27], [291-[30], [36J, [39],l45J, [56], [58], [60], [76]. The first involves plotting allthe total dissolved combustible gas (TDCG) as a per-centage of their total in a histogram. Each fault type willgive a distinctive pattern characterized by a key gas, gen-erally the most abundant. For example, high levels of hy-drogen with low levels of other gases are characteristic ofpartial discharge. The ratio method requires the calcula-tion of ratios of gases among each other, such as methaneto hydrogen. Three or four such ratios are used for diag-nosis. The most widely used are Roger's ratios; the sever-

ity of the fault is established by comparison of the levelsof gases with threshold levels and their rate of generation.At least two consecutive samples are needed to calculaterates of fault generation.

A list of key gases and their related faults are shown inTable III. For a detailed discussion, consult IEEE Std.C57.104-1991, "IEEE Guide for the Interpretation ofGases Generated in Oil-Immersed Transformers."Insulating Oil QualityThe condition of the oil greatly affects the performanceand the service life of transformers. A combination of elec-trical, physical, and chemical tests is performed to measurethe change in the electrical properties, extent of contamina-tion, and the degree of deterioration in the insulating oil.

The results are used to establish preventive maintenanceprocedures, to avoid costly shutdowns and prematureequipment failure, and extend the service life of the equip-ment. There is a multitude of tests available for insulatingoil. The most commonly used, and their significance, arelisted in Table IV.Threshold levels for these tests are speci-fied in ASTM D3487 for new oils and IEEE Guide637-1985 for service oils.

As paper degrades, a number of specific furanic com-pounds are produced and dissolved in the oil. The pres-ence of these compounds is related to the strength of thepaper as measured by its degree of polymerization (DP).Furan and phenol measurement in oil is a convenient,noninvasive method to assess the condition of the paperinsulation. Transformer oil samples should be analyzedfor furans and phenols when one or more of the follow-ing conditions exist:

overheating or overloading of the transformer h igh levels of carbon monoxide or carbon dioxide rapid decrease of interfacial tension without a correspond-

ing increase in acid number sudden darkening of the oil and a sudden increase of the

moisture content of the oil

T ab le I I . R e c o m m e n d L im its o f D is s o lv e d G a se sG a s Dornenburg /S t r i l t I E E E B u re a u o f R e c la m a tio n A g e C o m p e n s a te d

H y d r o g e n 2 0 0 1 0 0 5 0 0 20 n + 5 0M e t h a n e 5 0 1 2 0 1 2 5 20 n + 5 0E t h a n e 3 5 6 5 7 5 20 n + 5 0E t h y l e n e 8 0 5 0 1 7 5 20 n + 5 0A c e t y l e n e 5 3 5 7 5 n + 1 0C a r bo n M o n o x id e 5 0 0 3 5 0 7 5 0 2 5 n + 5 0 0T D C G * ( to ta l o f a b ov e) 72 0 110n + 7 1 0C a r b o n D i o x id e 6 0 0 0 2 5 0 0 1 0 0 0 0 100n + 1 5 0 0n =y e a rs i n s e rv ic e* T o t a l d is s olv e d c o m b u st ib le g a s

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transformers over 25 years old.Furan measurement is still a relatively new technique,and its interpretation is dependent on many operationaland historical factors. However, the guidelines in Table Vprovide some assistance.The degree of polymerization (DP) estimated from

furan analysis relates to the average value. Paper in trans-formers usually does not age uniformly, and there will beareas where degradation is more severe.POWER FACTOR TESTINGThe insulation power factor is the ratio of the resistive

current component to the total leakage current under anapplied voltage. Power factor measurement is an impor-tant source of data inmonitoring transformer and bushingconditions. In general, power factor measurement equip-ment comes with three basic modes of operation: a)grounded specimen test (CST); b) CST guard; and c) un-grounded specimen test (UST). The three measurementmodes allow measurement of the current leaking back tothe test set on each lead, individually and together. In gen-eral, a power factor of less than 1 percent is consideredgood; 1-2 percent is questionable; and if it exceeds 2 per-cent, action should be taken. Practically, the evaluation isnot only based on a single power factor data point but isalso based on the history of the change in power factor.Measurement of a transformer's capacitance and

power factor at voltages up to 10 kV (at 50 or 60 Hz) has

long been used as both a routine test and for diagnosis.The acceptance value should be less than 0.5 percent.Reference [60] categorizes the interwinding power factoras the following: dry < 0.5 percent; medium < 1.5 per-cent; and wet> 1.5 percent. The evaluation also takes ac-count of the transformer's power factor history. The testrequires an outage and isolation of the transformer. Thetests can be done, respectively, on high-voltage windingto ground, high- to low-voltage winding, low-voltagewinding to ground, high- to tertiary-voltage winding,low- to tertiary-voltage winding, and the tertiary-voltagewinding to ground insulation. It is used to detect prob-lems with the transformer bushings and to evaluate thecondition of the oil/paper insulation structure [17]-[18],[22], [35], [39], [45], [56]-[57], [60], [91].WINDING RESISTANCEWinding resistance isused to indicate the winding con-

ductor and tap changer contact condition. The test re-quires an ohmmeter capable of accurately measuringresistance in the range of 20 Q down to fractions of an Q.Winding resistance varies with oil temperature. Duringthe test, the temperature should be recorded. For futurecomparisons, the resistance should be converted to a ref-erence temperature. Measurement of transformer wind-ing resistance requires an outage and isolation of thetransformer. Variations of more than 5 percent may indi-cate a damaged conductor in a winding [22].

T a b l e III.K e y G a s e s G e n e ra te d b y P a r t i c u l a r F a u ltK ey G a s C h a ra c te r i s t i c F a u lt

H 2 P a r t ia l D is c h a r g eC 2 H 6 T he rm a l F au ~ < 3 00 D CC 2 H 4 T he rm a l fa u~ 3 0 0 D C -< 7 0 0 D CC 2 H 2 , C 2 H 4 T h e rm a l F a u ~ > 7 0 0 D CC 2 H 2 , H 2 D is c h a rg e o f E n e rg y

T a b l e I V . I n s u l a ti n g O i l T e s tsT y p e o f T e st A S T M M e th o d S ig n i f i c a n c e /E f f e c t s

D i e l e c tr ic B r e a k d o w n 0 8 7 7 ,0 1 8 1 6 M O is t u r e , p a r t ic le s , c e l lu lo s e f ib e rs / lo w e r d ie le c t r ics t r e n g t h

N e u t r a l iz a t io n N u m b e r 0 6 4 4 ,D 9 7 4 A c id ic p r o d u c ts fr o m o il o x id a t io n ! s lu d g e , c o r r o s io nI n t e r r a c i a l T e n s i o n ( 1 F T ) D 9 7 1 P r e s e n c e of p o la r c o n ta m in a n ts , a c id s , s o lv e n ts , v a m is hC o l o r D 1 5 0 0 D a r k e n in g in d ic a t e s co n ta m in a t io n o r d e te r io ra t io nW a te r C o n te n t 0 1 5 3 3 E x c e s s iv e p a p e r d e c o m p o s i t io n / lo w e r d ie le c t r ic s t r e n g thP o w e r F a c to r 0 9 2 4 ( 1 0 0 , 2 5 C ) D is s o lv e d m e ta ls , p e ro x id e s , a c id s , s a l ts /o v e r h e a t in gO x id a t io n In h ib IT o r (D B P C * ) 0 2 6 6 8 , 0 1 4 7 3 L o w le ve ls r e su ts in a cc e le ra te d o il a g in gM e t a ls in O i l I n d ic a t iv e o f p u m p w e a r, a rc in g o r s pa rk in g w i th m e ta l* D B P C -D ib u t y l P a ra c re so l

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T a b le V . G u id e l in e s fo r D e g ra d at io n2 -F u r a ld e h y d e ( p p m ) D e g r e e o f P o l y m e r i z a t i o n E x t e n t o f D e g r a d a t i o n

0-0.1 800-1200 I n s i g n i f i c a n t0.1-0.5 700-550 S i g n i f i c a n t1.0-2.0 500-450 C a u se fo r c on ce rn>10


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RECOVERYVOLTAGE MEASUREMENTThe recovery voltage measurement (RVM) [95]-[98]

method is used to detect the conditions of oil-paper insu-lation and the water content of the insulation. The RVMrelies on the principle of the interfacial polarization ofcomposite dielectric materials; that is, the buildup ofspace charges at the interfaces of oil-paper insulation dueto impurities and moisture. A de voltage is applied to theinsulation for a time. The electrodes are then short-cir-cuited for a short period of time, after which the short cir-cuit is removed to examine the rate of the voltage buildupor the polarization profile. The time constant associatedwith this peak recovery voltage gives an indication of thestate of the insulation. The main parameters derived fromthe polarization spectrum are the maximum value of therecovery voltage, the time to peak value, and the initialrate of rise of the recovery voltage.

The test results give an indication of the state of theoil/paper insulation structure of the transformer. It re-quires a transformer outage to carry out the test [18],[23], [40], [45], [60], [66]-[67], [99]. This method is verycontroversial as to its suitability for direct measurementof the moisture content in oil, due to the strong depend-ence of the results on the geometry, and construction ofthe insulation system of a transformer. Figures 5 and 6show typical RVM curves for old transformers that are ingood and poor condition.

The drawbacks of this test are that a long outage maybe required and the unreliability in the interpretation ofthe results.WINDING INSULATING OIL TESTING/MONITORING

In addition to the winding insulating oil tests routinelycarried out, as already described, there are other oil teststhat can provide information on the condition of thetransformer. These include particle count, metals in theoil, furan analysis, aniline point, corrosive sulfur, and oxi-dation stability.

Equipment to continuously monitor oil condition inservice is increasingly being installed on transformers.The most widely installed systems measure hydrogencontent, although systems that measure moisture andother gases are also available. The hydrogen and compo-sition sensors use semiconductor or fuel cell technology;and more complex sensors, which make use of infraredtechnology and gas chromatography, can detect severalor all of these gases.TAP CHANGER/MOTOR MONITORING

The use of oil testing has been extended to the testingof the tap changer oil. The oil tests are used as an indica-tor of contact deterioration [19], [27], [35], [39], [42],[50]-[51], [55], [59], [62], [63]-[64], [100].

Monitoring of the tap changer temperature can be used todetect problems, such as contact overheating, while acousticanalysis of the switching operation can detect faults in the se-lector and diverter switches [99]. Tap changer motor cur-


rents can be monitored to obtain a signature every time thetap changer moves. Changes in this signature are used todetect problems in the tap changer. Bearing monitors areused to detect bearing wear on transformer oil pumps [26].INTERNAL TEMPERATUREMEASUREMENT

The traditional method to measure the temperature ofa transformer winding is to measure the transformer'stop and bottom oil temperature and estimate the hot spottemperature. New fiber optic equipment has been devel-oped that is able to monitor the temperature two differ-ent ways. One is a distributed temperature measurementalong the entire length of the winding by a fiber optic ca-ble. The temperature of the complete winding could bemonitored if a fiber optic cable can be laid along thetransformer winding during construction of the trans-former. There are drawbacks of this method, however.High cost and high mechanical stresses on the fiber(squeezing and buckling) are a major concern. The fiberoptic needs to be handled with extreme care. Itwouldhave to be installed during transformer construction[23], [100]. The application of the fiber optic sensor sofar has been mainly for laboratory research and principaldesign studies. The technology used in the fiber optictemperature sensors is capable of measuring the fullrange of temperatures encountered on transformers.

1000

~ 100Q)OJ~g 10

~ ~

/ ~./~10.01 0.1 10 100 1000 10,000

Charge Time (Seconds)Figure 5. Typical RVM curve for a transformer in good condition.

1000

~ 100Q)OJsg 10

..--+-..V '\1 \/ \10.01 0.1 10

Charge Time (Seconds)100 1000

Figure 6. Typical RVM curve for a transformer in poor condition.

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The other type of system uses fiber optics for pointtemperature measurement. Since the sensors and associ-ated cables are insulated, they can be installed directly atthe transformer hot spots. The best time to install these sen-sors isduring transformer construction at the locations indi-cated by thermal modeling of the transformer; however,they can be retrofitted to an existing transformer, but this isdifficult to do.Temperature systems are being installed in on-load tap

changers. Monitoring the temperature and temperaturetrends has been found to be a useful indicator of degrada-tion oftap changer contacts [23], [27], [35], [49]-[51], [53].ON-LINE POWER FACTORMEASUREMENTSystems to measure bushing power factor on-line are

now available. Manufacturers have made available twosystems for monitoring the condition of bushings, basedon detecting changes in their capacitance and power fac-tor. Both systems use sensors on the bushing capacitancetaps to measure the bushing leakage currents. One systemuses an electric field sensor to measure the bus voltagephase angle, and calculates the capacitance and dissipa-tion factor from the measured data. The other techniquesums the bushing currents from the three phases and plotsthem on a polar plot. Any shift in the resultant currentsindicates a change in capacitance or dissipation factor ofone of the bushings. These measurements can give suffi-cient warning of an impending bushing failure to allowreplacement of the bushing before a catastrophic failureoccurs.POWER FACTORVS. FREQUENCY MEASUREMENT(DIELECTRICSPECTROSCOPY)The measurement of power factor over a broad range

of frequencies from a low of 1 mHz to 1 kHz or higherhas been used to evaluate the insulation condition [17],[40], [48], [57]. Interference can be easily detected as anirregularity; the transformer insulation usually has asmooth power factor-frequency characteristic. Power

-30

-40

~ -50S- = : . -i! J -60~I])TI. a -70'c0> Reference Transformern:2 -80 Transformer Under Test

-90

0.5 1.5 2Frequency (Hz)

2.5 3x 106

Figure 7. PRA test results comparison.

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factor-frequency characteristics allow for a more com-plete diagnosis of the examined insulation. At the lowerfrequency range, pressboard dielectric loss is the mainfactor; at medium frequency range, the oil conductivity isthe dominant contributor; and at the higher frequencyrange, the pressboard and the oil volume determine thedielectric loss. Different aging mechanisms can be de-tected and identified at their respective frequency ranges.

WINDING MOVEMENT DETECTIONA very serious problem that is particularly difficult to

detect is movement or distortion of the transformerwinding. Forces on the winding during short circuits onthe transformer can cause winding distortion. The othersource of winding movement is reduction or loss of wind-ing clamping. This can result in a transformer fault thatwill cause damage to the transformer and may result inexplosive failure of the transformer. Traditionally, theonly way to evaluate the winding condition of a largepower transformer is to drain the oil from the trans-former and carry out an internal inspection.Some research work has focused on using the trans-former vibration signal to detect winding looseness andon developing the analysis techniques for interpreting thevibration data [101]-[104]. The method is based on look-ing for changes in the transformer's vibration signature todetect movement in the winding. This method is not usedas widely as frequency response analysis tests for detect-ing winding movement.In the frequency response analysis test (FRA), the

transformer is isolated from the system and the imped-ance or admittance of the transformer is measured as afunction of frequency (typically to at least 2 MHz). Thisgives a "fingerprint" of the transformer. The test is re-peated over time and the "fingerprints" from two ormore tests are compared.There are two different test methods commonly used

to carry out the FRA test: the swept frequency test and thepulse test. The swept frequency method applies a variablefrequency voltage or a white noise voltage to thehigh-voltage winding and records the response in an-other winding or terminal. This technique is more widelyused in Europe than in North America. A similar tech-nique more commonly used in North America is the pulseFRA test. With this technique a pulse signal is applied tothe high-voltage winding, and the response is recorded inanother winding or terminal. Research indicates that thepulse method is more sensitive to detect small windingmovement and winding clamping looseness [1OS] . Figure7 shows an FRA test results comparison for a transformerwith some movement compared to a transformer in goodcondition. In general, the greater the difference betweenthe two "signatures," the greater movement in the trans-former. The test requires experienced personnel to com-pare the two signatures and evaluate the severity of themovement.



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The conventional FRA test requires a transformer out-age to carry out the test. Work has been carried out in Eu-rope and North America to use the transient voltagesgenerated during switching operations as the driving sig-nal to measure the transformer admittance [75], [106]. Ifthe on-line FRA test could be developed, it could reduceor eliminate the need for outages to carry out an FRA test.The FRA test has been used extensively. The drawbacks ofthe test are that it requires an outage, an initial referencetest with the transformer in good condition, great consis-tency in the test setup from one test to the next, and it re-quires experienced personnel to interpret the data.Despite these drawbacks this has been found to be themost effective test in detecting winding movement.

Another technique used to detect winding displace-ment is the frequency response of stray losses (FRSL).This test is done over a range of frequencies from 20 Hzto over 600 Hz [17]-[19], [21], [23], [25], [27], [34],[38], [45], [49], [52], [54], [56], [58], [72], [76], [107J.The FRSL test has not been extensively used or studied.Itis thought not to be as sensitive to winding movementas the FRA test due to its lower measurement frequencyrange.

Diagnostic Software and Expert SystemsDiagnostic software, which gives more definite indica-

tions of transformer problems than conventional analy-sis, is under investigation by many researchers andutilities [63], [71], [76].The use of software can improvethe reliability and repeatability of the analysis of test data.Itcan also be used to extract information that is not avail-able from the data directly.

A great deal of research has been done on software tointerpret transfurmer uil test data such as gas, moisturecontent, and dielectric strength and correlating the datawith the transformer insulation condition. Expert sys-tems have been developed that give an alarm signal to sys-tem operators. Some systems have been developed tudetect PD signals in transformers [94]. Equipment usingacoustic emission sensors and specialized software hasbeen successful in detecting PD and locating the origin ofthe discharge. The sensors are muunted externally on thetransformer tank wall and three-dimensional locationtechniques are applied to locate the source of the detectedsignals.

The present advancement in artificial intelligence (AI)modeling techniques has enabled power engineers and re-searchers to develop powerful and versatile AI software todiagnose transformer faults. The use of expert systems of-fers the potential of reducing the manpower and financialoverhead required by utilities to assess transformer condi-tion; however, this potential has not yet been realized.

Discussion and Concluding RemarksThe most widely used tests to diagnose the condition

of transformers are still oil tests and off-line power factor

November/December 2002 - Vol. 18, NO.6

testing at reduced voltages. The use of other tests (bothoff-line and on-line) is increasing but is limited by a num-ber of factors.

Cost: The high cost of testing and monitoring can makeit difficult to justify the tests. The purchase price of theequipment is only one cost factor limiting their use. Thecost of isolating the transformer and performing the testcan be substantial for off-line tests. The long outage timerequired by tests, such as the recovery voltage method,can make them difficult to carry out. The installationcosts for on-line monitoring equipment can be a majorcost factor.

Data interpretation: The interpretation of tests often re-quires experienced expert personnel. Incorrect inter-pretation of the data can lead to false conclusions aboutthe transformer condition.

Reliability: The degradation of a transformer occursover several years. Sensors and electronic equipment in-stalled on the transformers must be able to perform overmany years with minimal maintenance.

Compatibility: The compatibility of the many on-linemonitoring systems now available is a major concern.Typically systems from one supplier are completely in-compatible with those of other suppliers.

Use of nontraditional diagnostic and monitoring tech-niques is expected to increase on the aging transformerpopulation. The cost of the equipment will fall and reli-ability will increase with increased usage. The interpreta-tion and understanding of the test data obtained fromtests such as FRA, RVM, and vibration testing will im-prove. In particular, standard analysis techniques are be-ing developed that will enable field personnel to moreeasily use the test results and will reduce the need for in-terpretation by experts. Multiple test software that com-bines the results uf different tests and gives an overallassessment of condition is expected to find increasinguse. The use of continuous on-line monitoring of trans-formers is increasing. The cost of the equipment is de-creasing and the sensors are improving. This makes iteasier to justify the installation of sophisticated monitur-ing systems on transformers. Standardization will make iteasier to integrate systems and data from different suppli-ers. The use of wireless technologies within the substa-tion for communication between the transformer andcontrol room will make it easier to install monitoringequipment.

The ultimate goal of transformer monitoring and diag-nostic techniques is to have a set of devices/systems to moni-tor and anticipate the transformer failure, so thatappropriate action can be taken before forced outage oc-curs. The organizational culture of a power utility signifi-cantly impacts on the operational practices in the use ofcondition-based maintenance.M. Wang received the B.Sc. degree in electrical engineeringfrom Xian Jiaotong University, Xian, China and the

21


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M.A.Sc. degree in electrical engineeringfrom the University of British Columbia,Vancouver, Canada, in 1982 and 1991, re-spectively. From 1982 to 1988, she waswith the Wuhan High Voltage Research In-stitute as a research engineer. In 1991, shejoined Powertech Labs Inc. as a senior re-search engineer. Her research interests are

in transformer condition monitoring, transformer fre-quency response analysis, and high-voltage engineering.She is an active IEEE member and is a registered profes-sional engineer in the province of British Columbia.

John Vandermaar received his B.Sc. in En-gineering from the University of Manitobain 1975. From 1975 to 1980 he was withthe Operations and the Engineering Divi-sions of BC Hydro. In 1980 he joined theResearch and Development Division of BCHydro (now Powertech Labs Inc.). He hasbeen responsible for many research pro-jects in the areas of high-voltage insulation, equipment con-

dition monitoring, and equipment life assessment.Currently, he is the Manager of the High Voltage Group atPowertech Labs Inc. Mr. Vandermaar is the secretary of IECTC 42 High Voltage Test Techniques and a member of IECWorking Group 12 on Voltage Measurement by Means ofAir Gaps. He is also active on various IEEE standards com-mittees.

K.D. Srivastava (M'67-SM-81-F'85-LF'00)received the B.E. (Honors) degree in elec-trical engineering from the University ofRoorkee, Roorkee, India and the Ph.D. de-gree from the University of Glasgow, Glas-gow, U.K. in 1952 and 1956, respectively.He was a Research Engineer at A . Reyrolleand Co., Newcastle, Ll.K. from 1957 to

1958. From 1958 to 1960, he was with the University ofRoorkee and the University of Jodhpur as a Senior FacultyMember. From 1961 to 1966, he worked at Brush ElectricCo., Loughborough, U.K., as a Senior Research Engineer,and then at the Rutherford High Energy Laboratory,Harwell, U.K. as a Principal Scientific Officer. In 1966, heemigrated to Canada and was appointed Professor of elec-trical engineering at the University of Waterloo, Waterloo,ON, Canada, and from 1972 to 1978, he was Chairman ofthe Department. In 1983, he was appointed Professor andHead of the Department of Electrical Engineering at theUniversity of British Columbia (UBC), Vancouver, BC, Can-ada, and from 1986 to 1994, he was Vice President of Stu-dent and Academic Services at the same University. Hisresearch interests are in gaseous insulation and high-voltageengineering.

2 2

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