1077-2618/12/$31.00©2012 IEEE

Guidelines to replace older transformers before failure

TRANSFORMERS PLAY CRITICAL

roles in delivering power to distribution

equipment for homes,

commercial establish-

ments, and industrial facilities. The

sudden failure of a transformer can

cause serious repercussions, leading to

loss of power for a few minutes to hours. There are cases

where an outage can last for weeks because of the system

configuration, such as a simple radial system or the

transformer was the single-point failure. In industrial

complexes, an outage lasting for a

few minutes could lead to loss oppor-

tunities as well as millions of dollars

in lost production and start-up costs.

Many older transformers have been

in operation for more than 80 years without failure or

major problems. There have been recent failures of units

producing fires and explosions, resulting in the release of

toxic and combustible gases as well as smoke into theDigital Object Identifier 10.1109/MIAS.2012.2202814

Date of publication: 17 July 2012

BY FRED L. DIXON,

DAVE STEWARD,

& JAMES HOFFMEISTER

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atmosphere; Also, the OccupationalSafety and Health Administration(OSHA) has levied fines because of thetype of incidents. Many transformers inthe petrochemical industry now fall underOSHA 1910.119 [15], mechanical integ-rity regulations, due to the probability ofcatastrophic failure during power loss,resulting in the release of highly hazard-ous chemicals. Transformer tanks contain-ing more than 10,000 lb of aggregatessometime fall under the 1910.119 as wellas 1910.269 regulations. Mineral oil intransformers is used as a media for coolingand insulating parts within close proxim-ity. Mineral oil has a National Fire Protec-tion Association (NFPA) flammabilityrating of one, indicating it is slightly flammable with a healthrating of one, indicating a slight health hazard. During faultconditions, however, mineral oil can be hazardous to yourhealth and the environment.

Aging TransformersThe purpose of this article is to provide information andinsight related to repair or outright replacement ofaging transformers containing mineral oil, under faultconditions, such as the production of combustible gases.This article explains how oil sampling, gas analyses,internal inspection, and testing are used to determinewhich transformers required replacement or simplerepairs. It also describes the use of standards such asIEEE C57 [1] guidelines to determine loading, hours ofoperation, degradation, and other tests to evaluate con-ditions and suitability for future operation of transform-ers. The use of insulation power factor (PF), furan, andother tests to predict the remaining life of transformersas well as life cycles and vintage of transformer producedin the 1950s versus those manufactured for our facilityafter 1990 are also discussed. Descriptions about meth-ods, local repair shops employed to test and evaluatetransformer-incoming conditions, and suitability forfuture service are also outlined.

The industrial plant, where many transformers areinvolved, was built in 1940 as a government defense plant.The transformers used in the study were installed in 1951and later. Some of the original equipment, such as breakersand switch racks, still exist. Transformers installed in theearly 1950s until the year 2000 operated without mainte-nance with little or no problems.

This article deals with three-phase, mineral-oilimmersed power distribution transformers rangingfrom 500 kVA up to 10 MVA and with primary vol-tages from 4,160 to 13.8 kV. It involves a study ofwhether to replace or repair transformers; therefore,the values and results shown apply to this study, andthe results may not be applicable in other circumstan-ces. One third of the transformers were discovered withsevere internal problems via oil analyses such as dis-solved gas analysis (DGA) and liquid screens. Itappeared that most of those transformers having prob-lems were older than 50 years and were initiallythought to be past their life expectancy. There are a

total of 45 transformers involved inthe study. This article will revealmethods and procedures used todetermine whether to replace orrepair those producing dangerousamounts of combustible gases. SeeTable 1 for a list of transformersinvolved in the study and therelated combustible gases.

There are many publicationsindicating the life span of powertransformers. American NationalStandards Institute (ANSI)/IEEEC57.91 indicates an expected lifespan of about 20 years; however,there are many transformers thathave been in service three to four

times that long. Experiences have shown the lifeexpectancy to be 30–40 years. Factually, it is knownthat unit substation transformers built during andafter the 1970s were built with fewer materialsbecause the engineering process had improvedgreatly, allowing manufacturers to install fewer mate-rials and maintain a life expectancy of 20–30 years.Figures 1 and 2 are 1,000-kVA units, Figure 1 is 59years old, whereas Figure 2 is five years. The unitshown in Figure 2 failed after a year of service. Thetransformer in Figure 1 is approximately 2.5 timeslarger due to larger winding conductors, more insula-tion, and more steel in the core.

The most significant part of a transformer that deter-mines life is the insulation system. All transformer failuresare caused by some type of insulation system failure. Insu-lation is usually made of paper or any cellulose type ofmaterial, mineral oil, or any cooling and dielectricmedium. External bushings are also considered as part ofthe insulation system. Even under ideal operating andenvironmental conditions, failures still occur from insula-tion degradation.

Description of Initial Problemswith Aging TransformersIn the 1980s, the transformers listed in Table 1 beganto have predictive testing performed on them. Thesetests were performed on an annual basis by extractingoil samples while the unit was energized. Sampleswere sent to a certified laboratory. The followingtests were performed: DGAs, dielectric, Karl Fischermoisture, neutralization or potassium hydroxide(KOH), interfacial tensions (IFTs), inhibitor, color,and visual tests.

In 2004, it was discovered that many transformers wereproducing dangerous amounts of combustible gases.Some of the units indicated cellulose deterioration as wellas overheating, high moisture content, and sparking viaoil analyses.

A study was performed to evaluate the condition ofthe plant’s entire power distribution system with trans-formers at the forefront. It was decided that immediateaction was necessary to alleviate safety hazards. How-ever, there were ten initial questions, problems, andtasks that needed to be considered and resolved. Some of

THE OLDERTRANSFORMERAPPEARS TOOPERATE

COOLER THANNEWER UNITS

BUILT AFTER 1980.

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TABLE 1. INITIAL CONDITION OF TRANSFORMERS ON 20 SEPTEMBER 2004.

EquipmentNumber

Size(MVA)

Primary/SecondaryVoltage(kV)

Con-nection

DateBuilt

TankCapacityat 25 �CLevel (gal)

O2

(ppm)

Two KeyCombinationGases

Key Gases(ppm)

TotalCombination(ppm)

10XF-1 1.0 4.16/.480 Y/D 1950 450 3,366 H2/C2H4 6,170/2,740 10,837

10XF-2 1.0 4.16/.480 Y/D 1951 450 3,126 H2/C2H4 5,215/821 7,029

10XF-3 1.0 4.16/.480 Y/D 1951 450 10,399 CO/C2H4 713/452 1,265

10XF-4 1.0 4.16/.480 Y/D 1952 450 2,064 H2/CO 3,166/521 4,279

10XF-5 1.0 4.16/.480 Y/D 1952 450 3,070 CO/C2H4 1,119/347 1,540

10XF-6 1.0 4.16/.480 Y/D 1951 450 26,221 CO/H2 131/16 156

10XF-8 1.0 4.16/.480 Y/D 1961 300 24,829 CO/CH4 419/68 535

10XF-10 1.0 4.16/.480 Y/D 1961 297 4,909 CO/CH4 577/35 644

10XF-11 2.5 13.8/4.16 D/Y 1987 394 10,668 CO/CH4 763/30 817

10XF-12 1.0 4.16/.480 Y/D 1957 499 2,385 CO/C2H6 389/55 513

12XF-1 1.0 4.16/.480 Y/D 1957 450 2,340 C2H4/H2 2,348/1,454 6,066

12XF-2 1.0 4.16/.480 Y/D 1957 450 5,941 C2H4/CH4 1,033/384 1,939

12XF-3 1.0 4.16/.480 Y/D 1957 450 9,689 CO/C2H4 827/208 1,052

12XF-4 1.0 4.16/.480 Y/D 1957 450 8,278 CO/C2H4 887/314 1,221

16XF-1 1.0 4.16/.480 Y/D 1954 499 3,013 CO/C2H6 265/32 348

16XF-2 .50 4.16/.480 Y/D 1952 235 24,149 CO/H2 206/13 231

21XF-1 1.0 4.16/.480 Y/D 1963 450 11,094 CO/H2 551/10 568

21XF-2 1.0 4.16/.480 Y/D 1963 235 4,298 C2H6/CH4 689/223 1,073

24XF-1N 3.75 13.8/4.16 D/Y 1971 430 5,073 CO/CH4 1,079/46 1,148

24XF-1S 1.5 13.8/.480 D/D 1971 355 4,621 CO/C2H4 542/43 622

24XF-2 1.5 13.8/.480 D/D 1971 355 3,487 CO/CH4 514/65 672

24XF-3 3.75 13.8/4.16 D/Y 1971 430 29,287 CO/C2H6 71/16 92

24XF-4N 3.75 13.8/4.16 D/Y 1971 521 4,148 CO/C2H6 810/21 841

24XF-4S 1.5 13.8/.480 D/D 1971 355 2,962 CO/CH4 575/109 768

24XF-5 1.0 13.8/.480 D/D 1971 250 7,003 CO/C2H4 742/39 826

24XF-6 1.0 13.8/.480 D/D 1971 250 33,144 CO/C2H4 25/3 29

24XF-7 2.5 13.8/4.16 D/Y 1997 321 14,421 CO/C2H4 535/32 571

33XF-1 7.5 13.8/4.16 D/Y 1990 1,091 2,636 CO/CH4 1,292/41 1,367

33XF-2 1.5 13.8/.480 D/D 1990 192 2,069 CO/CH4 349/5 363

33XF-2D .1175 4.16/.480 D/D 1990 115 2,510 CO/H2 548/9 571

33XF-3 10.0 13.8/4.16 D/Y 1990 1,253 2,111 CO/CH4 1,649/23 1,697

33XF-4 1.5 13.8/.480 D/D 1990 192 5,038 CO/CH4 1,040/16 1,065

33XF-4C .225 4.16/.480 D/D 1990 234 3,057 CO/CH4 620//9 642

33XF-5 7.5 13.8/4.16 D/Y 1990 1,091 1,876 CO/CH4 987/41 1,045

33XF-6 1.5 13.8/.480 D/D 1990 192 2,480 CO/CH4 718/14 748

33XF-6C .1175 4.16/.480 D/D 1990 115 2,342 CO/CH4 628/9 650

33XF-7 1.5 13.8/.480 D/D 1990 192 2,335 CO/CH4 412/12 437

33XF-8 1.5 13.8/.480 D/D 1990 192 9,526 CO/CH4 710/10 725

62XF-2 1.0 12.5/.480 D/D 1999 500 7,295 CO/C2H4 373/5 387

62XF-3A 2.5 12.5/2.4 D/Y 1981 720 2,296 CO/H2 531/17 575

62XF-3B 1.0 12.5/.480 D/D 1981 322 3,915 CO/C2H4 774/137 981

(continued)48

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the questions had to be resolved quickly due to safety

reasons as well as prevent imminent failures. At the timeof discovery, each production unit was operating atcapacity because of demand. The loss of productionwould lead to millions of dollars in lost revenues if theyhad to shut down to repair or replace transformers. Thefollowing questions were generated to approach the sit-uation in a responsible manner:

1) Is it safe for personnel to work in the vicinityof transformers that produced more combusti-ble gases?

2) Is there a high probability of an explosion or firedeveloping if there is an ignition of combustiblesgases in the oil or atmosphere above the oil insidethe tank?

3) Is it necessary to shutdown the transformers toremove the combustible gases?

4) Can the repairs wait? (A schedule for the turn-around of a plant is less than a year away.)

5) Transformers were 54 years old at the time. Shouldthey be replaced?

6) What is the remaining life of each unit?7) Do we have spare transformers, and how long will

it take to replace with a spare?8) How long will it take to manufacture new trans-

formers, or can we purchase used transformers orpossibly rent them?

9) Can we replace or repair problem transformerswithout shutting down?

10) When should we replace aging transformers to pre-vent similar occurrences? Develop a philosophy orcriteria to determine when aging transformersshould be replaced.

The initial questions of safety had to be resolvedquickly. See Table 1 for type transformer and significantgases involved. Table 2 lists the gases in oil for each ofthe failing transformer. An initial reevaluation led to a

2Transformer 62XF-2 core and windings, 1,000-kVA unit.

TABLE 1. (CONTINUED)

1Transformer 12XF-3 core and windings, 1,000-kVA unit.

EquipmentNumber

Size(MVA)

Primary/SecondaryVoltage(kV)

Con-nection

DateBuilt

TankCapacityat 25 �CLevel (gal)

O2

(ppm)

Two KeyCombinationGases

Key Gases(ppm)

TotalCombination(ppm)

62XF-6 1.0 13.8/4.16 D/Y 1976 300 3,625 CO/C2H4 281/52 357

62XF-12 .50 12.5/.480 D/D 2006 230 18,852 CO/C2H4 378/23 438

68XF-31 .500 4.16/480 D/D 1989 273 7,301 CO/C2H4 616/19 654

68XF-32 .50 13.8/480 D/D 1971 310 4,797 CO/C2H4 819/58 914

Gas Solubility(vol %) Gas Solubility (vol %)

CH4 = Methane (43.8) C2H2 Acetylene (122)

C2H6 = Ethane (259) CO Carbon monoxide (13.3)

C2H4 = Ethylene (176) H2 Hydrogen (5.6)

CO2 = Carbon dioxide (117) O2 Oxygen (17.9)

N2 = Nitrogen (9.7)

Numbers in bold indicate amounts that exceed recommended values.

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choice to deenergize or removecombustible gases as soon as possi-ble. The “Different Type Tests andAnalyses” section will discuss thecombustible mixture in detail.The amount of combustible gasmixture with oxygen indicatedthat ignition was possible. Unitscontaining critical amounts ofcombustible gases could not beeasily deenergized because it wouldengender substantial amount ofloss product and profits. It wasdecided to degas the units; how-ever, in the past, the rule ofthumb was never to degas atransformer while energized [5].It was decided to bring in acompany that specialized in thedehydration process while trans-formers are still energized. Thetransformers were successfullydegassed without incident. Afterdegassing, the increase rate forsome units was substantial. Theteam used ANSI/IEEE 57.104,Table 3, to provide guidelines forequipment serviceability andappropriate action.

The production of each gas wascaused by different failure modesinside transformers; information inTable 7 in ANSI/IEEE 57.104 wasused to determine possible the causeand remedy.

Different Type Tests andAnalysesSeveral tests were used to determinethe condition of transformer wind-ings and insulation systems. Tests,such as chromatography, were usedto analyze different dissolved gasesin oil. Each gas produced is the resultof an anomaly that effects the opera-tion and possible life of thetransformer. Furan and insulation PFtests were used to determine degra-dation of the insulation. Oil screentests were performed to determinethe condition of the oil. ANSI/IEEEC57 indicates that there are five faulttypes, such as arcing, corona, spark-ing, overheating, and overheatedcellulose, although only four wereidentified in transformers involved.

Arcing is the most severe of allfaults producing acetylene gas; how-ever, there were no signs of arcingbecause of the absence of acetylenegas. Arcing normally occurs whenloose connections occur. Acetylene

TABL

E2.

TRANSFORM

ERSOPE

RATING

WITHDANGER

OUSAMOUNTS

OFCOMBU

STIBLE

GASE

S

Equipment

Number

Insulatio

nPF

(%)

H2(p

pm)

CH4(p

pm)

C2H6(p

pm)

C2H4(p

pm)

C2H2(p

pm)

CO

(ppm)CO

2(p

pm)

N2(p

pm)

O2(p

pm)

TwoSignificant

Combinatio

nGase

sSignificant

Gase

s(p

pm)

Tota

lCombinatio

n(p

pm)

10XF-1

0.53

6,17

01,09

246

32,74

00

371

15,801

86,947

3,36

6H2/C

2H4

6,17

0/2,74

010

,837

10XF-2

2.0

5,21

524

510

082

10

648

17,375

92,520

3,12

6H2/C

2H4

5,21

5/82

17,02

9

10XF-3

0.67

952

3945

20

713

17,426

88,318

10,399

CO/C

2H4

713/45

21,26

5

10XF-4

2.1

3,16

619

896

298

052

124

,340

77,997

2,06

4H2/C

O3,16

6/52

14,27

9

10XF-5

1.2

3033

1134

70

1,11

936

,309

80,393

3,07

0CO/C

2H4

1,11

9/34

71,54

0

12XF-1

0.49

1,45

41,11

342

62,34

80

725

39,241

80,632

2,34

0C

2H4/H

22,34

8/1,45

46,06

6

12XF-2

0.43

5638

416

31,03

31

302

8,99

190

,492

5,94

1C

2H4/CH4

1,03

3/38

41,93

9

12XF-3

0.38

58

320

80

827

11,575

85,881

9,68

9CO/C

2H4

827/20

81,05

2

12XF-4

0.59

710

331

40

887

19,103

8,04

458,27

8CO/C

2H4

887/31

41,22

1

21XF-2

1.12

122

368

919

014

13,44

097

,747

4,29

8C

2H6/CH4

689/22

31,07

3

24XF-1N

0.36

346

1210

01,07

98,71

716

8,67

95,07

3CO/CH4

1,07

9/46

1,14

8

24XF-5*

N/A

725

1339

074

27,06

385

,217

7,00

3CO/C

2H4

742/39

826

24XF-5**

0.39

511

730

037

95,51

480

,805

21,240

CO/C

2H4

379/30

432

33XF-1

0.52

2241

85

01,29

220

,547

89,738

2,63

6CO/CH4

1,29

2/41

1,36

7

33XF-3

0.85

1623

63

01,64

912

,435

82,411

2,11

1CO/CH4

1,64

9/23

1,69

7

33XF-4

0.51

316

23

01,04

016

,974

98,548

5,03

8CO/CH4

1,04

0/16

1,06

5

33XF-5

0.54

741

64

098

723

,521

83,395

1,87

6CO/CH4

987/41

1,04

5

Numbersin

bold

indicate

amounts

thatexc

eedrecommendedva

lues.

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gas is more dangerous than others(Table 2) because of its lowerexplosive limit (LEL) as well aswide range of mixture for ignitionto take place [10], [11].

Evidence of a corona wasshown in the samples because oflow-energy electrical dischargesproducing hydrogen and methanewith small quantities of ethane andethylene. There were comparableamounts of carbon monoxide anddioxide due to discharges in thecellulose (paper).

There was substantial evidenceof sparking because of the increasedlevels of methane and ethane withconcurrent increases in ethyleneand hydrogen. It was determinedthrough DGA that several unitsexperienced overheating due tosigns of decomposing products suchas ethylene and ethane.

Large quantities of carbonmonoxide and carbon dioxidewere produced, exhibiting signsof overheated cellulose, as shownin Table 1. Lab reports indi-cated that there were substantialamounts of combustibles gases inthe atmospheric blankets abovethe oil on several units (seeTable 2). The mixture andamount of combustible gases weregrave concerns. Although gas inoil are in parts per million (ppm),a mixture with high levels of oxy-gen by volume could producesmall ignitions, causing com-bustion within the oil media,though propagation of flames arehighly unlikely [12] because aconstant supply of oxygen is notavailable within the oil. Theresults, however, lead to carbon-ization of the oil.

Carbonization reduces electri-cal clearances; therefore, smallignition or combustion in oilcan cause tracking and eventuallyarcing. Propagation of flames inoil is highly likely once a mixtureis between the lower and upperflammable limits [12] with ade-quate oxygen. Arcing can causerapid expansion of all gases, there-by breaching roofs, walls, and bot-toms of tanks.

A properly calibrated hand-held LEL combustible gas detec-tor [9] was used to sniff theatmospheric blanket above the

TABL

E3.

REPA

IRORRE

PLACECRITERIA.

Equipment

Number

DGA*

(Alarm

at

1,00

0ppm)

PF(%

)Insulatio

nMaximum

2%

Exciting

Curre

nt

(2%)

Winding

Resista

nce%

(10%

Maximum

Deviatio

n)

Core

Insulatio

n>50

MOhms

Furan

(DP)

Minim

um

(500

)

Karl

Fisc

her

(ppm)

Neutralizatio

nAcidity

(Mg

KOH/g

)Hoursof

Operatio

nLo

ad

(%)

Possible

Seve

rePa

per

Degra-

datio

n

Vinta

ge

or

Desig

nRepairor

Replace

10XF-1

10,837

0.53

0.9

5.1

>10

0MN/A

90.01

652

5,60

090

?Disk

Repair

10XF-2

7,02

92.0

0.21

0>10

0M50

011

0.01

250

8,08

090

Yes

Disk

Replace

10XF-3

1,26

50.67

1.1

0.09

>10

0MN/A

50.01

850

8,08

090

?Disk

Repair

10XF-4

4,27

92.1

1.2

0.09

>10

0M50

7-60

015

0.04

551

6,84

010

0Ye

sDisk

Replace

10XF-5

1,54

01.2

1.42

0.2

>10

0MN/A

180.02

151

6,84

010

0?

Disk

Replace

12XF-1

6,06

60.49

0.95

1.6

>10

0MN/A

50.03

346

4,28

060

No

Disk

Repair

12XF-2

1,93

90.43

1.4

0>10

0MN/A

80.02

146

4,28

060

No

Disk

Repair

12XF-3

1,05

20.38

0.50

2>10

0MN/A

50.01

146

4,28

080

No

Disk

Repair

12XF-4

1,22

10.59

0.7

0>10

0MN/A

90.01

446

4,28

060

No

Disk

Repair

21XF-2

1,07

31.12

0.50

8.5

>10

0M59

812

0.03

141

1,72

098

Yes

Sheet

Replace

24XF-1N

1,14

80.36

0.09

0.1

>10

0M80

07

0.02

234

1,64

080

No

Sheet

Repair

33XF-1

1,36

70.52

0.98

0>10

0MN/A

80.01

117

5,20

060

No

Sheet

Repair

33XF-3

1,69

70.85

0.92

1.2

>10

0M98

99

0.01

317

5,20

060

No

Sheet

Repair

33XF-4

1,06

50.51

1.3

0>10

0M98

64

0.01

717

5,20

085

No

Sheet

Repair

33XF-5

1,04

50.54

0.91

0>10

0MN/A

60.01

917

5,20

080

No

Sheet

Repair

*1,000

ppm

limitwasentirely

base

donresults

foundwhencore

andwindingswere

remove

dfrom

theta

nk.

Thisva

lueissp

ecificonly

tothedata

base

shown.L

imits

maydifferdueto

differentratio

ofcombustible

gase

salongwith

otherva

riables.Bo

ldexc

eedsrecommendedva

lue.

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oil on transformer 10XF-4. Thisvalue was used to compare theequivalent total combustible gas.The purge valve, normally used foradding nitrogen, was open to samplegases above the oil. The LEL metersniffs the gas coming from the valveand the needle pegged out, indicat-ing that the combustible mixture waswell above 100% of the LEL. Labresults from the DGA of thetransformer indicated a combustiblegas level of 6.82% by volume in thegas blanket. The largest volume ofdissolved gas in this particulartransformer was hydrogen at 3,166ppm, with an LEL of 4.0% by volumeof air or oxygen [10], [11]. The con-ditions were extremely dangerous topersonnel and equipment, and remedial measurementsshould be implemented as soon as possible.

Each unit in Table 2 was immediately degassed as timepermitted with a hesitant attitude because of a past rule ofthumb stating that one should not degas a transformerwhile it is energized. The degassing efforts were successfulwithout incidents. Quantifying the hazard and degassingeach unit answered and resolved issues related to questions1)–4) in the “Description of Initial Problems with AgingTransformers” section.

The composition of the different gases and diagnosisdoes reveal root causes based on DGA. The condition ofoil on each unit was determined from Rogers ratio [1];however, the use of gas analysis cannot predict theremaining life of a transformer but can reveal symptomsof paper degradation. Normally carbon monoxide alongwith combinations of other gases exhibit cellulosedecomposition as mentioned earlier. The direct polymer-ization test can be used to predict remaining life and ismore accurate than any other method; however, this testis destructive, requiring insulating materials to beremoved from the internal windings to determine thedegree of polymerization. This method was not chosenbecause of its destructive nature.

An indirect polymerization test was performed ontwo our of 45 transformers to determine the remaininglife. Only two were chosen because in most of the unitsnew oil was added and had concerns about additionalcost-effectiveness. This test relies on the amount offuran released from the paper and is nondestructive.Many believe that the furan method is the most accurate;however, many of the transformers in question werefilled with new oil over the course their history; newoil tends to distort the furan test, providing an inaccu-rate degree of polymerization or Pv. It was decidedthat more than one test could not determine the remain-ing life of a transformer. Hence, test methods used bythe repair shop were decided to be included in thecriteria for determining the remaining life of allunits. In certain areas of some manufactured transformer,the furan test would not be applicable. Figure 3shows the results of a transformer failure, 24XF-5. Thefailure occurred between turns on the windings.

The turns are insulated only by thecoating on the copper conductor.

Shop Evaluation ofTransformersThe dissolved gas test proved to bethe most useful test in detecting seri-ous problems with the transformers.Externally many of the transformersappeared to be satisfactory. Thetemperature, pressure, and oil levelswere reading within proper ranges.The outside of each unit was rusty,and there were no apparent intrusionsof water inside the transformers.

Each of the problem units shown inTable 2 was eventually removed fromservice and sent to a local repairshop, where each transformer was

tested. An insulation PF test was performed using a dissi-pation factor tester as well as additional electrical tests andvisual inspections.

Before working on the transformers, each was drained ofoil and purged by nitrogen to eliminate the remains of anycombustible gases. Upon an internal inspection, it wasdetermined that the tap changer was the main cause of gasproduction in most units. Some gases, as shown in Table 2,were produced by overheating, with the tap changeraccounting for the great majority of gas.

An insulation PF test was also performed with a dif-ferent manufacturer’s test equipment when thetransformer was returned to the plant just before reener-gizing. The different test methods were close, butthe insulation PF was never the same. We based ourdecision on the field tester. Once each unit was opened,problems found were similar, requiring little assertionto determine what was causing the extreme productionof gases. The tap changers on 99% of the units were thecause of the production of most gases. Some gaseswere produced just simply because the transformer wasoverloaded.

The repair report shown in Figures 4 and 5 displays thetype of tests performed on each unit before leaving the

3Transformer 24XF-5 failure analysis, 1,000-kVA unit.

THE DISSOLVEDGAS TEST PROVEDTO BE THE MOSTUSEFUL TEST INDETECTINGSERIOUS

PROBLEMSWITH THE

TRANSFORMERS.

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repair shop. Values from these tests areused to determine whether to replaceor repair each unit in question. Valuesare listed in Table 3.

Values measured during thecapacitance/dissipation factor test,while at the repair shop, were usedto determine whether a transformershould be repaired or replaced (seetest values in Figure 4). The dissi-pation factor test is an insulation PFtest; the maximum value is 2% [13]. A high insula-tion PF indicates that insulation may be breaking

down due to the amount of energyabsorbed during a test. A compara-ble insulation PF test may be usedby other repair shops. New trans-formers are normally under 0.5%insulation PF.

The winding resistance test waschosen to be a part of the criteria todetermine whether a transformershould be replaced. Connectionresistance can be high, causing

localized heat buildup that causes degradation ofinsulation in areas within the windings. To correct a

4Shop final test report to repair a 10XF-1, 1,000-kVA unit transformer.

CARBONIZATIONREDUCES

ELECTRICALCLEARANCES.

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problem of this nature, the unit will have to berewound, which in some cases, can cost at least50% up to a maximum of 75% for a new transformer.A maximum deviation of 5% was considered as afailure limit.

The excitation or magnetizing current test wasincluded in the criteria to determine whether toreplace or repair. The failure limit value is 2%

maximum. High magnetizing currents tend to indi-cate high losses and the presence of higher than nor-mal eddy current. High magnetizing current can be asign of problem with the steel core. The cost to oper-ate a transformer with high losses may be prohibitivein certain cases. High losses indicate that thetransformer will run at higher than normal tempera-ture, leading to a shorter life.

5Page two of the shop final test report for 10XF-1, 1,000-kVA unit.

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The Karl Fisher test was included in the criteria becausetransformers having high moisture content for long periodsof time can cause degradation of paper. Also, considerablewater in the oil causes sludge that attacks paper as well.

Transformer HistoryMost transformers shown in Table 2 operate in a severecorrosive environment, carrying motor loads equal toat least 75% of full load capacity. There are no nonlin-ear or variable frequency drive loads. There are small20-kVA UPS systems loads on two of the transformerin Table 2. Transformer 10XF-4 was exceptional; itoperated at 107% for a minimum of 50 years beforefans were installed. The transformer in Figure 6exhibits signs of severe overheating when comparedwith the transformer in Figure 1 operating at 80%loaded for 51 years; both transformers suffered from

6Transformer 10XF-4, core and windings, 1,000-kVA unit.

(a) (b)7

(a) 10XF-4 and (b) 12XF-3 tap changers.

(a) (b)

8(a) Damaged tap changer compared to (b) repaired tap changer.

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loose connections between station-ary and movable contacts on the tapchanger (see Figures 7 and 8 for tapchanger damage). Both transform-ers were made by the same manufac-turer around the same time withboth rated at 1,000 kVA and 4,160V/480 V.

Most transformers listed in Table 2were installed in the 1950s when theproduction unit was initially built.The loading of each transformer forapproximately 50 years are tabulatedin Table 3. Loading is used as one ofthe criteria to determine whether toreplace or repair. All transformersrepaired were returned into service,except two units.

Transformers were monitored after repairs were com-pleted. It was observed that the older unit’s radiators werecooler than a similar newer unit, operating at the sameamperes and voltage. The radiator tubing diameters werelarger and greater in number than the newer unit. Thiswas observed by the use of the hand. The oil temperaturegauge appears to be slightly higher, about 48 �C on thenewer unit, while the older unit at around 45 �C. Theseare estimates because the scale markings are not welldefined to show distinct differences.

Cost of Operating Older Units Versus NewInitially, it appeared that the efficiency of the older unitswere more efficient than the newer units based on mag-netizing currents. A comparison was made between newtransformers versus old to account for operating cost.The operating cost was negligible based on the presentUS$0.05/kWh from the company cogeneration unit’snext door. Newer transformers are required to operate atcertain efficiencies per new U.S. Department of Energy(DOE) regulations.

ANSI/IEEE C57.100 provide criteria for end-of-lifetransformers. Experience and experimental evidence indi-cate that an insulation system is capable of operating60,000 h for approximately seven years.

Recommendation to Repair or ReplaceTable 3 shows an overall picture of the problems andresults of test performed on each. Many of the newerunits appeared to be smaller with a better insulation PF.Three new transformers were purchased based on thecriteria used.

ConclusionsTransformers have many criteria that can deem them at theend of life; however, there is no way one can accurately pre-dict the date or an interval when a transformer will fail. Onecan only use principles and guidelines taken from previousexperiences when it comes to replacing transformers. Manyprovide symptoms of imminent failure, and one should heedto those symptoms and repair or replace based on soundengineering judgment. The following philosophy, shown inTable 3, was developed as a guide to determine when atransformer should be replaced. The study did reveal,

without question, one main point;transformers with disk design appear tobe more robust and last longer than 50years. However, some of those unitshave experienced severe overloadingbecause of added loads over a periodof 59 years. Based on performance,age, design, test results, cost feasi-bility, vintage, and loading, oneshould carefully weigh criterialisted to determine when atransformer should be replaced. Inthe case of this study, the mainproblems were loose springs on thetap changer and movable andstationary contacts on the olderunits. The older transformerappears to operate cooler than

newer units built after 1980. This is not to say olderis always better, but in this particular study, olderunits were better.

AcknowledgmentsThe authors thank our respective companies for allow-ing the time to write and present this article. We alsothank Tom Langley of Alamo Transformer SupplyCompany for his help in gathering the material forthis article.

References[1] Guide for The Interpretation of Gases in Oil-Immersed Transformers, ANSI/

IEEE C57.104-2008.[2] Guide for Acceptance & Maintenance of Insulating Oil in Equipment, ANSI/

IEEE C57.106-2006.[3] National Electrical Code, NFPA 70, 2008 Article 450.9.[4] A. C. Franklin and D. P. Franklin, The J&P Transformer Book, 11th

ed. London, U.K.: Butterworth Publishing, 2003.[5] S. D. Myers, Transformer Maintenance Inst. Akron, OH, 1981.[6] Gold Book Recommended Practice for Design of Reliable Industrial and

Commercial Power Systems, ANSI/IEEE Standard-493, 2007.[7] Standard Test Procedure for Thermal Evaluation of Oil Immersed Distribu-

tion Transformers, ANSI/IEEE C57.100-2007.[8] Central Station Engineers. Electrical Transmission and Distribution Reference

Book. Westinghouse Electric Corporation, 1964.[9] Installation, Operation and Maintenance of Combustible Gas Detection

Instruments, ISA (Instrument Society of America) ANSI/ISA-S12.13Part II-1987.

[10] Hazardous Chemicals Data, NFPA 49-1975.[11] Fire Hazard Properties of Flammable Liquids, Gases, and Volatile Solids, NFPA

325M-1984.[12] M. G. Zabetakis, “Flammability characteristics of combustible gases

and vapors,” Bureau of Mines, Bull. 627.[13] “Use of Doble power-factor insulation tests,” UOD-1801, Doble Eng.

Company, Watertown, MA.[14] Standard Test Method for Measurement of Average Viscometric Degree of

Polymerization of New and Aged Electrical Papers and Boards, ASTM-D4243.

[15] OSHA 29CFR 1910.119 Part J.[16] Test Method for Furanic Compounds in Electrical Insulating Liquids by High

Performance Liquid Chromatography (HPLC), ASTM D5837, 2006.

Fred L. Dixon (dixonfl@cpchem.com) is with Chevron Phillips inOld Ocean, Texas, and Dave Steward and James Hoffmeister arewith Alamo Transformer Supply Co. in Houston, Texas. Dixon,Steward, and Hoffmeister are Members of the IEEE. This articlefirst appeared as “When to Replace Aging Transformers” at the2010 Petroleum and Chemical Industry Conference.

THE MOSTSIGNIFICANTPART OF A

TRANSFORMERTHAT DETERMINES

LIFE IS THEINSULATIONSYSTEM.

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