ML12334A494
| ML12334A494 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 12/12/2011 |
| From: | Edson J, Jackson J, Roberts E, Udy A Idaho National Engineering Lab (INEL), Office of Nuclear Regulatory Research |
| To: | |
| SECY RAS | |
| References | |
| RAS 21523, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01, NYS000012, Job Code A6389 INEL-95/0573, NUREG/CR-5753 | |
| Download: ML12334A494 (66) | |
Text
United States Nuclear Regulatory Commission Official Hearing Exhibit NYS000012 Entergy Nuclear Operations, Inc. Submitted: December 12, 2011 In the Matter of:
(Indian Point Nuclear Generating Units 2 and 3) c.\.~P.R REGlJ~" ASLBP #: 07-858-03-LR-BD01 P~~"
Docket #: 05000247 l 05000286 Exhibit #: NYS000012-00-BD01 Identified: 10/15/2012 I-
~ -'
~
0'!:
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Admitted: 10/15/2012 Withdrawn:
~4: O~ Rejected: Stricken:
" ** ** ... ... Other: NUREG/CR-5753 INEL-95/0573 lA.ging of Safety Class li E Transformers in FEB 2 7 12gS ISafety Systems of 0ST'
,Nuclear Power Plants
- Prepared by
. E. W. Roberts, J. L. Edson, A. C. Udy
- Idaho National Engineering Laboratory Lockheed Idaho Technologies Company Prepared for U.S. Nuclear Regulatory Commission i
DISTRIBUTION OF THIS DOCUMENT IS UNU~TEO <f'/Z MASTER
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OAGI0001164_00001
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OAGI0001164_00002
NUREG/CR-5753 INEL-95/0573 Aging of Safety Class IE Transformers in Safety Systems of Nuclear Power Plants Manuscript Completed: November 1995 Date Published: February 1996 Prepared by E. W. Roberts, J. L. Edson, A C. Udy Idaho National Engineering Laboratory Lockheed Idaho Technologies Company Idaho Falls, ill 83415 J. Jackson, NRC Project Manager Prepared for Division of Engineering Technology Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 NRC Job Code A6389 OAGI0001164_00003
OAGI0001164_00004 ABSTRACT This report discusses aging effects on safety-related power transformers in nuclear power plants. It also evaluates maintenance, testing, and monitoring prac-tices with respect to their effectiveness in detecting and mitigating the effects of aging. The study follows the U.S. Nuclear Regulatory Commission's (NRC's)
Nuclear Plant-Aging Research approach. It investigates the materials used in trans-former construction, identifies stressors and aging mechanisms, presents operating and testing experience with aging effects, analyzes transformer failure events reported in various databases, and evaluates maintenance practices. Databases maintained by the nuclear industry were analyzed to evaluate the effects of aging on the operation of nuclear power plants.
iii NUREG/CR-5753
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OAGI0001164_00005
OAGI0001164_00006 CONTENTS ABSTRACT . . . . . . . . . . . . . * . . . . . . . . * . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii LIST OF FIGURES . . . . . . . . . . . . . . . . . . . * . . . . . . . . . . . . . . . . . . . . . . . . . . . . * . . . . . . . . . . . . . . vii LIST OF TABLES .*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . * . . . . . . . . * . . vii EXECUTIVE
SUMMARY
.............................................*........*.. ix
- 1. INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . * . . . . . . . . * . * . . . . . . . . 1
- 2. POWER TRANSFORMERS ....*....................*......................... 3 2.1 Transformer Construction .............**................................. 3 2.1.1 Core and Windings .....................................*..*..... 3 2.1.2 Solid Insulation ................................................ . 3 2.1.3 Insulating/Cooling Medium ..*.......................*............ 5 2.1.4 Transformer Bushings ....................*....*.......*.......... 7 2.1.5 Transformer Tank (enclosure) ......**.....................*........ 7 2.2 Transformer Cooling Systems ............................................. 7 2.3 Load Tap Changers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
- 8
- 3. SIGNIFICANCE OF AGING. * . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 3.1 Major Transformer Components ........................................... 15 3.2 Construction Materials. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . * . . 18 3.3 Transformer Loading .................................................... 18 3.4 Transformer Capacity Considerations ....................................... 18
- 4. TRANSFORMER AGING MECHANISMS .................................**...* 21
- 5. REVIEW OF OPERATING EXPERIENCE .................**.......*....*...*... 24 5.1 Types, Applications, and Descriptions of Safety Class IE Power Transformers. . . . . . . 25 5.2 Transformer Age ....*.................................................. 25 5.3 Transformer Problems, Failures, and Replacements ................*........... 25 5.4 Trends. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . * . . . . . . . . . . . . . . . . . . . * . . . . . . . . . . . . . 27 5.5 NRC IE Information Notices. . . . . . . . . . . . . . . . . .* . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 5.6 Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . * . . . . . . . . 28
- 6. TRANSFORMER RISK ANALYSIS . . . . . . . . * . . . . . . . . . . * . . . . . . . . . . . . . . . . . . . . . . . . . 30 v NUREG/CR-5753 OAGI0001164_00007
- 7. TRANSFORMER INSPECTION, SURVEILLANCE, MONITORING, AND MAIN1ENANCE ....**...*...**.............**....*...*....*................ 31 7.1 Guidance for Maintenance, Surveillance, Monitoring, and Inspection ............. , 31 7.1.1 Oil-Filled Transformers .....*.................*..*.............*. 31 7.1.2 Dry-Type Transformers. * . . . . * . . . . * * . . . . . . . . . . . . . . . . . * * . * * . * . . . . . . 38 7.1.3 Gas-Cooled Transformers. . . . . . . . . . . . . . . . . . . . . . . . . . * * . . . . . * . . . * . . . 40 7.2 Current Maintenance Practices for Safety Class IE Transformers *.*.*............ 41 7.3 Comparison of Typical and Current Maintenance Practices .....*.............*.* 41 7.4 Functional Indicators of Transformer Degradation ...............*....***..*.*. 42
- 8. REVIEW OF STANDARDS, GUIDES, AND DESIGN CRITERIA RELATED TO TRANSFORMER AGING ......**....*.....*...............*.....*...*.*...**. 43
- 9. CONCLUSIONS. . . * . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . * . . * . * * . . * * . * . . . . . 50
- 10. BffiLIOGRAPHY............................................................ 52 NUREG/CR-S7S3 vi OAGI0001164_00008
LIST OF FIGURES 2-1. Typical nuclear power station electrical diagram .................................... 4 2-2. Basic components of a power transformer ......................................... 5 2-3. Electrical diagram of power transformer load tap changer. . . . . . . . . . . . . . . . . . . * . . . . . . . . . 8 3-1. Comparison of windings used for core- and shell-form transformers .................... 17 5-1. Class IE and nonclass 1E power transformer problems and failures listed by year. . . . . . * . . . 28 LIST OF TABLES 2-1. Components for air-cooled power transformer . . * * * . . . . . . . * * . . . . . . . * * . * . . . . . . . * . . . . . 9 2-2. Components for nitrogen- or fluorogas-cooled power transformer ...............*.....* 10 2-3. Components for low voltage <<15 kV) fluid cooled power transformer .................. 11 2-4. Components for high voltage (> 15 kV) mineral oil-cooled power transformer ........*... 12 2-5. Components of power transformer cooling systems . . . . . . * . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 3-1. Components of power transformers and materials of construction .....*................ 16 3-2. Component stressors and failure mechanisms ..........*.........................*. 19 5-1. Type cooling for NPRDS-listed Class IE power transformers. . . . . . . . . . . . . . . . . . . . . . . . . . 25 5-2. Voltage ratings of NPRDS-listed power transformers ....*........................... 25 5-3. Age of NPRDS-listed safety Class IE power transformers *........................... 25 5-4. Reported safety-related transformer problems .****..**..*.*.......**............... 26 5-5. Transformer problems by cooling type (1983 through May 1991) ..........*........**. 27 7-1. Maintenance intervals for oil-filled transformers .....................*.............. 32 7-2. Maintenance intervals for dry-type transformers ....*.............*................. 39 7-3. Maintenance intervals for gas-cooled transformers .*........*........*.............. 41 7-4. Maintenance practices for oil-filled transformers at a typical nuclear power station. . . . . . . . . 42 7-5. Functional indicators of transformer degradation. . . . . . . . . . . . . * . . . . . . . . . . . . . . . . . . . . . . 42 8-1. Acceptance criteria and guidelines for electric power transformers . . . . . . . . * . . . * . . . . . . . . . 43 8-2. Industry standards applicable to Class IE power transformers .....***...........**.... 44 vii NUREG/CR-5753 OAGI0001164_00009
OAGI0001164_00010 EXECUTIVE
SUMMARY
Power transformers of various sizes and types that the aging of transformers is causing signifi-operate in the Class IE power systems at nuclear cant problems or that there is an increasing num-facilities throughout the United States. Continued ber of problems and failures. However, because safe and reliable operation of these transformers of the relative young age of the Class IE trans-is critical to the overall safe operation of the formers it is difficult to determine if this is an nuclear facility. Therefore, it is important to iden- accurate picture of the effects of transformer tify the aging mechanisms and their effects that aging at the nuclear plants.
can lead to transformer failure and to implement maintenance and testing practices that can identi- A standard probabilistic risk assessment (PRA) fy and alleviate the effects of these aging was reviewed to determine the risk significance mechanisms. of Class IE transformers and the potential for aging to increase the risk significance. The fault This report describes a study that was spon- trees for the PRA included transformers along sored by the U.S. Nuclear Regulatory Commis- with other Class IE components. Truncation of sion and performed at the Idaho National the cut sets still left the transformers as poten-Engineering Laboratory to evaluate aging effects tially risk-significant components. Reevaluation on Class IE power distribution transformers in with a unity failure probability for the most risk-nuclear power plants. The study identifies materi- significant type of transformer shows that aging als used in transformer construction, stressors, of the transformer has the potential to signifi-and aging mechanisms; presents data on Class IE cantly increase core damage frequency. Aging is transformer failure events as reported in various an important factor for the most risk-significant databases; and compares current transformer transformers.
maintenance and testing procedures.
An example maintenance program was devel-Transformer data from the NRC Licensee oped for oil, gas, and air-cooled power trans-Event Reports (LERs), the Nuclear Plant Reli- formers using industry and manufacturer's ability Data System (NPRDS), and the Nuclear recommendations. The maintenance program for Power Experience data system were reviewed to an operating nuclear station was examined and determine if evidence of transformer aging compared with the developed program. The pro-effects could be found in the nuclear plant operat- gram compared favorably with the example ing experience. A cooperating utility provided program, with only minor deviations.
manufacturing data, operating experience data, and maintenance information for the study. Main- It is our conclusion that there is no presently tenance practices and scheduling information identified transformer aging mechanism that were obtained from an operating nuclear station. would cause a safety concern. If nuclear plants use currently recognized monitoring and testing Using the information from the above sources, methods and follow a rigorous surveillance, test-transformer records were examined for 88 plants ing, maintenance, and replacement program for the years of 1983 through 1990. During this (based on current and future manufacturers and period, 33 disabling problems and failures were industry guidelines) the effects of transformer reported on the 723 Class IE power transformers aging will not increase the risk to nuclear plant listed in the NPRDS. Five of the reported safety. These conclusions are based on our review incidents resulted in reportable events (LERs). of (a) the transformer aging mechanisms, (b) the The data for the 88 plants also show that 95% of accepted transformer monitoring and testing the Class I E transformers were under 20 years methods, (c) the manufacturer's and industry old, and nearly 75% are less than 15 years old. transformer maintenance and surveillance guide-The low number of problems occurring on the lines, (d) the current transformer surveillance and Class IE power transformers give little indication maintenance practices at an operating nuclear ix NUREG/CR-5753 OAGI0001164_00011
station, and (e) the transformer plant operating the effects of transformer aging or the current experience for 88 nuclear plants. surveillance and maintenance practices in the However, it is our opinion that owing to the age industry. Review of plant operating data (approxi-of the Class 1E power transformers in use at mately every 5 years) would be useful in deter-nuclear plants (which are relatively young in mining if present information remains accurate comparison to the expected transformer life), the and in determining if any significant unidentified past operating experience may not truly reflect trends are developing.
NUREG/CR-5753 x OAGI0001164_00012
Aging of Safety Class 1E Transformers in Safety Systems of Nuclear Power Plants
- 1. INTRODUCTION The U.S. Nuclear Regulatory Commission mitigate the effects of aging and to diminish (NRC) initiated the Nuclear Plant-Aging the rate and extent of degradation caused by Research Program (NPAR) to obtain a better aging and service wear.
understanding of how degradation caused by ag-The NPAR Program is being conducted at ing of key components could affect nuclear plant several national laboratories, including the Idaho safety, if not corrected before loss of functional National Engineering Laboratory (INEL).
capability, and how the aging process may change the likelihood of component failures in systems A nuclear plant typically has between 4 and that mitigate transients and accidents. The possi- 12 Class IE power transformers supplying the bility of aging degradation causing accidents is many safety-related systems and equipment.
also a concern. Reliability of these transformers is essential to ensure continued safe operation of the plant. Even This report presents an engineering study of though sufficient redundancy is provided so that power transformers used in safety-related appli- failure of only one transformer will not place the cations. While the IE power system includes plant in an unsafe condition, the failure of one other transformers, such as current, potential, transformer does result in challenges to plant control, and instrumentation transformers, these operation (such as reactor scram) and reduces the transformers are not included in this study. Con- reliability and redundancy aspects of the IE trol transformers, which are commonly found in power system. This study attempts to resolve two motor control centers, are included in an aging issues: (a) whether aging of transformers is assessment of motor control centers reported in expected to significantly reduce reliability during NUREG/CR-5053. Control transformers are sim- their installed lifetime, and (b) whether careful ilar to current and potential transformers. There- monitoring and maintenance would improve or fore, this study focuses on power transformers. ensure reliability over their service life.
The work supports the NPAR goals stated in NUREG-Il44, summarized as follows: Section 2 describes the power transformers themselves and the components they use; Sec-
- Identify and characterize aging and service- tion 3 describes the materials used; Section 4 wear effects associated with electrical and reviews transformer failure modes; Section 5 mechanical components, interfaces, and reviews operating experience using various data-systems likely to impair plant safety. bases and plant specific information; Section 6 addresses transformer aging risk analysis; Section
- Identify and recommend methods of inspec- 7 discusses transformer inspection, surveillance, tion, surveillance, and condition monitoring monitoring. and maintenance; Section 8 reviews of electrical and mechanical components standards, guides, and design criteria applicable to and systems that will be effective in the Class IE power transformers; and Section 9 detecting significant aging effects before presents conclusions.
loss of safety function, so that timely main-tenance and repair or replacement can be This study used two databases to evaluate the implemented. effects of aging on transformers in nuclear power plants: the Nuclear Power Experience database
- Identify and recommend acceptable mainte- (NPE) and the Nuclear Plant Reliability Data nance practices that can be undertaken to System (NPRDS). In addition, Licensee Event 1 NUREG/CR-5753 OAGI0001164_00013
Introduction Reports (LERs) were used to identify transfonn- failure causes and effects on plant operation.
ers failures that resulted in events that were Because this study was on the effects of power reportable to the NRC. During this study, it was transfonner aging, the decision was made not to determined that the NPRDS was the only use the transformer data on plants placed in ser-infonnation source with nameplate data on Class vice after January 1, 1989. Subsequent review of IE power transformers. For this reason, the NPRDS data shows that only 88 other plants had NPRDS was used to identify specific types and Class IE transformer nameplate data included in ages of transformer that experienced failures. All the database. The information from these plants of the infonnation sources were used to identify was used in the study.
NUREG/CR-5753 2 OAGI0001164 00014
- 2. POWER TRANSFORMERS Figure 2-1 shows a typical nuclear plant elec- different numbers and location of power trans-trical distribution system with the associated formers, the information on the construction, power transformers. The maximum voltage for aging, and maintenance of transformers applies to transformers, electrical buses, and electrical all transformers used in nuclear plants.
equipment within the dashed line is 15 kV. The voltages on the high-voltage winding (primary) The sections that follow describe the basic ele-of transformers, located outside the dashed line, ments of the Class IE power transformers for the varies between 15 and 500 kV, depending on the 88 nuclear plants used in this study. Transformers individual plants and the connected commercial have many special design and construction meth-power system. ods for cores, windings, tanks, bushings, load tap changers, and other elements. No attempt has During this study, NPRDS transformer records been made to describe these design and construc-were reviewed for 88 nuclear plants. NPRDS tion methods.
event records and engineering data show that 19 of the plants list a total for 50 Class IE high- 2.1 Transformer Construction voltage (> 15 kV) transformers. The high-voltage rating for these transformers varied between 19 Figure 2-2 shows the basic components of and 500 kYo The transformers use a liquid insula- power transformers. As the figure shows, the basic tor/coolant, usually mineral oil. These high- transformer components include a silicon-steel voltage transformers have forced-air and core, primary and secondary windings (with con-forced-oil supplementary cooling. The 88 plants nections to the bushings), solid insulation, the win-have 673 Class IE low-voltage <<15 kV) trans- ding/core insulator/coolant medium, a transformer formers, with 70 of these using liquid insulation/ tank enclosure, and the primary and secondary coolant (mineral oil or noninflammable fluid), 50 bushings. Tables 2-1 through 2-5, located at the end using a flourogas insulation/coolant, and 553 of Section 2 (beginning on page 9), show all of the using air as the insulation/coolant. A review of components normally used for air, nitrogen, and the electrical diagrams for several of the 19 plants fluorogas, and low- and high:voltage fluid-cooled listed as having 1E high-voltage transformers and transformers, respectively.
conversations with persons with inplant experi-ence indicate that none of these high-voltage 2.1.1 Core and Windings. Power transform-transformers are likely to be actually classified as ers are constructed using separate copper or alu-IE. However. with the exception of some of the minum primary and secondary windings on a auxiliary equipment on the high-voltage trans- silicon-steel core. Upon applying an ac voltage to formers. such as load tap changers and forced-oil the primary winding, a corresponding varying cooling. descriptions and failure mechanisms are magnetic flux is created in the core. The magnetic generally applicable to both high- and low- flux in the core, in turn, induces a voltage on the voltage liquid-filled transformers. In addition, secondary winding. Some transformers have mul-failure of these nonsafety-related transformers tiple windings allowing power to be transformed usually has a significant impact on the operation to different voltages. The input to output voltages of the plant, such as reactor scram, actuation of are a direct ratio to the number of turns on each emergency power sources, or loss of redundancy. winding. The use of power transformers allows Therefore. the high-voltage transformers classi- power to be transmitted at high voltages fied as IE by NPRDS, though probably not actu- (reducing line losses) and then lowered to usable ally IE, will be included in this report. voltages.
Although individual plants have different 2.1.2 Solid Insulation. To prevent electrical power supply circuitry and corresponding shorting between adjacent turns and between 3 NUREG/CR-5753 OAGI0001164_00015
Transmission lines Note - Voltages vary with plant-specific designs. Voltage ranges are listed below.
~~
~
A Bus voltage: 4160-13800 Vac B Bus voltage: 208-600 Vac C Bus voltage: 208-600 Vac D Bus voltage: 125 or 250 Vdo Q ::?
....... ~
~
E Bus voltage: 120 or 240 Vac Main transformer F Battery voltage: 125 or 250 Vdc CP w
Transmission IInesJ....
6! Maln::C generator System aux transfQ.([ller
""T" "'I!~I-----Unlt aux transformers
. ) NC
~ ~
MCC motor control center. ..
NO normally open NC normally closed
- - - - Class 1E power system boundary ~
.j::..
F o Manual ~e breaker I.-_J..<-_ _- ,
DC contror bus II Q I Reactor protection channel Reactor protection channel CJ'!f!.~ 11!p_o_"!.e!_sy!!e..".!_b_o_u_n~aD!. _____ ______ ;- __*_____________________ _
- - - --- -- -- - - - - - - - - - - - --.- - - -- -- - -- -- ---- -- - - - -- - - ---- -- Tram 2 Train 1
- *Traln 21s Identical to Train 1 C 148*WHT.l195-0I Figure 2*1. Typical nuclear power station electrical diagram.
Power Transfonners low voltage High voltage bushings (2) bushings (2)
(secondary) (primary)
Tank (enclosure)
Low voltage r------ ..
winding (secondary) High voltage winding (primary)
Insulator/coolant medium I I
IL _ _ _ _ _ _ J Winding and wire insulation T920696 Figure 2-2. Basic components of a power transformer.
separate windings, various methods and materials as good as, or in some cases better than, the wind-are used to provide the necessary dielectric ing insulation. Although different materials and strength (insulation) between the winding turns, designs are used in transformers, all power trans-the high- and low-voltage windings, the magnetic formers use either a gas or liquid insulating core, and other electrical conductive materials. medium to surround the solid insulation. These The insulating methods include applying layer insulating mediums prevent the entry of contami-insulation or coil insulation between parts of nants. In addition, the insulating medium serves windings and applying tum insulation between another critical function; it transfers the heat gen-individual or groups of strands forming a single erated by core and winding losses to the atmo-turn. The materials used are described in sphere. Without this heat removal, the life of the Section 3 of this report. solid insulating materials would be significantly reduced. Note also that because the liquids and 2.1.3Insulating/Cooling Medium. The trans- gases are critical to cooling the transformer core, former winding and wire insulation materials the terms type insulated and type cooled are have the necessary dielectric strength to prevent interchangeable.
electrical shorting between individual winding turns, the windings, the core, and other electrical 2.1.3.1 Liquid-Cooled Transformers.
conductive material. However, entry of contami- The liquid coolants in power transformers are nating materials to the winding insulation is a mineral oil or various low-flammability fluids.
threat to the transformer operation. Water is the Mineral oil has a characteristic of high dielectric most frequent contaminant experienced during strength, an ability to recover after high dielectric transformer operation. All contaminants have the stress, and an excellent heat transfer capability.
potential to reduce the dielectric strength of the Because of its high dielectric strength, mineral oil winding insulation and can compromise the elec- is used in all transformers with high voltages over trical insulation. 34 kV. In addition, because of its heat transfer capability, mineral oil is the most efficient To prevent the entry of contaminating materi- medium to remove internal heat from power als, the transformer solid insulation is surrounded transformers and prevent excessive temperatures by an insulation medium with a dielectric strength that shorten the life of the transformer. However, 5 NUREG/CR-5753 OAGI0001164_00017
Power Transformers mineral oil is very flammable. Mineral oil-cooled
- Maintaining a pressurized nitrogen atmo-transformers cannot be located where a sphere above the oil in the sealed tank. A transformer fire would be a hazard to other low nitrogen gas pressure is maintained equipment or buildings. Mineral oil-cooled using nitrogen cylinders, pressure gauges, transformers are used for all high-voltage and pressure regulators.
(> 15 kV) transformers.
- Using a sealedflexible diaphragm on top of the oil inside the sealed tank with an air Although transformer oil is a highly refined space above the diaphragm. A flexible dia-product, it is not chemically pure. It is a mixture phragm completes the seal between the oil of hydrocarbons with other natural compounds, in the tank and the air space. The diaphragm some of which are detrimental to the oil and oth-is able to accommodate expansion or con-ers beneficial in retarding the oxidation of the oil.
traction of the oil and oil leaks.
Oil impurities are destructive to dielectric proper-ties. The most troublesome impurities are water, The other types of fluids used for liquid insu-oxygen, and the many combinations of com- lated transformers are Askarel, silicones, high-pounds formed by water and hydrogen (acids) at flash-point hydrocarbons, chlorinated benzenes, elevated temperatures. Under ideal conditions, or chlorofluorocarbons. Because of environmen-only very small amounts of water will dissolve in tal concerns, transformers using Askarel are no a true solution with the oil. Small amounts of dis-longer manufactured and are being phased out of solved water have little affect on the dielectric service. The low flammability types of insulating strength of the oil. However, the presence of acids fluids have a much lower dielectric constant and increases the amount of water that will be dis- can only be used in transformers with a voltage solved, reducing the dielectric strength of the oil less than 34 kV. These transformers do not trans-accordingly. The oil-water solution will be subse- fer heat as well as mineral oil; however, they quently absorbed by the* paper and paperboard transfer heat much better than gas-insulated trans-used in the winding insulation. The result will be formers. Transformers using these types of insu-a decrease in the dielectric strength of the insulat-lating fluids can be used inside of buildings.
ing materials and an accelerated aging of the These transformers use a sealed case with a gas paper. The problem of air and water in space above the fluid.
transformer oil can be minimized by eliminating them from, and keeping them out of, the trans- 2.1.3.2 Gas-Cooled Transformers (Dry).
former oil. For this reason, all oil-cooled trans- Gas-cooled transformers, commonly known as formers are completely sealed. There are three dry type transformers, use air, fluorogas, or nitro-basic methods used in nuclear plant transformers gen as the insulating coolant. Air has a low to perform these functions and permit normal dielectric strength and low heat transfer capabil-expansion and contraction of the transformer oil ity. To make full use of the limited heat transfer without disturbing the integrity of the seal. capabilities of air, most transformers of this type are usually not sealed and are ventilated to the
- Leaving an air space above the oil in the surrounding atmosphere. To prevent the intrusion sealed tank. The small amounts of water and of contaminants, including water, the transform-oxygen present in the air will be absorbed, ers are located in a clean and dry atmosphere.
leaving a space filled with the nitrogen gas This type of transformer is used in nuclear plant from the air. This method is used for Class IE power supply systems with a maximum transformers with voltages below 15 kV. voltage less than 15 kV.
Although unconfirmed, it is believed that there are no Class 1E transformers in the Nitrogen-cooled transformers have dielectric 88 plants reviewed that use this method to and heat transfer characteristics similar to dry air.
maintain the integrity of mineral oil-filled Nitrogen insulated transformers require a sealed transformers. case; pressure monitoring instruments, and a NUREG/CR-5753 6 OAGI0001164_00018
Power Transformers means to add nitrogen. They may be used in con- bolted steel plates. A transformer tank may taminated atmospheres. enclose multiple windings and cores. Normally, a three-phase transformer will have the windings Fluorogas-cooled transformers have better and cores for all three phases in one tank.
dielectric strength and heat-transfer capacity than air or nitrogen. The dielectric strength and the 2.2 Transformer COOling heat-transfer capability increase with density of Systems the fluorogas. For this reason, fluorogas-insulated transformers are used with the internal gas pres- An important part in the operation of the trans-sure above atmospheric pressure, in some cases former is preventing high core/winding tempera-with a 3-atm gauge pressure. As with the nitrogen tures that would shorten the life of the electrical insulated transformers, the fluorogas transformer insulation. Almost all modem transformers have requires a sealed transformer case, gas pressure insulation systems designed for operation at 65°C monitoring instruments, and a means to add average and 80°C hot spot winding temperature fluorogas. This type of transformer is used in rise over an ambient temperature of 30°C. Older place of air-cooled transformers in contaminated transformers were designed with a 55°C average atmospheres where the space is limited and and 65°C hot spot rise over a 30°C ambient tem-increased load handling capability is required.
perature. All power transformers are designed to maintain the transformer temperatures within 2.1.4 Transformer Bushings. A transformer these limits when the transformer load is within bushing is a structure that provides an insulated the nameplate rating. There are three methods passageway through the transformer tank wall for used to remove the winding/core heat from power an electrical conductor. The bushing allows exter- transformers: (a) natural convection (self-nal connections to be made to transformer inter- cooled), (b) forced-air, and (c) forced-oil cooling.
nal electrical parts without violating the tank A self-cooled transformer mayor may not have internal integrity (sealing). The power trans- an external radiator(s); forced-air and forced-oil former bushings are designed with insulation cooling requires them. Self-cooled is inherent, capable of handling the dielectric stresses in the and forced-air cooling can be applied to all trans-transition through the transformer tank to the con- formers. A forced-oil system uses a pump to nection to electric wire or cables. Porcelain is move the hot oil above the windings and core to used for the exposed bushing surfaces. Bushings the forced-air cooling radiator. The cooled oil is used outside andlor in contaminated atmospheres, returned to the bottom of the transformer. All of are designed with one or more (depending on the 50 high-voltage transformers examined have voltage and atmosphere) skirts to prevent normal forced-air and forced-oil cooling. Forced-oil moisture or other contamination from making an cooling was not used on any lower voltage electrical path across the porcelain. As the volt- Class IE transformers. Each transformer has a ages are increased, the transformer bushings self-cooled electrical load rating (kVa). Increas-require an increased dielectric strength. The bush- ing kVa ratings are allowed for each additional ings use insulation materials similar to those used cooling capability included on the transformer.
in a transformer, including mineral oil in their Secondary water cooling is also used on high-internal construction. power transformers; however, this type of supple-mentary cooling is not used on any of the 2.1.5 Transformer Tank (enclosure). All transformers for the plants reviewed. Forced-air power transformers have a steel enclosure for the and forced-oil cooling systems have temperature winding and core. This enclosure provides both a transducers, control systems, and fan/pump physical barrier to the electric parts and a sealed motors to maintain transformer temperatures container for the liquids and gases (excluding air) below set limits. Note that the failure- of any used as an insulator and coolant medium. The forced cooling system requires the corresponding enclosures are made using both welded and reduction in transformer loading.
~~~--_._~_.- -
OAGI0001164_00019
Power Transfonners 2.3 load Tap Changers lating currents through the shunt and connecting contacts, a small amount of arcing is always pres-ent during the changing of taps. Because of the Anumberofthehigh.voltage (>15 kVA) trans* contact arcing, the load tap changer contacts and fonners used in the nuclear plants have load tap winding connections are always located in a changing (LTC) equipment. This equipment sealed oil-filled compartment that is isolated from enables the transfonner to automatically maintain the transfonner core and windings. An external a constant voltage (+/-2.5%) for plant equipment motor mechanism drives the internal shunting under variable offsite power conditions. As contacts. This mechanism includes the necessary shown in Figure 2*3, the regulation is perfonned gearing, mechanical coupling, cam-operated by increasing or decreasing the active turns in the stepping switches, and other equipment to step high-voltage winding. To prevent load interrup- the internal tap contacts. Voltage measuring and tion, the change is made by shunting one winding tap changer motor controls allow both a variable load tap to another without opening the winding. time delay and voltage operational band to pre-Although special methods are used to limit circu- vent unnecessary wear of the system parts.
.i .i i !
i !
i !
Low voltage 1 i High voltage i i (Primary)
(secondary) i !
1 1
i Stepping shunt i
i 1
i
... 1 Figure 2-3. Electrical diagram of power transfonner load tap changer.
NUREG/CR-5753 8 OAGI0001164_00020
Power Transfonners Table 2-1. Components for air-cooled power transfonner.
Component Use Comments Windings High- and low-voltage windings. There may be multiple low-Tertiary windings. voltage windings.
Silicon-steel core Contains magnetic flux for voltage induction between core windings.
Solid insulation Electrical insulation between winding turns, windings, and all electrical conductive materials.
Tank (enclosure) Physical protection for electrical Unsealed and normally parts. May enclose multiple ventilated to atmosphere.
windings and cores.
Bushings Structure to provide for termina- Separate bushings are required tions and insulated pathway for each connection to through transformer tank wall for transformer winding.
electrical conductor.
Temperature indicator Indication of interior and ambient May include alarm and temperatures. contacts. Sensor location depends on design specifications.
Radiator Forced-air cooling. Required for forced-air cooling.
Fan(s) and motor(s) Forced-air cooling. Required for forced-air cooling.
Temperature transducer Control of forced-air cooling. May be included with (contacts) temperature indicator.
Fan motor controller(s) Controls fan motors for forced-air cooling.
9 NUREG/CR-5753 OAGI0001164 00021
Power Transformers Table 2-2. Components for nitrogen- or fluorogas-cooled power transfonner.
Component Use Comments Windings High- and low-voltage windings. There may be multiple low-Tertiary windings. voltage windings.
Silicon-steel core Contains magnetic flux for voltage induction between core windings.
Solid insulation Electrical insulation between winding turns, windings, and all electrical conductive materials Tank (sealed enclosure) Physical protection for electrical Sealed from outside parts. May enclose multiple atmosphere under nitrogen or windings and cores. fluorogas pressure.
Bushings Structure to provide for tennina- Separate bushings are required tions and insulated pathway for each circuit connection to through transfonner tank wall for transfonner winding.
electrical conductor.
Fluorogas insulator Provides fluorogas, controls tank Fluorogas insulated coolant cylinder(s)/ pressure, and provides indication of transfonners.
regulator/control tank interior pressure.
Nitrogen insulator/ Provides nitrogen gas, controls tank Nitrogen insulated transfonners.
coolant cylinder(s)/ pressure, and provides indication of regulator/control tank interior pressure.
Temperature indicator Indication of interior and ambient May include alarm and contacts.
temperatures. Sensor location depends on design specifications.
Radiator (fins) Forced-air cooling. Required for forced-air cooling.
Fan(s) and motor(s) Forced-air cooling. Required for forced-air cooling.
Temperature transducer Start-stop forced-air cooling. Required for forced-air cooling.
(contacts) May be included with temperature indicator.
Fan motor controller(s) Controls fan motors for forced-air Required for forced-air cooling.
cooling.
NUREGfCR-5753 10 OAGI0001164_00022
Power Transfonners Table 2*3. Components for low voltage <<15 kV) fluid cooled power transformer.
Component Use Comments Wmdings High- and low-voltage windings. There may be multiple low volt-Tertiary windings. age windings.
Silicon-steel core Voltage induction between core windings.
Solid insulation Electrical insulation between winding turns, windings, and all electrical conductive materials.
Tank (sealed enclosure) Physical protection for electrical Tank seals internal components parts. May enclose multiple from outside atmosphere. Uses a windings and cores. Contains cool- gas blanket to prevent the entry of ant fins. air, water, and other contaminants.
Bushings Structure to provide for termina- Separate bushings are required for tions and insulated pathway each circuit connection to through transformer tank wall for transformer winding.
electrical conductor.
Insulator/coolant Provides dielectric insulation Mineral oil has a high dielectric (mineral oil) support, protection from strength, the ability to recover contaminants, and a medium to after dielectric stress, and is an remove winding/core heat. Used excellent heat transfer medium.
where fire does not present hazard Oil is flammable and is not used to other equipment or buildings. where a fire would present a hazard to equipment or facilities.
Insulator/coolant Provides dielectric insulation The nonflammable fluids used are (nonflammable fluids) support, protection from siIicons, high-flash-point contaminants, and a medium to hydrocarbons, chlorinated remove winding/core heat. benzenes, or chlorofluorocarbons.
Askarel is being phased out.
Silicons are used on modem transformers. These fluids have lower dielectric strength than mineral oil.
Nitrogen blanket Optional-Provides nitrogen gas The equipment used for the blanket over the transformer fluid. system include gas cylinders, gas The blanket acts to prevent the regulator, a pressure control, and a entry of contaminants and allow for gas pressure indicator.
the expansion/contraction offluids.
11 NUREG/CR-5753 OAGI0001164_00023
Power Transfonners Table 2-3. (continued).
Component Use Comments Temperature indicators Indicate bulk or hot spot May include alarm contacts.
temperature of windings.
Radiator (fins) Forced-air cooling. Required for forced-air cooling.
Air fanes) and motor(s) Forced-air cooling. Required for forced-air cooling.
Temperature transducer Start-stop forced-air cooling. Required for forced-air cooling.
(contacts) May be included with temperature indicator.
Fan motor controller(s) Controls fan motors for forced-air Required for forced-air cooling.
cooling.
Liquid level gauge Indicates liquid level. May include alarm/control contacts.
Pressure relief valve Automatic relief and reseal after high May include alarm/control pressure in tank. contacts.
Top liquid temperature Indicates oil temperature at high May include alarm/control gauge point of oil. contacts.
Table 2-4. Components for high voltage (> 15 kV) mineral oil-cooled power transformer.
Component Use Comments Windings High- and low-voltage windings. There may be multiple low-Tertiary windings. voltage windings and windings for taps.
Silicon-steel core Contains magnetic flux for voltage induction between core windings.
Solid insulation Electrical insulation between wind-ing turns, windings, and all electri-cal conductive materials. Contains mineral oil. Provides core support.
Tank (sealed enclosure) Physical protection for electrical Tank seals internal components parts. The tank may enclose multi- from outside atmosphere. Uses a ple windings and cores. Contains gas blanket to prevent th~ entry of mineral oil. Provides core support. air, water, and other contaminants.
NUREG/CR-5753 12 OAGI0001164_00024
Power Transfonners Table 2*4. (continued).
Component Use Comments Bushings Structure provides for terminations The bushings are mineral oil-filled and insulated pathway through with a level gauge. Separate transformer tank wall for electrical bushings are required for each cir-conductor. cuit connection to a transformer winding.
Insulator/coolant Provides dielectric insulation sup- Mineral oil has a high dielectric (mineral oil) port to winding insulation and acts strength, the ability to recover as a medium to remove winding! after dielectric stress, and is an core heat. excellent heat transfer medium.
Filter press, drain, and Theses valves are required to allow sampling valves the sampling and testing of the oil, the addition of oil, and filtering of contaminated oil.
Flexible diaphragm Flexible synthetic-rubber dia-phragm is sometimes used over the mineral oil to prevent the entry of air/water/contaminants and allows the expansion and contraction of the oil without damaging the tank; maintains positive pressure.
Radiator (fins) Required for forced-air and forced- Required for forced-air and oil cooling. forced-liquid cooling.
Air fanes), motor(s), Required for forced-air and forced- Required for forced-air and temperature transducers, liquid cooling. forced-liquid cooling and controls Air fanes), motor(s), Required for forced-oil cooling. Required for forced-air cooling.
temperature transducers, Transducer input may be from oil and controls temperature gauge contacts.
Liquid level gauge Indication of liquid level. May include alarmlcontrol contacts.
Pressure/vacuum relief Automatic relief and reseal after tank May include alarmlcontrol valves high/vacuum pressure. contacts.
Top liquid temperature Indication of oil temperature at high May include alarmlcontrol indicator point of oil. contacts.
Winding temperature Indication of average winding or hot May include alarmlcontrol indicator spot winding temperature. contacts.
Rapid pressure rise relay Provides alarmltrip in the event of transformer failure.
Load tap changer Regulates output voltage to plant High maintenance item.
with varying off-site voltages.
_~~_~_ ~ ___ _______._____
~ ~._,_,-------c------ ---.~-----.
OAGI0001164_00025
Power Transfonners Table 2*5. Components of power transformer cooling systems.
Required by coolant system Forced-air- Forced-oil Self-cooled cooled cooled Component (AA) (FA) (Fo)a Gas heat exchanger(s)-air, nitrogen, or No Yes No fluorogas-cooled transformers Liquid heat exchanger(s)-oil or No Yes Yes nonflammable liquid cooled transformers Temperature transducers Optional Yes Yes Control system(s) No Yes Yes Fan(s) and motor(s) No Yes Design dependentb Pump(s) and motor(s) No No Yes Temperature indicator(s) Yes Yes Yes
- a. Forced-oil cooling is only used on high-voltage transfonners (>15 kY).
- b. Nonnally yes for transfonners rated ~ 15 kV.
NUREG/CR-5753 14 OAGI0001164_00026
- 3. SIGNIFICANCE OF AGING Aging of Class 1E transfonners has the poten- 3.1 Major Transformer tial to degrade their ability to meet design require-ments. General Design Criteria 17 of 10 CFR 50, Components speaks in general tenns of requirements placed on transformers. The IE power system, including A transfonner is composed of a magnetic core, transfonners, must have sufficient capacity and electrical windings and tenninations, an enclo-capability to ensure adequate protection of the sure, and insulation and coolant. Table 3-1 gives a reactor core, reactor coolant pressure boundary, brief description of these major components.
and the containment integrity. In addition, suffi-cient independence, redundancy, and testability The magnetic circuit of a transformer com-must be provided to perform their safety func- prises mainly a core of laminations. There are two tions assuming a single failure. Aging has the basic core lamination design types: the core-fonn potential to affect the capability to provide rated type is typically used in power transfonners up to capacity and to reduce the effectiveness of redun- 50 MVA. and the shell-fonn type is typically used dancy through aging degradation that is common for transformers with ratings greater than to redundant transfonners. General Design Crite- 50 MVA. Figure 3-1 shows the two design types.
ria 17 also requires the consideration of environ-mental conditions that are a result of accidents.
However, Class IE transformers are located in The cores used in modern transformers are buildings and rooms that have controlled environ- improved versions of the fundamental designs ments that are independent of postulated acci- developed early in the twentieth century. Most dents and, therefore, are not affected by this transfonner cores are constructed of thin sheets requirement. (approximately O.3-mm thick) of grain-oriented, 3% silicon steel. Steel is used because it carries and confines the magnetic field better than air or Aging is a natural phenomenon and is highly other low cost materials. The industry is exper-related to the environmental conditions the trans-imentaIIy using an amorphous steel developed by fonner encounters. Transfonner aging would be Allied-Signal, Inc. The amorphous steel, called minimal if the transformer were not operating.
Metglass, has greatly reduced core losses over However, environmental conditions inherent with conventional silicon steels.
transformer operation cause components to degrade with time in service. Aging of trans-former insulation causes deterioration that can Early transfonners used thick laminations of reduce the period a transfonner is capable of pro- soft iron. Excessive hysteresis and eddy current ducing the needed capacity. In addition, as trans- losses produced heat in the cores. This excessive fonners approach their end of life, deteriorated core heat caused transfonner failures. Modern insulation becomes more susceptible to failures transformer cores are constructed of thin steel caused by electrical transients such as those sheets with their grain oriented to give less caused by lightning and switching. Some aging resistance to magnetic flux and to reduce eddy cur-mechanisms are reversible, and quality can be rents. In addition, flux densities are design-limited regained, such as moisture or impurities in the to minimize hysteresis losses. Modern design insulation oil that can be removed, while others methods for transfonner cores and windings have are irreversible, such as deterioration of the cellu- improved projected transfonner life. Transfonner losic paper used as insulating material. With an cores are very reliable if the transfonners are oper-appropriate transfonner surveillance and mainte- ated within the temperature limits specified by the nance program, the rate of aging can be mini- manufacturers and the cores are properly sup-mized. Thus, the full design life of the ported to reduce vibration and mechanical transfonner can be achieved. damage.
~---
OAGI0001164_00027
en
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Table 3-1. Components of power transformers and materials of construction. 5i Q
~
~~
Component Materials Comments G g,
W Core Silicon steel Laminated sheets.
J:
~.
Windings Cooper or aluminum Each turn may be made up of groups of strands.
Solid insulation Cellulose, kraft paper, phenolics, fiberglass', Used to provide wire, turn, and layer insulation for and varnishes-shellac, enamel, or various the windings. Paper wrapping is also used on the resins leads coming from the windings.
Fibrous-resin-paper laminates, pressboard and Used to bond and protect (mechanical and moisture) various kinds of paper (nylon or wood based) fibrous insulating material.
Liquid-insulating! High-flammability High dielectric strength and excellent heat transfer cooling medium Mineral oil capability. No high voltage (> 15 kV) restrictions.
Low-flammability Good dielectric strength and heat transfer capabili-
...... Askarel, silicones, high-flash-point hydrocar- ties. High voltage limit is s 15 kV. Askarel is being 0\ bons, chlorinated benzenes, or chlorofluoro- phased out. Silicones are used on all modem low-carbons flammability fluid transformers.
Gas-insulating! Air Relatively low dielectric strength and heat transfer cooling medium capabilities.
Nitrogen/fluorogas Relatively low dielectric strength and heat transfer capabilities. Requires pressure regulation system to maintain pressure in sealed tank.
Bushings Porcelain. kraft paper. metal foil, mineral oil High-voltage bushings use kraft paper. metal foil.
and copper or aluminum conductor and oil inside a porcelain outer surface. Lower volt-age bushings use kraft paper with a conductor inside
-I a porcelain outer surface.
Tank Carbon steel Heavy gauge steel, painted to prevent corrosion.
Connections Copper. aluminum, solder, brazing o
G) o o
o (J)
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o o
o N
CD
Significance of Aging
-(1n arrangement of An arrangemen.t of winding used with core-form winding used with shell-form transformers. ,. transformers.
Figure 3-1. Comparison of windings used for core- and shell-form transformers.
Transformer windings have two major compo- medium and coolant, and it protects the trans-nents: conductors and insulation. The conductors former from external environments.
commonly used in power transformers are copper or aluminum. Each material has specific advan- The majority of transformers used in Class IE tages. For instance, copper has greater mechanical applications are open-wound, dry-type trans-strength and greater electrical conductivity than formers. Dry-type transformers use air as the sole aluminum. Aluminum, however, costs less and is source of coolant. The insulation is provided by a lighter than copper. The many turns in a winding combination of air or nitrogen and solid insulat-must be insulated from each other and from neigh- ing materials. Most dry-type transformers use a boring windings. Winding conductors use Kraft Class H, 220°C insulation system. Thus, the max-paper,a Nomex, cellulose, or another similar insu- imum allowable hot spot winding temperature is lating medium. Windings include spaces, or chan- 220°C.
nels, to allow flow of the insulating coolant (such as air, oil, or gas). This cooling establishes the life Liquid-filled transformers are also used in of the insulation. Degraded cooling accelerates the Class IE applications. A specific liquid is used as aging of the insulating materials. a heat transfer medium. The liquid removes heat from the transformer core and windings. The Heavy gauge structural steel is typically used enclosure surface and radiators dissipate the heat to make transformer enclosures. The enclosures to the ambient environment. Oil pumps, forced air can be vented or sealed, indoor or outdoor, pad- fans, and external radiators increase the cooling mounted or pole-mounted, or dry-type or liquid- capacity of the liquid-filled transformer. The filled. The enclosure contains the insulating cooling fluid is in contact with the transformer windings. Therefore, the fluid must be an accept-able insulator. Historically, liquid-filled trans-
- a. Mention of specific products or manufacturers in formers have a high reliability because of the high this document implies neither endorsement, prefer- dielectric strength of the coolant, the *insulating ence, nor disapproval by the U.S. Government, any of structure, the sealed enclosure construction, and a its agencies, or Lockheed Martin Idaho, of the use of proven design. Many different insulating liquids a specific product for any purpose. are currently used in liquid-filled transformers, 17 NUREG/CR-5753 OAGI0001164_00029
Significance of Aging including mineral oils, silicone fluids, synthetic Each material listed above has its own aging hydrocarbons, high molecular weight hydrocar- mechanism, as identified in Table 3-2.
bons, trichlorotrifluoroethane, and chlorinated benzene. 3.3 Transformer Loading Gas-cooled (vapor-cooled) transformers have An issue separate from reduced transformer characteristics that are similar to liquid-filled capacity induced by aging is increased trans-transformers. A gas-cooled transformer has its former loads resulting from plant modifications.
core and windings immersed in a refrigerant such Modifications to the plant design over years of as Freon (R-113). The refrigerant vaporizes at the operation add electrical loads to the electrical dis-core or winding interface with the refrigerant. tribution system and transformers. These addi-The vaporization removes the heat from the core tionalloads cut into the design reserve capacity of or winding. The vaporized coolant rises to a con- the transformers. Thus, late in the design life of a densing unit above the transformer. It cools and transformer, a transformer may be loaded beyond condenses to a liquid state before returning to the the original station design requirements. The transformer tank by gravity. transformer may be loaded beyond its continuous rated capacity under accident conditions as a result. The additional loads will accelerate the 3.2 Construction Materials naturally occurring aging of the transformer. This is because transformer-generated heat is directly Materials used in dry-type, liquid-filled, and proportional to the transformer load. The heat gas-cooled transformers are, in general, the same, generated can be further increased by the physical except that the cooling medium differs. Every condition of the transformer. The amount of heat material has its own aging mechanisms. The retained in the transformer is related to the physi-aging mechanisms are accelerated by contami- cal condition of its cooling system.
nants or excessive heat. As the dielectric strength of the insulation decreases, a point is reached 3.4 Transformer Capacity where flashover (winding to winding, winding to Considerations ground, or primary winding to secondary wind-ing) occurs. The flashover results in contamina- As stated, transformers are specified and tion (discharge tracking) of the insulation. This designed with minimum design capacity and capa-permanently reduces the insulation's dielectric bility. The transformers are relied on to operate strength. These effects accelerate aging and under postulated accident and environmental increase the likelihood of further flashovers. conditions while minimizing the likelihopd of simultaneous failures. Thus, with the additional Typical transformers are constructed of high loads imposed by responding to an accident, a permeability silicon steel cores. Structural steel transformer is designed to have sufficient design forms the tank (enclosure) and structural sup- reserve capacity to continue operation. This design ports. Windings are formed by copper or alumi- reserve capacity exists beyond additional growth num conductors. Liquid coolants can include loads caused by plant modifications and loss of mineral oils, silicone fluids, synthetic hydrocar- transformer capacity caused by transformer aging.
bons, high molecular weight hydrocarbons, trich- Additionally, the loads imposed may be peaked by lorotrifluoroethane, and chlorinated benzene. such items as swing loads and loads such as bat-Insulation can be cellulosic (paper or pressboard), tery chargers operating at their maximum output.
Kraft paper or Nomex, phenolics, plastics, porce-lain, wood, epoxy, fiberglass, rubber, cork, ther- Catastrophic failure or end of transformer life, moplastics, and varnishes. Other miscellaneous it is hoped, will not occur during an accident or materials include paints and solder. The above accident recovery. System redundancy alleviates materials do not include auxiliary equipment such the concern. However, the same aging mecha-as cooling fans, radiators, and oil pumps. nisms are at work on both redundant transformers.
NUREG/CR-5753 18 OAGI0001164_00030
Table 3-2. Component stressors and failure mechanisms.
Component Stressor Failure mechanism Result Comments Windings Overvoltages. Partial discharge. Breakdown of tum-to-tum insula- Long term damage to the insulation is the most likely tion. occurrence.
High continuous Solid insulation hot spot tem- Aging of solid insulation See "Solid Insulation."
current (overloads). peratures. increases with increased heat.
Lightning and Core movement. Insulation deformation.
switching surges.
Vibration. Tum-lo-tum short.
Core Vibration. Delamination. Increase in core heat/hot spots. See "Solid Insulation."
Core telescoping and lateral Core movement deforms solid shifts. insulation. Decomposition of insulation by core vibration.
Solid Heat above design (I) Loss of mechanical Heat speeds up the chemical Hot spot or average winding temperatures above the insulation limits. strength-increases brittle- action that eventually destroys rated temperature increases the aging rate of the solid ness. the insulation. insulation. The effects of the overheating solid (2) Eventual reduction in insulation are accumulative, that is, nonreversible.
...... dielectric strength .
\0 Moisture. Reduced dielectric strength of Electrical shorts between turns, Moisture held in combined form releases under solid insulation. winding, and/or ground. Disable increasing temperatures producing same conse-transformer. quences as free moisture.
Contaminants. Same as "Moisture." Same as "Moisture." Contaminants usually have inferior dielectric strength.
Core movement. Insulation compaction. Decomposition of insulation. Reduces ability to withstand lightning and switching-induced surge voltages and 60 Hz over voltages and I transient.
Mechanical damage. Electrical failure.
Bushings Heat and moisture See "Solid Insulation" for Cracking, embrittlement.
on inside of bush- failure mechanisms, results ing. and comments. Cf.l Contamination on Reduced electrical distance Short to tank (ground). Can be easily cleaned and prevented. <§.
~
outside of bushing. though air to ground.
Connections Oxidation and vibra- High electrical resistance, Open circuits and protective relay Visual and infrared inspection used to detect. ::n Q
tion. arcing, and high heat. tripping.
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Table 3*2. (continued).
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Component Stressor Failure mechanism Result Comments ....
- n o
Q Reduced heat transfer capability. Requires derating transformer or sludge removal.
~
Mineral oil Entrained air or Sludge formed.
Buildup causes shrinkage of cellulose insulation.
~
(Insulating! water. ('l) cooling g, mediums)
U!
w ~
Acids formed. Absorbed by fibrous insulations Most acids formed are weakly acidic, however, over Jg' attacks metallic and other compo- time, material aging is accelerated if acids not nents. removed.
Solid insulation absorbs water. Absorbs increasing amounts of See "solid insulation-moisture."
moisture in solution.
Reduces electrical breakdown Decomposition products include H2, CH4, C2H2, strength. C3H3. H3, and other types of hydrocarbons.
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- 4. TRANSFORMER AGING MECHANISMS Historically, transformers have been reliable or hot spot temperatures. Heat accelerates the components in electrical power systems. How- chemical reactions that liberate oxygen from the ever, various stressors and aging mechanisms can fibrous atomic structure. This mechanism makes cause transformer failures, and many of these can a transformer more likely to fail as it increases in lead to sudden failure under electrical stress. For age. This occurs even though the dielectric this reason, transformers tend to appear as a two- strength of the insulation material may not be seri-state device; it operates or it fails. Through an ously decreased. The deterioration of the fibrous understanding of transformer aging mechanisms, insulation is not reversible. Monitoring trans-material conditions can be tested and trended so former temperatures to verify continued operation timely replacement or repair can be performed within design temperature limits helps to ensure prior to catastrophic failure. In addition, mainte- the design transformer life. Imbedded temperature nance actions can be taken to minimize the rate of sensors and infrared heat scans can be used.
aging and ensure maximum transformer lifetime.
Moisture in an insulating medium (oil, air, or Transformer failures are classified as one of gas) is another aging mechanism. Heat accelerates four types: magnetic circuit, winding, insulation, this mechanism. The primary concern with mois-or structural failures. These do not include fail- ture is that the paper and pressboard insulation ures of auxiliary equipment such as cooling fans. readily absorbs the moisture. This decreases the Some overlap of these classifications may occur, dielectric strength, accelerating the aging of the such as the structural failure of an insulating insulator structure. Appreciable quantities of bushing. Another example of overlapping classi- water in insulating oil decreases the dielectric fication is a flashover between adjacent winding strength of the oil. This may lead to failure at oper-turns that causes degradation of the dielectric ating voltages. Moisture permanently damages the strength of the insulating structure. insulation. Subsequent drying of the insulation only reduces the rate of deterioration. The lower The metals in the structure, magnetic circuit, the water content in the insulation, the greater the and windings are, in general, not subject to aging possibility of meeting the design life of the trans-as are nonmetallic components. Thus, the life of former. Complete removal of moisture from a cel-the transformer depends mostly on the life of the lulose insulation is not possible without damaging insulation. Transformer failures follow a typical the cellulose.
bathtub curve. Manufacturing defects (such as poor design, faulty materials, burred conductors, The dielectric strength of the oil and cellulose and workmanship) show up early in the life of a insulation systems are drastically weakened when transformer. Then a period of relatively trouble there are free gas intrusions (bubbles). In an oil-free operation occurs. Late in the life of a trans- filled transformer, gas bubbles in the oil can result former, aging mechanisms could potentially in partial discharges and reduced cooling effec-translate into transformer failures. The objective tiveness. Wet fibers can distort the electrical field of General Design Criteria 17 is to have trans- and cause local stress that can also result in partial formers operate in the second, bottom portion of discharges. Partial discharges can also be caused the bathtub curve. That is, transformer life will by small conducting particles or contaminants in either extend beyond the station life or the trans- the insulating coolant. These discharges result in former will be replaced before failure would burning and charring of the insulating materials.
occur if responding to an accident condition. Gaseous combustion products are released by these discharges also.
Temperature is an aging mechanism that decreases the mechanical strength and increases All these aging accelerators can be monitored the brittleness of the fibrous insulation. This aging by periodic sampling and analysis or by on-line mechanism accelerates with increased operating analysis of the cooling (liquid or gas) fluid and 21 NUREG/CR-5753 OAGI0001164_00033
Transfonner Aging Mechanisms insulation testing. The design life of the trans- However, the stress loads caused by lightning and former can be preserved by maintaining the purity switching transients are somewhat limited by their of the cooling fluid and the insulating properties of short duration and by installed surge protective the insulation. The historical trend and the current device characteristics.
condition of the insulation and any cooling fluid can be used for identification of maintenance mea- The ambient temperature directly affects the sures needed to preserve or extend the life of a equilibrium temperature of an operating trans-transformer. Physical inspections of all trans- former. Electrical and mechanical properties of former types can provide similar and supportive insulating materials are related to their tempera-end information. The interpretation of the condi- ture. Softening of polymeric insulators increases tion of the insulation depends primarily on com- as the temperature rises. Other temperature-parison of current insulation testing with previous related changes such as, melting, crystallization, test results. embrittlement, deformation, and creep occur in insulating materials. Some of these changes are Oil-filled transformers have the separate aging not reversible. Dielectric loss also exhibits a mechanism of sludge formation. Sludge is one of temperature-dependent change. Increased dielec-many oil decay products. Sludges formed into tric loss could lead to local thermal runaway. On solid insulation cause insulation shrinkage. the other hand, maintaining transformer tempera-Insulation shrinkage results in winding motion tures under design limits ensures that the useful under shock or impulse loading. Sludge deposits life of the transformer is not compromised. If the result in higher transformer operating tempera- temperature is maintained low enough, the useful ture. Derating the transformer to account for life of the transformer may extend beyond the sludge deposits helps ensure the design life of the design life.
transformer.
The magnetic forces within a transformer exert Another aging concern is solar magnetic dis- mechanical forces on the windings and the mag-turbances. Solar flares have a characteristic effect netic materials. These repulsive and attractive on earth. Solar magnetic disturbances cause forces combine with thermal expansion and con-geomagnetic-induced currents in the miles-long traction forces. These forces may distort insulating transmission circuits. These currents are harmon- structures, especially if the structure is already ics of the base (60-Hz) power frequency. The weakened by temperature-induced deformations.
harmonics cause a half-cycle saturation of the Stationary windings can move as much as three transformer. There is a direct relation between inches under short-circuit conditions. A short cir-geomagnetic-induced currents and half-cycle cuit generates considerable magnetic force.
transformer saturation. The saturation causes Steady 60-Hz alternating current also causes mag-increased heating and greatly increased gen- netic forces to operate on the windings. The con-eration of combustible gases within the tinual alternating force causes a vibration that, transformer. There are known instances of trans- over time, will compact the mechanical insulation former failures attributed to active solar storm structure that holds the windings in place. Thus, activity. both vibration- and surge-induced core move-ments damage the insulating structure of the trans-Systems to monitor the effects of geomagnetic- former. A loose transformer structure means induced current flows are being developed by unrestrained windings for impulse- and fault-industry. These will supplement any other trans- induced stress. These conditions when further former monitoring program. Having ample stressed, cause further transformer aging.
reserve transformer capacity will help the trans-former weather the storm. Systematic programs that monitor physical conditions, insulation properties, sound levels, Lightning- and switching-induced impulse coolant properties and purity, geomagnetic-voltages have similar effects on a transformer. induced transients, and transformer temperatures NUREG/CR-5753 22
~-
OAGI0001164_00034
Transformer Aging Mechanisms help to ensure the design life of the transformer. A Confidence that a transformer has always program of testing and monitoring, along with operated within its design envelope gives preventive and corrective maintenance, is the key assurance that a transformer will operate to or to achieving the desired transformer life. beyond its design life.
23 ~(}/~-5753 OAGI0001164_00035
- 5. REVIEW OF OPERATING EXPERIENCE This review was completed using information Some plants included'information in the obtained from the Nuclear Regulatory Commis- NPRDS for large numbers of special transform-sion's Licensee Event Reports (LERs), the Insti- ers. One nuclear power station included informa-tute for Nuclear Power Operations' Nuclear Plant tion for 120 transformers in the NPRDS. Included Reliability Data System (NPRDS), the Nuclear in the data was information on special low-power Power Experience database (NPE), and informa- transformers, such as current and potential, con-tion obtained from a cooperating utility. The data trol, voltage regulating (electronic controlled),
and information were analyzed to determine the and adjustable voltage transformers. Because this types of Safety Class IE transformers used, their study is on power transformers, all NPRDS infor-ages, and their problems and failures associated mation was reviewed, and data on nonpower with aging. The information was also analyzed to transformers were not included in the study.
determine if any transformer problem/failure trends have developed as the transformers The majority of reported transformer problems became older. and failures in the NPRDS, NPE, and the LER are not directly related to power transformer aging.
These include problems and failures caused by The use of information from the NPRDS data-human error, design and operation deficiencies, base, the NPE database, or the LER records has and acts of nature. The database also lists as limitations. Licensee reporting requirements are transformer-related, problems for other power such that a complete record cannot be obtained equipment. For example, problems on electrical from anyone of the sources. Because each data-buses, breakers, lightning arresters, relays, and base requires different information, in varying other equipment were frequently included in the degrees of detail, a partial piece of information transformer category. To ensure that all problems might be misleading, and might be recorded in and failures included in this study were actually one database and not in another. The NPE and on power transformers, an examination was made LER databases only report problems and failures on each problem and failure that was reported in resulting in recordable events (LERs). They do the databases.
not include any transformer specifications or non-event transformer failures for either Safety Class To separate problems that were directly asso-IE or non-IE transformers. The NPRDS, how- ciated with the transformer proper and the aging of ever, includes information on transformer specifi- the transformer, guidelines were established for cations and failures (event and nonevent) for each the engineering evaluation of the database infor-reporting plant. mation. The guidelines used are listed as follows:
The use of the NPRDS transformer specifica-
- The transformer envelope included connec-tion and inservice data also had some limitations. tions, insulators (bushings), current trans-Only 91 operating plants have Class IE power formers, and potential transformers on the transformer nameplate data and failure informa- transformer proper.
tion in the NPRDS. In addition, a comparison of
- The transformer envelope also included all failures (LERs) reported in the LER, NPE, and cooling equipment (controls, control trans-NPRDS show that the NPRDS records were formers, and fans).
sometimes incomplete. To obtain a better view of the problems and trends caused by transformer
- Database reported transformer problems aging, the NPRDS transformer information on and failures not associated with the plants licensed since January 1, 1989, was not transformer envelope andlor not related to used in this study, resulting in the use of NPRDS the aging of power transformers were not to data from 88 plants for this study. be used in this study.
NUREG/CR-5753 24 OAGI0001164_00036
Review of Operating Experience During the study, a detailed engineering review 5.2 Transformer Age was completed on 269 NPRDS problem reports, 1167 NPRDS transformer information records, The ranges of age for the Safety Class 1E 400 NPE entries, and 70 LER reports. All reports, power transformers are shown in Table 5-3. The records, and entries that were not related to the NPRDS data for the 88 plants indicate that over effects of power transformer aging were dis- 95% of the transformers are less than 20-years carded. For comparison, the NPRDS-reported old, and about 75% are under 15-years old.
operating experience for non-l E power trans-formers is also included in this report. 5.3 Transformer Problems, Failures, and Replacements Note that as discussed in Section 2, transform-ers listed in NPDRS as IE and having voltage rat- The NPRDS data show that 56 power trans-ings above 15 kV are likely not actually IE formers have been put in service since the plants transformers. However, NPRDS data are being used, and the NPRDS classifications will be used Table 5-1. Type cooling for NPRDS-listed in this section of the report. Class IE power transformers.
Type Percentage of cooling Number transformer 5.1 Types, Applications, and Descriptions of Safety Oil 120 (16.6%)
Class 1E Power Air 553 (76.5%)
Transformers Gas 50 (6.9%)
Transformers currently in Safety Class IE Total 723 (100%)
installations in Nuclear Power Plants consist largely of three types: liquid-filled, dry-type, and Table 5-2. Voltage ratings of NPRDS-Iisted gas-cooled. Each type has specific applications power transformers.
for which they are commonly used. A typical High-voltage rating Percentage of nuclear power station electrical diagram is shown in Figure 2-1. The Safety Class IE transformers of transformers transformers covered by this component aging study are shown oto 601 volts 36.1 within the dashed line area.
601 to 15,000 volts 57 As shown in Table 5-1, the NPRDS records of Over 15,000 volts 6.9 the 88 plants show a total of 723 Safety Class IE power transformers, 76.5% of these are air- Table 5-3. Age of NPRDS-listed safety cooled (dry-type), 16.6% are oil-filled, and 6.9% Class IE power transformers.
are gas cooled.
Age Number Percentage Table 5-2 shows the high-voltage rating for NPRDS-listed Safety Class IE power transform- oto 5 years 119 16.5 ers. As shown in the table, the majority of Safety 5 to 10 years 218 30.1 Class IE transformers have a high-voltage rating 10 to 15 years 199 27.5 between 601 and 15,000 volts. The highest Safety 15 to 20 years 154 21.3 Class IE transformer voltage rating included in Over 20 years 33 4.6 the NPRDS data is 500 kV for two transformers at one nuclear station. Total 723 100.0 25 NUREG/CR-5753 OAGI0001164_00037
Review of Operating Experience have been licensed, with 33 of these occurring resulted from the ten problems with "Load Tap since 1983. 1Wenty-six of these were oil-filled, Changers" and "Connections." Other events were and the remainder were dry type. The data do not prevented by problem detection during routine show the reasons for the installation or whether observations, incidental observations, inservice they were replacements for existing transformers. inspections, and surveillance tests. The problems The installations of these transformers happened with "Oil, Nitrogen, and Gas Leakage" did not between 4 to 18 years after plant licensing. The result in any events during the period reviewed.
installations do not correspond to identified prob- However, undetected leakage can result in trans-lems, failures, or LERs. former failure, as reported in NRC 1E Information Notice Number 82-53, Main Transformer Failures at the North Anna Nuclear Power Station, Table 5-4 shows both the NPRDS-recorded December 24, 1982. (See Section 5.5 of this Safety Class IE and all classes of plant trans-report.)
former aging-related problems and failures dur-ing the period from January 1983 through April 1991. During this period, a total of 143 problems/ Table 5-5 shows the causes of transformer failures occurred on all classes of transformers at problems and failures for both NPRDS-listed the 88 plants. Of these problems, 33 were attrib- Class IE and all safety classes (Class IE and uted to Safety Class IE transformers. Only 38 of nonclass IE) versus the type cooling for the the 143 recorded problems/failures resulted in period between January 1, 1983, and April 30, reportable events (LERs). Of the 33 recorded 1991. As can be observed, 64% of the problems Safety Class IE problems/failures, five caused and failures occurred on oil-cooled transformers reportable events (LERs). for both IE and non-IE transformers. Sixty-four percent of Class IE transformer problems and The NPRDS data show that detection of failures failures occurred on a population of 16.6% of during routine observation, preventive mainte- the total transformers in service (see Table 5-1).
nance, and surveillance tests appear to have pre- This was attributed to use of oil-cooled vented reportable events. For example, either an transformers at high voltages and greater loads, "Internal Failure" or a "Bushing (Insulator)" fail- with the resulting increased stresses on ure result in- the total failure of a transformer. insulation. In addition, problems with load tap However, only 50% of these types of failures changers were the cause of 5 of the 21 reported resulted in LERs. Only three events (LERs) problems and failures for NPRDS-listed Table 5*4. Reported safety-related transformer problems.
All safety classes Safety Class IE transformers transformers Problems and failures Total LERs Total LERs Internal failure 49 23 6 1 Bushing (insulator) 11 7 3 1 Cooling system 44 3 7 0 Transformer connections 9 1 5 1 Load tap changers 11 4 5 2 Oil, nitrogen, gas leakage 19 0 7 0 Total 143 38 33 5 NUREG/CR-5753 26 OAGI0001164_00038
Review of Operating Experience Table 5-5. Transfonner problems by cooling type (1983 through May 1991).
All safety classes Safety Class IE Problems and failures Oil Air Gas Oil Air Internal failure 25 25 2 4 Bushing (insulator) 10 I 2 1 Cooling system 31 13 4 3 Transformer connections 1 8 1 4 Load tap changers 11 5 Oil, nitrogen, gas leak 14 5 7 Total 92 (64%) 46 (32%) 5 (4%) 21 (64%) 12 (36%)
Class 1E transformers. Load tap changers are This notice described a series of seven main only used to regulate output voltages for oil- transformer failures on the 330-MVA, cooled, high-power, and high-voltage trans- 500-kV primary winding main power trans-fanners. formers. The problems experienced are also common to all oil type transformers, includ-5.4 Trends ing cooling system and bushing failures.
Although all of the factors leading to the The transformer problems/failures for all failures are contributors to, and indicators NPRDS-listed transformers and Safety Class IE of, the aging of the transformer, none of the transformers, from 1983 through 1990, are shown described failures were directly attributed to in Figure 5-1. The experience of all classes of transformer aging.
transformers shows a peak period of problems and failures starting in 1985 with 19 occurrences,
- IE Informat~on Notice 83-37, Transformer rising to 27 during 1987, receding to 19 during Failure Resulting from Degraded Internal 1988, and followed by 16 each during 1989 and Connection Cables.
1990. The Safety Class IE transformer experi-ence is very similar, with a peak of 8 problems This notice described an event caused by a and failures occurring in 1987. During 1987, degraded internal transformer connection cooling equipment problems were the major fac- on a Safety Class IE 4160/480 volt dry-type tor for the failures in all classes of transformers, transformer at Brunswick 2 on April 26, while connections proved to be the major prob- 1983. The failure was attributed to long-lem experienced by Safety Class IE transfonners. term, heat-induced degradation initially caused by a poor connection. Later inspec-5.5 NRC IE Information Notices tion of similar safety-related transformers at Brunswick 2 identified eight of 48 con-Since 1982, there have been two Inspection nections with cable-to-Iug degradation.
and Enforcement Notices providing information Detailed transformer inspections, necessary on significant transformer problems. A summary to detect these failure mechanisms prior to of each notice follows: complete failure, were not included in the licensee preventive maintenance program.
- IE Information Notice 82-53, Main Trans- Similar connection problems and failures former Failures at the North Anna Nuclear have been detailed in the NPRDS, LER, and Power Station. NPE data bases, with 8 occurrences in 1987 27 NUREG/CR-5753 OAGI0001164_00039
Review of Operating Experience 30r---------------------------------------------------~
Non Class 1E Transformers en
~ 20
- J
'(ij LL 1 16
"'0 c 16 tU en EQ)
- a0 10 a.
OL---------------------------------------------------~
1983 1984 1985 1986 1987 1988 1989 1990 Years Figure 5-1. Class 1E and nonc1ass IE power transfonner problems and failures listed by year.
(3 for Class IE transfonners). However, none of about 75% are less than 15 years old. The these have occurred since 1987. young age of the transfonners makes it diffi-cult, if not impossible, to determine the effects of transformer aging using plant 5.6 Summary operating experience.
A review of the infonnation provided by the
- FromJanuary 1983 through April 1991, only NPRDS database, the NPE database, and LERs 5 LERs were caused by problems or failures yields the following information: of Safety Class IE transformers (Table 5-4).
Only 33 failures were reported on
- The NPRDS records of the 88 plants show a 723 Class IE power transfonners. Based on total of 723 Safety Class IE power trans- the number of plants operating in a given formers; with 76.5% of these using air year, this is an average failure rate of (dry-type), 16.6% oil, and 6.9% using an 0.822 X 10-6 failures per hour per inert gas as the insulation and cooling transfonner. Categories oftransfonnerprob-medium. Over 57% of the transformers lems and failures include internal failure, have a high-voltage rating of 600 volts to bushing (insulator), cooling system, trans-15 kV, and only 6.9% have a rating over fanner connections, load tap changers, and 15kV. oil, nitrogen, or gas leakage. About 64% of the problems occurred on oil-insulated
- This review shows that about 95% of the transformers. (During this same period, transformers are under 20 years of age, and 38 LERs were caused by problems or NUREG/CR-5753 28 OAGI0001164 00040
Review of Operating Experience failures on non-IE power transformers at the case, if they were replacements for existing plants. There were 143 total problems or failed units, the problems were detected in failures on these transformers. About 64% of time to prevent licensing events (LERs).
the problems occurred on oil-insulated transformers.)
- There is no present evidence, based on the
- It was not possible to determine the reasons NPRDS, NPE, and LER data that there are for the installation of 56 transformers after significant problems with the aging of the plants start up (34 of these occurring transformers. This is based on the NPRDS, since 1983). If this information were avail- NPE, and LER data, which show that only able, a better understanding of the transfor- 56 replacements, 33 problems/failures and mer experience, the detection of failures, 5 LERs occurred from 1983 through 1990 on and the licensee's surveillance/maintenance the 723 Safety Class IE transformers for the programs might have been obtained. In any 88 plants studied.
29 NUREG/CR-5753 OAGI0001164_00041
- 6. TRANSFORMER RISK ANALYSIS A standard PRA was used to determine which and bus work as potentially risk-significant components were risk significant. The PRA for components.
the Surry Nuclear Power Station (Bertucio 1990) It is possible to further screen components was used. The Surry PRA was chosen because it based on the increase in risk caused by assuming is well documented in NRC-supported literature that the failure probability of a particular compo-and is familiar to many in the PRA community. nent is unity. If such an assumption does not result Additionally, the authors had previously loaded in a significant increase in risk, then the aging of the PRA and verified it to quantify correctly on the component is not risk significant. Unity fail-the Integrated Reliability and Risk Assessment ure probability for a key IE transformer yields a System (IRRAS) software. The quantified risk risk increase of 1.0E-04. Comparing this increase was expressed in terms of core damage frequency. to the total core damage frequency of 3.0E-OS The fault trees for the Surry PRA included break- indicates that the increase in failure probability of ers, transformers, bus work, inverters, rectifiers transformers could contribute significantly to and batteries. Only the relays and isolation plant risk.
devices were not included explicitly in the PRA.
The Surry PRA used a transformer failure rate Quantification of a PRA generally involves of 1.7E-06. The average failure rate observed in truncation of those cut sets that do not contribute this study was 0.822E-06. At the time of this significantly to the final core damage frequency. study, there does not appear to be an increase in This was the case for the Surry PRA. All cut sets the transformer failure rate with the age of the with a probability of less than 1.0E-09 before transformers. If the transformer failure rate is recovery were truncated. The truncation resulted kept at the presently observed level, by using a in the complete removal of the battery, inverter, maintenance and surveillance program, an and rectifier components from the final set of increase in the risk of core damage because of the cut sets. This left only the breakers, transformers, aging of transformers is not expected.
NUREG/CR-5753 30 OAGI0001164_00042
- 7. TRANSFORMER INSPECTION, SURVEILLANCE, MONITORING, AND MAINTENANCE 7.1 Guidance for Maintenance, helps reduce internal pressures and operating temperatures. Painting transformers prevents cor-Surveillance, Monitoring, rosion of the metal parts.
and Inspection Verifying that connections to the terminals are Inspection and testing of certain items on the tight avoids abnormal junction heating.
Safety Class IE transformers at regular intervals extends the life of the transformer. Recommended Liquid Level. Low transformer oil levels maintenance and inspection practices for Safety invite transformer failure. A liquid level gage Class IE transformers vary according to trans- with remote alarm contacts on oil-filled trans-former type (dry, oil-filled, or gas-filled), size formers can help prevent low fluid levels. A (kVA), and voltage ratings. The objective of the monthly inspection and calibration of the liquid inspections is to verify that there are no abnorma- level gage, along with testing of the low-level lities with regard to noise, leakage, level, and alarm circuit, is important for the proper temperature of the dielectric, and operation of the operation of that instrumentation.
cooling system. The following maintenance, inspection, and testing procedures follow the rec- Cooling Fans. The regular inspection of ommended procedures of transformer manufac- forced-air cooling equipment verifies it is in satis-turers and those sources closely involved with the factory operating condition. Motor bearings, if power distribution transformer industry, including permanently lubricated and sealed at the factory, S. D. Myers, Inc., and the J &P Transformer Book need no attention. Otherwise, monitoring motor by Franklin and Franklin (see Bibliography). bearings for wear and periodic oiling, if called for, Some of the recommended procedures cannot be helps ensure reliable fan operation. Oiling is performed during reactor operation; therefore, needed if the bearings are not sealed. Painting fan schedules coinciding with refueling outages are blades can cause an imbalance that may lead to the appropriate. destruction of the blade. Checking excessive noise from the pumps and fans can detect possible 7.1.1 Oil-Filled Transformers. Maintenance anomalies.
intervals for Safety Class IE oil-fiIled trans-formers are summarized in Table 7-1. Where a Control Circuits and Equipment. Regular interval is listed as annual, this can be understood inspection of the following items for control as during a refueling outage. circuits helps ensure transformer operability:
Periodic Cleaning and Inspections.
- Control-circuit voltage Inspection of porcelain bushings at regular inter-vals helps ensure they are kept free from dust,
- Collections of dirt and gum dirt, acid fumes, salt deposits. and other contami-nants. The accumulations of contaminants on the
- Evidence of excess heating of parts (discol-external surface may result in flashover. oration, odor, etc.)
Although surge arresters do not require testing,
- Freedom of moving parts inspection for dirt or dust contamination reduces the likelihood of external flashover.
- Corrosion of metal parts Keeping the heat radiating surfaces of the
- Excess wear on contacts transformers and the screened openings in the breathers and/or pressure-vacuum bleeder clean
- Loose connections 31 NUREG/CR-5753 OAGI0001164_00043
Transfonner Inspection Table 7-1. Maintenance intervals for oil-filled transfonners.
Maintenance item Frequency Comments Visual Inspections Tap changers AnnuaUya Clean and inspect functionality Bushings Monthly Clean and inspect Radiators Monthly Clean and inspect Cooling intakes On demand Clean and inspect Oil filters Weeldy Clean Inspect for leaks Weekly Visual inspection Cooling fans Daily Inspect for damage and noise Pumps Daily Inspect for damage and noise Connections Monthly Inspect and tighten Control circuits Quarterly Inspect and test Transfonner housing Quarterly Paint if needed Vacuum interrupter AnnuaUya Inspect for wear Auto gas control Quarterly Inspect and maintain Surge arresters Quarterly Clean and inspect Instrumentation and Control Temperature gages Monthly Functional test Annuallya Calibrate Pressure gages Monthly Functional test Annuallya Calibrate Level gages Monthly Functional test Annuallya Calibrate Alarm circuits Annuallya Check functionality On-line gas analyzer Monthly Check functionality Load tap changers Monthly Check functionality Relays Monthly Clean and test Testing Oil-dielectric Annuallya Oil-acidity Annuallya Oil-moisture Annuallya Oil-color Annuallya Oil-sludge Annuallya Combustible gas analysis On-line monitor Gas chromatography Every 3 months or when warranted Acoustic emissions When conditions warrant Infrared scan Annuallya and when damage is suspected NUREG/CR-5753 32 OAGI0001164_00044
Transfonner Inspection Table 7-1. (continued).
Maintenance item Frequency Comments Doble Power Factor Tests Windings Annuallya Bushings Annuallya Liquid Annuallya Electrical Insulation Tests Excitation current Annuallya and when damage is suspected Turns ratio test Annuallya and when damage is suspected Winding resistance Annuallya and when damage is suspected Ground resistance Annuallya
- a. Annually means 18 months or during each scheduled reactor refueling outage.
- Proper contact pressure The types ofgases (H2, CH4, C2H2. C2H4,C2H6, CO, and C02) present in a sample and their rela-
- Excessive arcing in opening circuits tive amounts enable the nature of the fault to be determined (thermal or electrical). The type of material producing the gas can also be determined.
- Evidence of water in controls A log of combustible gas readings, if kept, will show an increasing trend. With an increasing
- Excess slam on pickup trend, the time between tests can be shortened. If the combustible gas content exceeds a preset limit
- Worn or broken mechanical parts. (>1 % by volume), a laboratory dissolved-gas-in-oil analysis helps to develop a plan of action.
Combustible Gas Analysis. Sampling Acoustic Emission Measurement. When Safety Class IE liquid-filled transformers greater used in conjunction with a gas-in-oil analysis, than 500 kVA for combustible gases at regular acoustic emission CAE) measurements of corona intervals is an effective way to detect insulation (partial discharges) provide an accurate pre-degradation. Either a portable gas analyzer or an diction of incipient failures. Acoustic emission online combustible gas analyzer can be used. Of measurements can detect imminent faults. An the two methods, the online gas analyzer is the online gas detector has delays of hours and even most desirable. It provides alarm capabilities of days while the gases propagate through the oil to an internal fault in the transformer when a preset the analyzer. Present AE technology offers the level of combustible gases is exceeded. The advantage of being able to determine the location online gas analyzer has an excellent record for of partial discharges and/or arcing within a trans-reliability in predicting incipient failures in both former to a high degree of accuracy.
old and new transformers. Gas chromatography (laboratory gas analysis), following any indica- AE measurements are made externally, on the tion of an incipient fault by the online gas ana- transformer housing, or with a waveguide, which lyzer, confJfD1s a preliminary diagnosis. is placed in the oil next to each high-voltage 33 NUREG/CR-5753 OAGI0001164_00045
Transfonner Inspection winding. With new installations, wave guides can
- Sludge (interfacial tension).
be installed during transformer fabrication. The drawback with acoustic emissions detection is Dielectric Strength Test-Maintaining a that it takes a trained operator to both take and in- high dielectric strength of the insulating oil terpret the data. AE does not replace a gas analy- ensures transformer operability. Oil samples sis, but it is a method of conflrming the results of taken from transformers in the field, tested a gas analysis and is a means to help pinpoint fault according to ASTM Method D 1816 helps achieve locations within the transformer. this goal. A low breakdown voltage is an indica-tion that impurities such as moisture, conductive Sampling and Testing Insulating Oil. dust, lint, or carbonized particles have entered the Transformer oil not only serves as the cooling oil. Compact and efficient dielectric test equip-medium, it plays a major role as part of the electri- ment is available for use in the field. The test set cal insulation system. It can reflect the cleanliness, applies an ac voltage at a controlled rate to two dryness, and to some extent, the degree of aging of electrodes immersed in the dielectric fluid.
the transformer. The following information covers Ideally. the oil tests 26 kV or higher with a the sampling and testing of transformer oil and the O.040-in. (I-mm) spacing between electrodes. Oil significance of the test results. testing lower than 25 kV is either filtered to bring it back to 26 kV or replaced.
Sampling-The accuracy of the test results can be seriously affected by an improper sampling Although the dielectric test can indicate the procedure. Procedures outlined in American Soci- presence of some impurities in the oil, it cannot ety for Testing and Materials (ASTM) Method detect the presence of dissolved water below 80%
D923, if followed, help obtain consistent results. saturation, acids, or sludges.
ASTM Method D923 addresses recording the top oil temperature at the time of sampling. Particular Acidity Test-The acidity test is the best attention is given to the cleaning and drying oftest- single test for indicating oil oxidation. ASTM ing containers: Taking samples when the insulat- Method D974 is a laboratory means measuring ing oil is at least as warm as the ambient air avoids acidity from oil oxidation in transfonners. Acids moisture condensation. Samples taken on a clear are detrimental to the insulation system and can dry day, avoids the possibility of water or dust con- induce rusting of metal parts when moisture is tamination. The sample must be protected from present. An increase in the neutralization number contact with light, air, and moisture. It is very is an index to the rate of deterioration of the oil.
important that the sample not be exposed to the Under normal conditions, the oil acidity is below ultraviolet rays of the sunlight. which will acceler- 0.2 mg KOH. There are fleld tests available to ate aging: Ideally, the sample will be drawn measure acidity (ASTM Method DI534); how-quickly, kept in a dark sealed container, and tested ever, they are not as sensitive as the laboratory as quickly as possible. method and therefore are not recommended.
The following tests determine the condition of Water and Moisture Content-Water the transformer oil: content is critical in that an increase can indicate a leaking condition and ultimate reduction in
- Dielectric strength test dielectric strength. Free water may be detected in the sample by visual examination, in the form of droplets or as a cloud dispersed throughout the
- Acidity (neutralization) oil. Because water in solution cannot be detected visually, the Karl Fischer Reagent method
- Water or moisture content (ASTM Method D1533) is recommended as a means of determining water content in the oil, in
- Color parts per million.
NUREG/CR-5753 34 OAGI0001164_00046
Transformer Inspection Instrumentation suitable for water-in-oil analy- The purpose of the insulation power factor tests sis is available for use in the field. Recording is to provide an indication of the integrity of the results from this analysis periodically aids in insulation system. Power factor is a measure of detecting anomalities. Although a gradual the power loss through the insulation system to increase in water content over the life of the trans- ground, caused by leakage current. The IPF can former is to be expected, any abrupt increase be measured by applying a voltage across a needs investigation to ascertain if serious condi- capacitive network, in this case the transformer tions, such as leaks, may exist. insulation, and measuring the amperes and watts loss and using these data to calculate a power Color Test-The next in a series of oil factor. For field application, a de-energized series sample tests is the color test. A gradual darkening of tests that measure insulation power factor of the oil in service can be expected. The test, (Doble tests) are used.
meaningless by itself, is significant when there is a distinct change. The color test can be useful for All insulating systems will have some minor leakage paths that permit a small current to flow.
diagnostic purposes, along with acidity and other A transformer is deemed suspect if the insulation tests to indicate the degree of contamination or power factor exceeds 2%. The causes of high deterioration of the oil.
power factor can be determined through additional testing. The bushings and liquid insulation can be There are two ASTM methods available for tested to determine if they contribute to the high performing the color test: (a) a laboratory method reading.
(see ASTM Method DI500), and (b) a field test kit (see ASTM Method D1524). The recommended procedure for testing bush-ings is the ungrounded specimen test (UST)
Sludge Test-The test used to determine method. The equipment manufacturer recom-the degree of sludging in the insulation system is mends a maximum permissible test voltage not to called the interfacial tension test (1FT). be exceeded during testing.
The test procedure is described in ASTM The liquid IPF is determined by taking an oil Method D971. IFf test results are related to the sample from the transformer and testing for a power factor using the UST Method. New oil degree of the oils oxidation and are an indicator of the degree of oil deterioration and contamination should have a power factor of ~ 0.05% at 20°C.
of the oil by the solid materials immersed in it. When the power factor exceeds 0.5%, further tests (insulation resistance or moisture content tests) can determine the cause, or whether mois-Electrical Insulation Tests. The following ture is present.
tests are used to evaluate the condition of the transformer insulation. When the results from the Excitation Current-Excitation current insulation tests are coordinated with data from the measurements are made to detect shorted turns and oil tests, the general working condition of the heavy core damage. The excitation current tests transformer can be determined. are performed using the UST method and the same test equipment used for the power factor tests. The Insulation Power Factor TestS-The test results can be compared to factory and pre-insulation power factor (IPF) tests are divided vious field test data to determine abnormal read-into the following three categories: ings. High precision in excitation current measurements is not a requirement, because fault
- 1. Winding IPF conditions found as a result of the test have excita-tion current values greater than 10% over normal.
- 3. Liquid IPF. Test-The transformer turns ratio test can be 35 NUREG/CR-5753 OAGI0001164_00047
Transformer Inspection performed in the field to detect short-circuited tures above those recommended limits will result turns, incorrect tap settings, mislabeled terminals, in accelerated deterioration of the oil and aging of and tap changer failures. A TIR test can indicate the cellulose insulation. Local overheating is a pri-that a fault exists, but does not determine its exact mary indicator of incipient faults within a location. The test is normally performed annually, transformer.
any time a transformer has been repaired or modi-fied in the field, or if a fault has occurred drop- Top-liquid and bottom-liquid temperature are ping the transformer offline. not suitable for indicating operating conditions within the transformer. Hot-spot temperature The TIR test uses the transformer turns ratio readings give a more accurate indication of load test set. The test equipment has an internal alter- conditions within the transformer windings. 1\vo nator to supply test voltage and is reliable and winding temperature indicating instruments are simple to use in the field. suitable for existing transformers. One local tem-perature gage with a high limit set point mounted Winding Resistance Measurements- at the transformer at eye level aids local operators.
Winding resistance measurements will reveal a A second temperature indicator with an audible change in de winding resistance when there are high-temperature alarm and room operators short-circuited turns, poor joints, or bad connec- located at a manned remote location aids control.
tions. Prior factory andlor field test readings are required so that a comparison of data can be made. Operating temperatures, along with coincident records of ambient temperature, load, and voltage, Measurements made with a Wheatstone or when carefully recorded as often as practical, aid in Kelvin double bridge yield the most accurate evaluating the operating history of the transformer.
results. It is essential that the temperature of the Changes in operating temperatures are often the windings be accurately measured top to bottom, only means by which the operator can detect an as all test readings must be converted to a com- abnormal condition within the transformer.
mon temperature to give meaningful results. The dc circulating current applied to the system needs Infrared Detectors-Portable infrared to settle down before measurements are taken. detectors can be used periodicaIIy to aid in the de-tection of incipient faults on both old and new Ground Resistance Measurements- transformers. Periodic thermal imaging is per-Ground resistance measurements are conducted formed with an operating guide that defines tem-to determine the integrity of the grounding con- perature as a function of image color. Although nections and the copper ground conductors. High the infrared detector will not pinpoint a fault loca-resistance readings can indicate a poor condition tion, it can aid in determining whether or not a of the ground grid or ground electrode or that the piece of equipment has overheated.
soil may have to be conditioned with water or chemicals. A good ground system will protect Polarization Recovery Voltage Test. A both personnel and equipment. The resistance method of detecting moisture and aging degrada-measured to ground should not exceed 5 ohms. tion products in the paper insulation, as well as the oil, has been developed and marketed for use in Load Records. Records of load and voltage Europe and in the United States. The technique on the transformer, when checked regularly, veri- applies a voltage between a transformer winding fies that the transformer is operating within its and the transformer tank for a period of time, prescribed limits and is being used efficiently. applies a short to the winding. removes the short, and then records therecovery voltage as a'function Temperature Measurements-The of time. This process is repeated by varying the operating temperature of the transformer has period of time that the voltage and short are limits defined in American National Standards applied. An analysis of the results provides an Institute (ANSI) Standard CS7.12.00. Tempera- indication of the moisture content and the presence NUREG/CR-5753 36 OAGI0001164_00048
Transfonner Inspection of aging degradation products. The presence of liquid. They are designed to rupture at IOta either of these products indicates a degradation of 15 psi. Mechanical-relief devices are usually the total insulation system. The technique appears mounted on the top of the tank. The pressure to be very sensitive to the presence of moisture and relief device typically include alarm contacts to aging degradation products. Oil analysis provides indicate operation of the device.
a good measurement of moisture content in the oil, but since moisture is more readily absorbed in the Fault-Pressure Relay-The fault-paper than in the oil this technique may be particu- pressure relay is designed to de-energize the trans-larly useful for indicating the presence of moisture former and/or initiate an alarm in the event of in the paper insulation. sudden pressure rise. The relay is not susceptible to trip because of vibration, mechanical shock, or Fluoroptic Sensors-online hot spot pressure variations due to transformer temperature measurements using fluoroptic sensors wound changes. The relay is mounted on a valve on the into the transformer windings can accurately mea- tank wall, near the base of the transformer.
sure winding temperature. The fluoroptic device uses a phosphor sensor at the end of an optical fiber If a periodic test program is followed, it will to measure temperature. The temperature of the help ensure that fault pressure relays are available sensor is determined by measuring the rate of for their role of protecting the transformer and decay of the fluorescence of the phosphor after it initiating an alarm. Electrically tripping the relays has been excited by a pulse of blue-violet light sent during any scheduled outage of equipment and at down the fiber from a Xenon flash lamp within the yearly intervals will ensure that they are in good instrument. Once the rate of decay of the fluores- condition, and that all the circuits are complete so cence has been measured, sensor temperature can that breakers and alarms can be tripped.
be determined by comparison with an empirical Relay contacts can be cleaned during testing calibration curve. The probes and fibers are made with a flexible brushing tool to ensure reliable of durable material that can withstand shock and operation. Knives, files, or abrasive paper or cloth vibration within the transformer and many years of should not be used to clean relay contacts.
continuous exposure to hot transformer oil.
Because the fluoroptic sensors are installed within Load Tap Changers (LTCsj. Load tap the transformer windings, they should only be changers are typically inspected and tested for considered for new installations where the sensors proper operation annually; the following six pro-can be installed at the factory. The relative high cedures are normal:
cost of the fluoroptic system must be weighed against the cost and critical nature of the trans- 1. Check the condition and dielectric strength former to determine whether or not the system is of the oil in the tap selector compartment cost effective. and replace if necessary. Proper minimum oil level should be maintained.
Pressure Relief Devices and Sensors.
An excessive increase in tank pressure is an indi- 2. Check the self-adjusting oil seal for wear or cation that an internal fault condition exists. leaks.
Mechanical pressure relief devices, fault-pressure relays with alarm contacts, and digital or analog 3. Check operation of the protective system.
pressure gages (with a means of recording tank
- 4. Verify that the gear-teeth paint marks are pressures) ensure that pressures have remained properly aligned.
within normal limits.
- 5. Keep the mechanism gears and control cams Pressure Relief Devices. Pressure relief lightly greased.
diaphragms are usually mounted on the end of a pipe connected to the transformer case above the 6. Clean relay contact surfaces.
-~----~----~~-~~------------------~----~------ -- - ---
OAGI0001164_00049
Transfonner Inspection Vacuum Interrupter. The arcing contacts to the oil-insulated transformers. Procedures and within the interrupter will gradually wear over a requirements for electrical insulation testing and period of time as a result of interrupting current dielectric testing of the windings (Doble Tests) during each tap change. Inspection of the wear in- are similar to the oil-fIlled units (discussed pre-dicators and the entire switch mechanism, annu- viously). The following sections discuss mainte-ally or after 25,000 operations, whichever occurs nance, inspection, and surveillance practices fIrst, helps ensure reliable operation. Worn inter- common to dry-type transformers. Maintenance rupters should be replaced based on manu- intervals for dry-type transformers are summa-facturer's recommendations. rized in Table 7-2.
Automatic Gas Controls. Some medium Periodic Cleaning and Inspections. With power Safety Class IE transformers may be the transformer de-energized, the front and rear equipped with automatic gas-control equipment. access panels are removed. Inspections are made The purpose of gas-control equipment is to main- for dirt, especially on insulating surfaces or for tain an atmosphere of dry nitrogen under pressure those that will restrict air flow, for loose connec-between the top oil surface and the transformer tions, for the condition of tap changers or terminal cover. This isolates the oil from the outside air boards, and for the general overall condition of and prevents oxygen, moisture, and other the transformer. Tracking or carbonization are contaminants from being absorbed in the oil. The signs of overheating and voltage creeping over nitrogen is supplied from a gas cylinder and insulating surfaces. Any anomalies are identifIed enters the transformer through a gas regulator. and corrected where possible.
High- and low-pressure alarms, along with the transformer gas space pressure gage, are normally Painted surfaces are checked for signs of rust, part of these controls. corrosion, or deterioration. Any deteriorated sur-faces need to be cleaned, prepared, and repainted with the type of paint recommended by the trans-Excessive loss of gas can be the result of a high former manufacturer.
oil level, abnormal loading, a defective regulator, or leaks. A log of transformer pressure, oil tem-Fans and motors are inspected for wear or dam-perature, and gas cylinder pressure, if kept, can age and receive periodic service. The fan control aid in determining the cause of gas consumption.
system is checked to ensure that air delivery is Regulator operation is tested, and a leak test per-made to the transformer coils.
formed on the nitrogen system on a regular basis to ensure reliable operation. Excessive dirt on the windings or insulators is removed to permit free air circulation and to pro-Transient Recorders. One primary cause of tect against insulation breakdown. Cleanliness of transformer failure is power line disturbance. The the top and bottom ends of winding assemblies, as purpose of the transient recorder is to keep a well as ventilating ducts, ensures ventilation. Tap record of the power line anomalies that tend to changers, terminal boards, bushings, and other accelerate transformer aging. By knowing the fre- insulating surfaces can be brushed or wiped with quency of occurrence and the magnitude of the a dry cloth. Pressurized air should not be used for transients, testing can be initiated to detect pos- cleaning because it may blow abrasive debris into sible damage to the transformers before failure of the winding~ and damage the winding insulation.
the unit occurs.
Insulation Resistance and Dielectric 7.1.2 Dry-Type Transformers. Maintenance, Tests. Prior to initial energization of the trans-testing, and instrumentation procedures for the former, and following any shutdown exceeding dry-type transformers are similar to the oil-fIlled 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, an insulation resistance test will deter-units with the exception of the oil testing common mine if moisture is present in the insulation.
~--~.
OAGI0001164_00050
Transfonner Inspection Table 7-2. Maintenance intervals for dry-type transfonners.
Maintenance item Frequency Comments Visual Inspections Internal surfaces Quarterly Clean and inspect Tap changers Quarterly Clean and inspect Tenninal boards Quarterly Clean and inspect Transformer housing Quarterly Paint if needed Connections Monthly Inspect and tighten Cooling fans Daily Inspect for damage and noise Windings AnnuaUy.
I 0
0 0
(J1 (J)
Table 8*2. (continued),
Addresses these items relative to aging Inspection System Standard Aging Operational surveillance component function number Title degradation Maintenance records monitoring Comments Documentation IEEE 494-1974 Standard Method for Identification of No No No No Documents Related to Class IE Equipment and Systems for Nuclear Power Generating Stations Safety system criteria IEEE 603-1977 Standard Criteria for Safety Systems for No No No No Aging not included Nuclear Power Generating Stations in Sections 4 and 5 Safety system qualification IEEE 627-1980 Design Qualification of Safety Systems Generically No EQonly EQonly
,I Equipment Used in Nuclear Power Generating Stations
~ Quality assurance ANSIIASME
", Standard Recommended Practices for No No Yes Yes NQA-I-1983 Quality Assurance Program Requirements NQA-2-1986 Applicable to All Phases of Nuclear Power Plant Design, Construction, and Operation Replacement parts 934-1987 Standard Requirements for Replacements No No No Yes Parts for Class IE equipment in Nuclear Power Generating Stations Statistical analysis 930-1987 Guide for Statistical Analysis of Voltage Yes No No No Endurance Data for Electrical Insulation
- 0 Standards for IE Power
~
~
Systems .-.
('D
=E Design criteria 308-1980 Criteria for Class 1E power Systems for No No No Yes 0 Q >-+>
0
~
&. Testing programs 415-1986 Nuclear Power Generation Stations Preoperational Testing Programs for No No Preoperation Preoperation
-8.
CI.l G) -...J Class IE power Systems for Nuclear test testing only 0
0 Ut w Power Generating Stations procedures B-en 0
(J)
.j::>.
I 0
0 0
(J1
-....J
Table 8-2. l:tI
~
(continued).
~
~
~
Q Addresses these items relative to aging 0
""!)
~
VI System Standard Aging Operational Inspection surveillance CI.l g
~ 0-VI w component function number Title degradation Maintenance records monitoring Comments a
rn Protection of IE power 741-1986 Protection of Class IE Power Systems Degraded No Test and Degradcd and Equipment in Nuclear Power voltage records only voltage Generating Stations IE Power Component Standards All electrical equipment 943-1986 IEEE Guide for Aging Mechanisms and Yes No No Only as Diagnostic Procedures in Evaluating applied to Electrical Insulation Systems diagnostic techniques
~
Askarel ANSIIASTM Test for Color of Chlorinated Aromatic Yes No No Yes D2129-79 Hydrocarbons (Askarel)
ANSIIASTM Test for Thermal Stability of Chlorinated Yes No No Yes D1936*64R1980 Aromatic Hydrocarbons (Askarels)
IEEE 76*1974 Transformer Askarel in Equipment No Yes No No Bushings ANSIIIEEE Loading Power Apparatus Bushings No Yes No No 757-1983 ANSIIIEEE Outdoor Apparatus Bushings, Require- No Tests No No 24-1976 ments, and Tests ANSIIIEEE Outdoor Apparatus Bushings, No No No Yes 24-1984 Performance 0
G) Insulating materials, ANSIIIEEE Acceptance and Maintenance of Insul- No Yes No No 0 systems, and electric CS7.106-1977 ating Oil in Equipment 0 insulations 0
(J)
.j::>.
I 0
0 0
(J1 CD
Table 8*2. (continued),
Addresses these items relative to aging Inspection System Standard Aging Operational surveillance component function number Title degradation Maintenance records monitoring Comments
-j IEEE 266-1969 Evaluation of Insulation Systems for No Yes No No' RI981 Electronic Power Transformers IEEE 62-1978 Field Testing Power Apparatus Insulation No Yes No No HVI-1978 High-voltage Insulators No Yes No No ANSI/EIA Insulation Resistance Test Test Yes No No RS364-2IA-1983
~ ULI446 Systems of Insulating Materials-General No No No Yes Insulators ANSI C29.1- Electrical Power Insulators No Yes No Yes 1982 Power apparatus IEEE 62-1978 Field Testing Power Apparatus Insulation No Yes No No Testing equipment and IEEE 498-1980 Calibration and Control of Measuring and No Yes No No testing Test Equipment Used in the Construction and Maintenance of Nuclear Power Gen-erating Stations IEEE C57.12.14 Dielectric Test Requirements for Power No Yes No No ~
~
Transformers for Operation at System Voltages from 115kV to 230kV ~.
Q ANSI/IEEE Transformer Impulse Tests No Yes No No ~
C57.98-1968 ....
til 0
~
I [
G) 0 0
VI
~
VI w
a en 0
(J)
I.j::>.
0 0
0 (J1 CD
Table 8-2.
~_.
~
(continued),
Addresses these items relative to aging
~
Q ~
~
C'/)
Inspection VI System Standard Aging Operational surveillance g a.
--.l VI w component function number Title degradation Maintenance records monitoring Comments aCIl Transfonners ANSIIIEEE Acceptance and Maintenance of Insul- No Yes No No C57.106-1977 ating Oil in Equipment ANSI/IEEE Detection and Detennination of Gen- Yes Yes No No C57.104-1978 erated Gases in Oil-immersed Trans-fonners and Their Relation to Service-ability of the Equipment IEEE C57.12.14 Dielectric Test Requirements for Power No Yes No No Transfonners for Operation at System Voltages from 115 kV to 230 kV
~
NEMA TR98- Guide for Loading Oil-immersed Power No Yes No No 1978 Transfonners With 65C Average Winding Rise ANSI/IEEE Installation, Application, Operation, and No Yes No No C57.94-1982 Maintenance of Dry-type General Purpose Distribution Transfonners ANSI C57.12. Liquid-filled Transformers Used in Unit No Yes No No 27-1982 Installations Including Unit Substations ANSI/IEEE Liquid-immersed Distribution, Power, No Yes No No CS7.12.90-1980 and Regulating Transformers and Guide for Short-circuit Testing of Distribution and Power Transformers ANSI CS7.12. Load-tap Changing Transformers No Yes No No
- 30-1977
-- ANSIIIEEE C57.92-1981 Loading Mineral Oil-immersed Power Transformers No Yes No No
Table 8-2. (continued).
Addresses these items relative to aging Inspection System Standard Aging Operational surveillance component function number TItle degradation Maintenance records monitoring Comments IEEE 756 Loading Mineral Oil-immersed Power No Yes No No Transformers ANSIJIEEE Oil-immersed Transformers No Yes No No C57.l2.11-1980 ANSI C57.12. High-voltage Bushings No Yes No No 22-1980 ANSI C57.12. Pad-mounted Compartmental-type Self- No Yes No No 52-1981 cooled Three-phase Distribution Trans-
~ Formers With Separable Insulated High-Voltage Connectors ANSI CS7.12. Sealed Dry-type Power Transformers No Yes No No 26-1975 ANSI/IEEE Test Procedure for Thermal Evaluation of No Yes No No CS7.100-1974 Oil-immersed Distribution Transformers ANSI/iEEE Terminology for Power and Distribution No Yes No No C57.12.80-1978 Transformers
- d
~
~ .....
0
~
~ Q.,
en 0
>> ~ g a
Q..
U\
G) 0 0
v:
w (I) 0 (J)
I.j::>.
0 0
0 (J)
- 9. CONCLUSIONS The results presented in this section are the normally be supplied by a dry-type but where the product of the Phase I study for understanding use of oil is not appropriate, such as inside appli-and managing aging of transformers. Transform- cations where the concern for transformer flres ers perform their primary function without the use prevents the use of oil.
of moving parts but do depend on auxiliary equip-ment such as fans, motors, pumps, and load tap Failure data from the NPRDS, LERs, and NPE changers. Transformers have the critically impor- databases were reviewed. The failure rate of tant function of providing power to equipment transformers does not indicate an increased that is necessary for accident prevention, accident failure rate with age of transformer. However, management, and accident mitigation. The fol- over 95% of the transformers are less than lowing conclusions have been developed and 20-years old and 75% are under 15-years old.
supported by failure data from several databases Because transformers are normally considered to and from plant-specific records. They provide the be a long life item (40 years or greater), a signifi-basis for future research and work to mitigate ag- cant trend with age would not be expected at this ing degradation and improve the reliability of time. Reported categories of transformer prob-transformers. lems include internal failure, bushing (insulator),
cooling system. transformer connections, load tap Degradation or deterioration of electrical insu- changers. and oil. nitrogen or gas leakage. The lation is the most significant failure mode for total number of transformer failures is not large.
transformers. Failures of the windings (tum to From January 1983 through May 1991, NPRDS tum, winding to winding, or winding to ground data for 88 plants with 723 safety-grade faults) and failures in the bushings that provide Class IE transformers reported only 33 problems the interface between the transformer and the and failures. The incidence of transformer fail-transmission lines are primarily caused by a fail- ures does not appear to be increasing with the age ure of the insulation system. Insulation failures of the transformer. Therefore, we conclude that are caused by excessive temperature, excessive presently identified aging mechanisms are not voltages, moisture, and contamination. Contami- expected to cause safety problems.
nation is most often in the form of moisture, acids, and foreign material from the outside envi- A review of the Surry PRA revealed that trans-ronment or from the aging of internal compo- formers, along with circuit breakers and buses, nents. Vibration also causes insulation failures by are the risk-significant components in the Class contributing to the breaking down of solid insula- IE power system. If the transformer failure rate is tion material. kept at the presently observed level, an increase in the risk of core damage frequency is not expected.
Transformers currently installed in Class IE applications consist of three types: liquid-filled, A continual program of inspection, surveil-dry-type, and gas-cooled. Dry-type (air cooled) lance, monitoring, and maintenance will help account for about 76.5% of the transformers, ensure transformer reliability. Such a program while 16.6% are liquid-filled, and 6.9% are gas- will detect and reduce stressors that shorten trans-cooled. Liquid-filled are primarily used in high- former life, prevent stressors before they cause voltage, high-power applications such as those degradation, and detect degradation in the early that supply power to the 4160-Vac bus. Dry-type stages so that preventive and corrective action can are typically used in lower-voltage, lower-power be taken prior to transformer failure to reduce the applications such as those found in the distribu- rate of aging. An effective program of inspection, tion system within the various buildings. surveillance, monitoring, and maintenance con-Gas-cooled transformers are found in applica- sists of periodic cleaning and inspections; testing tions where more power is needed than would of dielectric strength; and testing of oil in Uquid-NUREG/CR-5753 50 OAGI0001164_00062
Conclusions filled transformers; testing to verify that electrical Because transformers installed in nuclear faci-characteristics such as winding resistance, lities are relatively young, a periodic review of insulation resistance, turns ratio, excitation cur- operating experience of transformers would be rent, and resistance to ground are maintained. useful to monitor their continued performance.
Regular measurement of temperature is an impor- A period of five years would be appropriate for tant element of a transformer monitoring pro- the review. The review would determine if the gram. There are numerous codes and standards present information remains accurate, and deter-that are applicable to transformers. These codes mine whether significant trends, not previously and standards provide guidance for design, the identified, are developing.
performance of several tests, and maintenance of all types of transformers.
- - - - - - - - - - - - - - - - - - - -- - - - - - - - ---~ ---- -- -----
OAGI0001164_00063
- 10. BIBLIOGRAPHY Atwood, C. L., Estimating Hazard Functions for Repairable Components, EGG-SSRE-8972, May 1990.
Atwood, C. L., User's Guide to PHAZE, a Computer Program for Parametric Hazard Function Estimation, EGG-SSRE-90I7, July 1990.
Bertucio, R. C., J. A. Julius, and W. R. Cramond, Analysis of Core Damage Frequency: Surry Power Sta-tion, Unit 1 Internal Events, NUREG/CR-4550, Volume 3, parts 1-3, April 1990.
Franklin, A. C. and D. P. Franklin, The J & P Transformer Book, 11th edition, London: Butterworth & Co.
Ltd, 1983.
General Electric Co., Instruction Manual, GEK-95915, 1987.
Hochart, Bernard, 1982, Power Transformer Handbook, English edition, London: Butterworth & Co. Ltd.
Levy, I. S., et al., Prioritization ofTIRGALEX-Recommended Components for Further Aging Research, NUREG/CR-5248, PNL-6701, January 1988.
Meyer, L. C. and J. L. Edson, Nuclear Plant Aging Research: The IE Power System, NUREG/CR-5181, EGG-2545, 1990.
Myers, S. D., J. J. Kelly, and R. H. Parrish, Fifty Plus Years: A Guide to Transformer Maintenance (in situ, in vivo), Ohio: S. D. Myers, Inc., 1981.
Shier, W. and M. Subdhi, Operating Experience and Aging Assessment ofMotor Control Centers, NUREGI CR-5053, BNL-NUREG-52118, July 1988.
Square D Company, Instructions for Receiving, Installing, Operating and Maintaining Dry Type Transformers, Manual 7421-1, 1985.
NUREG/CR-S7S3 52 OAGI0001164_00064
NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. RE?ORT NUMBER 12*89) (AulgnOd by NRC. Add Vol** SuPP** Rlv..
NRCM 1102. end AddindumNumbort.lllny.1 3201.3202 BIBLIOGRAPHIC DATA SHEET (See insrructions on rhe reversel NVREG/CR-5753
- 2. TITLE AND SUBTITLE INEL-95/0573 Aging of Safety Class 1E Transformers in Safety Systems of Nuclear Power Plants J. DATE REPORT PUBLISHED MONTH I YEAR February 1996
- 5. AUTHOR IS) 6. TYPE OF REPORT E. W. Roberts J. L. Edson A.C. Udy 7. PERIOD COVERED (InC(USIl"~ Datesl B. PERFORMI NG ORGANIZATION - NAM E AND ADDRESS (If NRC. provid~ Division. Oflice Dr Region. U.S. Nud**r Regul.tory Commiuion. and rrui!ing .ddr,m:iI conrracror.providd nMTIe .nd m.JIIng addT'lu.}
Idaho National Engineering Laboratory Lockheed Idaho Technologies Company P.O. Box 1625 Idaho Falls, Idaho 83415
- 9. SPONSORING ORGANIZATION _ NAME AND ADDRESS (II NRC. Iype "SA"", asabo ..... if conrraclor.pro.ide NRC D;';sion. OWe" or Region. U.s. Nuc/eor Re9u/dlOry Comminion*
- nd milling .dd,t.,.1 Division of Engineering Technology Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, D.C. 20555 - 0001
- 10. SUPPLEMENTARY NOTES J. Jackson, NRC Project Manager
- 11. ABSTRACT (200 word. o,l.ul This report discusses aging effects on safety-related power transformers in nuclear power plants. It also evaluates maintenance, testing, and monitoring practices, with respect to their effectiveness in detecting and mitigating the effects of aging. The study follows the U.S. Nuclear Regulatory Commission's (NRC) Nuclear Plant-Aging Research approach. It investigates the materials used in transformer construction, identifies stressors and aging mechanisms, presents operating and testing experience with aging effects, analyzes transformer failure events reported in various databases, and evaluates maintenance practices. Databases that were analyzed included the NRC's Licensee Event Report (LER) system and the Institute for Nuclear Power Operations' Nuclear Plant Reliability Data System (NPRDS).
- 12. KEY WO ROS/DESCR: PTO RS (List words or phrlse. mil wi" aui$! ""**rr:non in locating rho "'pOrt. I 13. AVAILABILITY STATEMENT Transformers Unlimited
- 14. SECURITY CLASSIFICATION Aging Stressors IThl'PAge' Class IE Unclassified
/ThisR.pom Unclassified
- 15. NUMBER OF PAGES
- 16. PRICE
'lAC FOAM ll5 12-891 OAGI0001164 00065
- Printed on recycled paper Federal Recycling Program OAGI0001164_00066