Relay

© 2011 Doble Engineering Company - 78th Annual International Conference of Doble Clients All Rights Reserved

500 KV GSU FAILURE DUE TO AIR BUBBLE FORMATION

Craig Swinderman Mitsubishi Electric Power Products, Inc.

Michael Lamb Dominion Virginia Power

Paul Griffin Doble Engineering Company

ABSTRACT The purpose of this paper is to provide a summary of the results of a failure investigation of a 400 MVA, 512.5/22 kV single-phase Generator Step-Up transformer, and present the recommendations of the investigation. The failure occurrence led to an extensive root cause investigation by Mitsubishi Electric, Dominion, and other industry experts. The findings of the investigation suggested that negative pressure existed within the main tank which resulted in air bubble formation. It was determined that the most likely cause of the negative pressure was an inadequate conservator tank breather system and an extended cooling pump operating time of a few hours prior to energization. This allowed air bubbles to form and collect in the HV bushing turret causing a reduction in the dielectric strength of the oil and led to a voltage breakdown between the 500 kV bushing shield and the bushing turret. Furthermore, there is strong correlation with this transformer failure and those of other catastrophic 500 kV shell form ODAF cooled transformer failures that Dominion experienced in the 1980’s, which were thought to be caused by static electrification but no obvious signs were discovered due to the extent of the damage. INTRODUCTION The North Anna Nuclear Power Station consists of two 900 MW nuclear generating units and a 500 kV switching station. Unit 1 began commercial operation in June 1978 and Unit 2 followed in December 1980. The two generator step-up transformer banks are each currently comprised of three single phase 512.5-22 kV 400 MVA ODAF 65°C rated shell-form transformers originally manufactured by Mitsubishi Electric in 2005 at their Ako, Japan factory. The transformers have a constant oil pressure system (COPS), 7925 gallon total oil volume and three cooler banks - each consisting of four fans and one circulating pump and an on-line combustible gas and moisture monitor. FAILURE EVENT On October 29, 2008 at approximately 16:40, while preparing to place Unit 2 back on-line following a planned refueling outage, the “C Phase” generator step-up (GSU) transformer experienced an internal fault. The fault occurred approximately four minutes after the main generator field was flashed. Just prior to the fault, the generator stator output voltage was approximately 22 kV and the generator output breakers in the 500 kV switching station were open. Two of the three cooler banks were correctly operating at the time of the failure. Prior to the failure, the combustible gas levels as indicated by routine dissolved gas analyses and the on-line combustible gas monitor were within acceptable limits and no increasing trends were identified. Immediately following the failure event, data from the digital fault recorders was reviewed and the findings indicated a “bolted” 500 kV high side fault on the “C Phase” GSU transformer. The maximum fault current on the 22 kV side of the GSU bank was recorded at 41,500 amperes. The fault condition was interrupted in the proper sequence and time durations, which included the operations of the Generator Reduced Speed Overcurrent Relay and the GSU rapid pressure rise “2 of 3” relay scheme. The generator field breaker tripped in less than five cycles, but since there was no generator output breaker the fault remained on the circuit for several seconds longer as the residual field of the generator continued to supply fault current.


2-12

INITIAL SITE INVESTIGATIONS Power station personnel were quickly dispatched to inspect the Unit 2 GSU bank following the event. They quickly discovered oil leaking from the pressure relief devices of the “C Phase” transformer with no fire present. Also, it did not appear that the main tank had ruptured, but the tank was physically deformed in several locations. No other external abnormalities were discovered at that time. After the transformer bank was isolated, the “C Phase” transformer was fully tested and abnormal results were discovered with the insulation resistance and transformer turns ratio tests. Also, the high voltage bushing capacitance test suggested that the bushing was damaged. Post event oil samples were analyzed and the combustible gases in the oil had increased to unacceptable levels. After draining the oil, the transformer was internally inspected by Dominion and Mitsubishi personnel and they quickly discovered the lower end of the high voltage bushing (ABB style 550W2000UE) was severely damaged with at least 50% of the porcelain missing. A large amount of the porcelain shards and carbon contamination was found on top of the coils. Significant arc damage was discovered between the internal epoxy coated corona shield of the high voltage bushing and the adjacent turret wall indicating a possible high voltage breakdown. The shield appeared to be installed correctly and no evidence existed that indicated a cause for the voltage breakdown. All internal lead connections were found correctly installed and no physical damage was discovered on them. The gas accumulation relay failed to operate during the failure event. The oil level gauge on the conservator tank initiated a low oil alarm approximately 88 minutes after the event.

Damaged High Voltage Bushing Figure 1


3-12

Arc Damage on Bushing Turret Wall Bushing Shield with Arc Damage

Figure 2 Figure 3 The 500 kV bushing was removed and the bushing turret and the current transformers (installed just above the bushing shield) were fully inspected and no evidence of contamination or moisture ingress was discovered. A closer examination of the bushing shield noted heat damage and holes, which appeared to be the point of flashover. Strike marks were found on the lower end of the turret which aligned with the strike marks of the bushing shield. Noted in the turret was a distinct internal line with a clean area below the line and a carbon cover area above the line, indicating the final oil level inside the transformer after the failure event. The bushing corona shield was installed well below this internal line within the turret. The 500 kV bushing was sent to the ABB bushing manufacturing facility in Alamo, Tennessee, where it was originally manufactured in 2005. After inspecting the bushing, ABB felt that the bushing did not appear to have failed internally and it was most likely not the cause for the transformer failure. In order to confirm this hypothesis, ABB recommended replacing the lower porcelain section and flange in order to fully test the bushing. After being reconstructed and reprocessed, the bushing was tested and the results were satisfactory. Following the tests, the bushing was disassembled for further analysis. The condenser was torn down, dimensionally checked, and no abnormalities were discovered. Furthermore, the lower porcelain fragments were closely analyzed and no electrical arc tracking was found on the interior wall of the porcelain. All of the findings confirmed that the high voltage bushing was not the initiator of the transformer failure. The site inspection continued with a full dismantling of the existing transformer to carefully inspect the core and coils of the transformer in order to search for other signs of trouble that may have helped contribute to the transformer failure. The upper tank section was next removed which exposed the core and coil assembly, which was carefully disassembled piece-by-piece under close supervision. The main core laminates, coils, insulation parts, leads, t-beams, and core ground straps were all individually inspected and no indications of tracking, static electrification, or other failure mechanisms were found within the core and coil assembly. From the results of the site inspection, it was determined that the problem appeared to be unique to the Unit 2 “C Phase” transformer, and not a common problem that could be present in the other similar transformers at the site. Based on this result, the plant was returned to service. ROOT CAUSE ANALYSIS A thorough root-cause analysis was performed by Mitsubishi Electric, Dominion, and other industry experts, as part of the investigation of this event. The purpose of the root cause analysis was to find the true cause of the failure in order to ensure that the appropriate countermeasures could be developed and implemented in order to prevent reoccurrence of the problem in the future. As the initial cause of the failure was not evident, an initial root cause analysis fault tree was created as an investigation tool, starting with the observed failure, and branching out to a


4-12

wide range of possible causes, ranging from possible design issues, manufacturing issues, component issues, operational issues, and external influences to name a few. All of these possibilities were evaluated in detail, and operational records, investigation observations and detailed analysis would need to be collected and reviewed in order to further narrow this wide range of possibilities. In reviewing the updated root cause analysis after completion of the initial site investigation, several possibilities had been carefully eliminated based on the results obtained. However, a few possibilities remained open, specifically theory involving a metal particle near the high voltage bushing shield, and another theory involving the location of air bubbles in the region around the high voltage bushing shield. From the initial investigation, it was not clear as to which of these remaining possibilities was the actual root cause of the failure. Additional research and experiments would be needed in order to further narrow the remaining possibilities in order to find the true root cause. FACTORY MOCK-UP TESTING In order to further refine the root cause analysis, it was decided to perform detailed laboratory mock-up testing using both scaled-down and full-sized models of various key components and assemblies of the transformer. In addition, laboratory testing was performed on some actual components removed from the transformer, such as the high voltage bushing. Detailed testing procedures to simulate conditions present on the in-service transformer were carefully developed in order to try and re-create the failure mode in the laboratory, based on the remaining possible theories from the root cause analysis. These laboratory mock-up tests were performed at the Mitsubishi Electric Ako factory from January 2009 through April 2009 under the witness of Dominion. A summary of the mock-up tests performed, and the test results observed, are described in the following sections.

Particle Tests One of the remaining theories in the root cause analysis was the possibility of a metal particle from the CT junction terminal board in the high voltage bushing turret dislodging and contacting the high voltage bushing corona shield, causing a breakdown. During the site investigation, no actual evidence of metal particles inside the transformer or missing materials from CT wiring terminals were found, and the likelihood of a particle dislodging after three years of operation at precisely the time of start-up of the transformer from an extended outage period seemed unlikely. However, it remained a possibility, and it was decided to perform laboratory testing to try and recreate this theory. The maximum particle size generated in the high voltage bushing turret area was deemed to be a 6 mm metal particle from a full-length shaving on a ring terminal wiring connection. This size of metal particle could theoretically cause an electrical breakdown at approximately normal operating voltage under the right conditions. A full-scale 500 kV bushing and turret tank was provided for the test, and a particle was located near the high voltage bushing internal corona shield. AC voltage was gradually applied in incrementally increasing steps for durations of 5 minutes per step, until an electrical breakdown was detected. Partial discharge was also measured during the test, and the actual observed breakdown voltage was recorded for each test, and the breakdown points noted. In all test cases, the actual breakdown voltage for the particle test were significantly higher than rated operating voltage of the transformer, and in some cases a breakdown did not even occur up to applied voltages of greater than 1.46 times rated voltage before the tests were stopped. Another test was performed in order to try and create particles of approximately 6 mm in length by fastening and unfastening a sampling of the CT wiring junction terminals repeatedly, which were determined to be the method that could potentially create the largest particle sizes in the bushing turret area if they went undetected during the assembly of the transformer. However, the results were that the actual maximum particle size that could be generated was no larger than 2 mm long. A particle of this size would not generate a breakdown in service unless an extremely high voltage was applied much greater than the normal operating voltage that was present when the failure actually occurred.


5-12

In addition, a further test was performed to simulate the dropping of various samples of metal particles of different shapes and sizes from the CT junction terminal area to the bottom of the bushing turret tank, with simulated oil flow in the tank as would be experienced during operation of the transformer. The particles were tracked as they dropped past the area of the corona shield. At the site, the actual failure location between the corona shield and bushing turret tank was approximately 150 degrees rotation in the cylindrical tank as compared to the location of the CT wiring junction terminal. The particle dropping tests were not able to replicate this, as all the sample particles dropped only migrated a maximum of approximately 90 degrees rotation from the CT wiring junction terminal. From the results of these various tests combined with the previous investigation observations, it was concluded that the particle theory was not a likely probability as being the true root cause of the failure experienced.

Air Bubble Tests The other remaining possible theory from the root cause analysis was from air bubbles being generated inside the transformer if negative pressure were somehow present on the oil inside the transformer. If the negative pressure was significant enough, the dissolved gasses typically contained in the transformer insulating oil, namely nitrogen, oxygen and carbon dioxide…the major gas components found in ambient air, would be pulled from the oil and form many small air bubbles in the oil inside the transformer. If these bubbles were to build up, they could reduce the dielectric strength of the oil, leading to an electrical breakdown. Under normal operation, there should not be a condition of negative pressure on the oil inside the transformer. However, if the constant oil pressure system was not functioning properly due to a significant restriction on the breathing system, a negative pressure could develop once the oil cooled from its normal operating temperature (approx. 70 deg. C in summer) and reached equilibrium temperature with the ambient air over a long shut-down period, in which the daily ambient temperature had also dropped significantly from the start of the shut-down period in early September until the transformer re-energization date of October 29. The oil temperature at the time of the failure of the transformer was only 9 deg. C. This temperature difference would cause the oil level inside the transformer to contract, and the breather system to draw additional air into the bladder system to take up the additional space in the conservator tank. However, the condition of the breather system was found to be clogged with dirt and debris during the site investigation. This condition could have prevented air from being drawn into the bladder, and the dropping oil level with the breather system clogged and not able to expand would cause a negative pressure to be created on the oil inside the transformer. If the temperature differential were great enough, the negative pressure developed on the oil could be significant enough to begin pulling air bubbles out of the oil. Conservator System and Air Bubble Generation Tests In order to verify if the negative pressure caused by the clogged breathing system could have developed to a low enough pressure to begin pulling air bubbles out of the oil, a full-sized mock up of the upper transformer tank area, conservator tank, piping and constant oil pressure system was manufactured. Additional models were created in which Transformer insulating oil adjusted with the same gas content as that of the oil present in the failed transformer, approximately 20,000 ppm of dissolved air, was used to fill the mock-up assembly to operating level. The breather clogging was simulated and the oil temperature was then dropped from 70 deg. C to 9 deg. C. Significant negative pressures of -8.1 psig were generated on the oil. Additional tests were performed on the transformer oil samples in a large vessel where the temperature could be adjusted precisely in a heating/cooling chamber. An oil pump was connected to the vessel to circulate the oil, and negative pressure was applied to the oil by using a vacuum pump system to adjust the oil pressure. In these tests, significant negative pressures were placed on the oil, and the oil pump would be placed in operation. In these tests, no air bubbles would be observed in the vessel when the oil was still, but once the oil pump was turned on, the oil motion would cause a significant amount of air bubbles to form. It was observed that once the negative pressure on the oil in the vessel approached approximately -10 psig, and the oil pump was in operation, a significant amount of air bubbles would be generated. The exact negative pressure at which air bubbles would start to form in the oil is dependent on the properties of the specific oil used, and largely depends on the air solubility characteristics of the oil and the kinematic viscosity of the oil. The solubility of air in the transformer oil decreases with decreasing temperature, so it is generally possible to generate air bubbles at lesser negative pressures with decreasing oil temperatures as the oil reaches a supersaturated condition sooner than based on pressure alone.


6-12

Other tests were performed to vary the gas content of the oil, vary the number of pumps running, as well as to adjust the range of temperatures and pressures on the oil, and it was found that once a significant negative pressure was placed on the oil and the oil pumps turned on, air bubbles would be created in the oil. The gas content of the oil, and number of pumps in operation did not have a significant effect on the amount of air bubbles generated. In one test, after operation of one oil pump for one hour at negative pressure, a volume of approximately 16.9 liters of air bubbles accumulated inside the mock-up tank. Repeating the test with two oil pumps in operation for one hour generated an accumulated volume of 15.3 liters of air bubbles inside the mock-up tank. Applied Voltage Test with Air Bubbles Present in Oil Another full-scale mock-up 500 kV bushing assembly and bushing turret tank was manufactured, in which the oil pressure could be adjusted to a negative pressure by means of a vacuum pump, and an oil pump would then circulate the oil inside the mock-up tank. This test would generate air bubbles inside the oil tank when the oil was under significant negative pressure, much like the other tests performed. AC voltage was then gradually applied in incrementally increasing steps for durations of 5 minutes per step, until an electrical breakdown was detected. Partial discharge was also measured during the test, and the actual observed breakdown voltage was recorded for each test, and the breakdown points noted. In all test cases, the PD activity was more erratic than the previous particle test, often with sudden bursts of PD as high as 5,000 pC observed, and then dropping back down to lower levels, and then spiking again once the actual breakdown occurred in the test model. In all cases, the actual breakdown voltage for the bubble occurred at voltages slightly less than the rated operating voltage of the transformer, and in all cases, the breakdown occurred at a time somewhere between 1 minute and 5 minutes after the voltage was applied to the test model. These results exhibited a striking similarity to the actual failure occurrence of the transformer, as the failure occurred after rated voltage had been applied to the transformer for a period of approximately four minutes.

500 kV Bushing Mock-Up Tests Figure 4

Cooling System Tests As a further test, the unit coolers and oil pumps from the failed transformer were sent to the OEM’s Climatic Laboratory in order to perform full-scale mock-up testing on a complete cooling system loop under various conditions and temperatures in order to further examine the air bubble generation phenomenon. The oil pressure on the cooling system was also adjustable by using a vacuum pump to create negative pressure. In addition, acoustic emissions sensors were mounted on the oil pumps to detect noise from pump cavitations as the pressures became negative.


7-12

The tests were performed while using the climatic laboratory to create a variety of ambient temperatures over a range from 9 deg. C to 40 deg. C.

Cooler System Test Setup

Figure 5 As the oil pressure dropped below 0 psig (below atmospheric pressure) and turned to negative oil pressures, it was observed that the acoustic emissions sensors would detect increasing noise from the oil pumps, indicating that cavitations were occurring at the pump impellers in the negative pressure condition. Once the oil pressure near the pumps reduced to -2.8 psig and below, the acoustic emissions from the pumps became significantly louder. Small air bubbles could be seen in the area of the oil pumps as the oil pressure turned negative. For oil temperatures of 20 deg. C and below, as the negative pressures reached approximately -8.5 psig and below, there was an observed significant increase in the amount of air bubbles generated. For higher oil temperatures in the range of 36 to 40 deg. C, the behavior observed was similar to the lower temperature tests, except that a significant amount of bubbles would not be generated until negative pressures of approximately -10.0 psig were obtained. Once the oil pressures increased to positive pressure greater than 0 psig, the air bubbles were observed to disappear from the oil. After completing the laboratory mock-up testing and analyzing the results, the root cause analysis was updated. Based on the results obtained, the most likely cause of the failure seemed to be from air bubbles being generated during the oil pump operation during the start-up process. This appeared to be due to the presence of negative pressure on the oil in the main tank of the transformer from an improperly functioning constant oil pressure system. In order to confirm that this theory was indeed possible to occur in service, it was decided to perform a further test on an actual complete installed transformer of a similar design in the field to see if the laboratory tests could be recreated. FIELD PROOF OF THEORY The existing spare transformer at the North Anna Power Station was selected as the most appropriate unit to perform the field testing on in order to verify the most-likely remaining theory of air bubble generation. This spare transformer represented a complete full-scale model virtually identical to the actual transformer that experienced the failure. The field testing could be safely performed on the spare transformer without taking the operating transformers out of service and interrupting the plant operation. Also, the planned field testing was safe, non-destructive testing that would not need any voltage applied to the main circuit of the transformer itself, and would not risk damaging the spare transformer.


8-12

Field Test Setup In order to verify the existence of air bubbles inside the spare transformer during the field testing, various oil piping sections and tank covers, including a cover on the high voltage bushing turret area, were fitted with acrylic windows in order to visually inspect the oil condition inside the transformer at various points on the transformer. Additionally, manifolds were created to add pressure transducers to accurately monitor the oil pressure at various locations on the transformer tank and cooling system piping. These pressure transducers were connected to a data acquisition system in order to record the various measured pressures inside the transformer during the performance of the field tests.

Field Test Arrangement

Figure 6 Acoustic emissions measurements were also taken at the external tank walls of the transformer at various locations, and were calibrated in order to monitor acoustic activity inside the transformer during the testing. Field Test Results The field tests were performed during the middle of April, 2009 at site, as the ambient temperatures during this time would be similar to the ambient temperatures at the time of the transformer failure in October of the previous year. A first run of tests was performed on the spare transformer simulating normal operating conditions with a fully functioning constant oil pressure system. The gas content of the oil was adjusted to approximately 20,000 ppm of air to simulate the oil present in the failed transformer at the time of the incident. The oil pumps were run for a period of four hours and the pressures at various points on the transformer were monitored. All areas of the transformer and cooling system were confirmed to have positive pressure on the oil during the test, and thus a negative pressure condition was not created under normal operating conditions of the transformer. No air bubbles were detected in the transformer during this test. Also acoustic emissions levels detected were minimal during this test. Similar tests were repeated on the spare transformer by adjusting the oil pressure by pulling vacuum on the conservator system bladder, simulating an improperly functioning system. When the tests were repeated with negative pressures on the oil inside the transformer, the acoustic emissions from inside the transformer increased due to bubble formation and possibly cavitations of the oil pumps and the generation of air bubbles inside the transformer. The point at which air bubbles were observed was approximately -8.0 psig oil pressure measured near the top of the conservator tank. The air bubbles were first observed near the oil pumps, but were also visible inside other areas of the transformer, including the high voltage bushing turret, shortly thereafter.

Location of Pressure Transducer for cooler inlet

Acrylic View Window

#1 Cooler Unit

Cooler #3

Cooler #2

COPS


9-12

These test results were significant as they validated that indeed it was possible to generate air bubbles inside the transformer during cool oil temperature conditions at negative oil pressures that could be achieved if the constant oil pressure system was not operating properly, due to a clogged breathing system. Once the air bubbles were generated, they would circulate inside the transformer tank, including the high voltage bushing corona shield area. From other tests, it was observed that a dielectric breakdown could occur between the bushing corona shield and tank wall at less than normal operating voltage. These results confirmed that the theory of the transformer failure being caused by air bubble generation inside the transformer due to an improperly functioning breather system was entirely possible with the conditions that were present at the time of the transformer failure.

Presence of Air Bubbles in Oil Piping Under Negative Oil Pressure Figure 7

An additional test was performed on the spare transformer to take DC electrostatic charge density measurements near the high voltage bushing corona shield area during operation of the cooling system of the transformer in various conditions. This further confirmed that the static electrification phenomenon was not present on these transformers. The test results obtained were well below maximum allowable criteria values, the highest value measured still being a factor of three times less than the maximum permissible levels under the most extreme-case conditions and oil temperatures. These tests further verified that static electrification was not a possible cause of the failure. CONCLUSIONS Mitsubishi Electric’s reduced and full scale tests performed at their factory and the tests performed on the existing North Anna spare transformer (duplicate design as the failed unit) confirmed that air bubble formation is possible when a negative gauge pressure condition exists within the main tank while oil circulating pumps are operating during cold temperature conditions, even with de-gassed oil. It was determined that the most likely cause of the negative pressure within the failed unit was an inadequate or constrained conservator tank breather system and an extended cooling pump operating time prior to energization, which allowed air bubbles to form and collect in the HV bushing turret causing a reduction in the dielectric strength of the oil. This led to the voltage breakdown between the 500 kV bushing shield and the bushing turret. A blocked or constrained conservator system with cooling oil temperatures can produce a vacuum condition within transformers. Transformers with conservator tank systems and oil directed air forced (ODAF) base rated cooling designs are more susceptible to this phenomena since some oil circulating pumps and fans are required to be operating when the transformers are initially energized and the transformer is cool. Oil natural air natural (ONAN) based rated transformers allow energization to take place with no forced cooling operating until the transformer has heated up and forced cooling equipment (if present) go into operation at temperature set points. The heating of the oil prior to the forced cooling equipment is called to operate allows a potential vacuum lock within the main tank to equalize itself and not create the conditions that could create the bubble formation.


10-12

Dominion has identified at least two failures in the 1980’s of single phase 500 kV Westinghouse shell form GSU transformers which likely failed due to bubble formation similar to the North Anna unit in 2008. Subsequent to these failures, as per Westinghouse’s recommendation, the existing nitrogen blanket systems were changed in the field to a constant oil preservation system (COPS). The two GSU transformers failed catastrophically within hours of energization and each case the damage was so great that a detailed investigation was not possible to determine the root cause. It was assumed at the time that the transformers had failed due to some type of dielectric failure mode, such as static electrification. The small, antiquated breathers on the new conservator systems were deemed suspect following the failures since the conservator tanks remained filled with oil even after the main tanks had ruptured during the internal faults. Following the failure of the second unit, the breather system on a sister unit which had received the new conservator system similar to the other units, was replaced with a larger breather system which allowed an increased air flow. That unit did not experience a failure event upon re-energization and has been operating for many years thereafter. Here are some important findings discovered during the failure investigation:

Extra strength transformer tank designs are more important for GSU transformers whenever there are no generator output breakers and the transformers must sustain the generator winding down while feeding a possible fault within the unit. This significant energy has a tendency to create internal pressures that can likely exceed the tank withstand capacity, especially for high voltage faults. Most transformer tanks would have ruptured for the failure event at North Anna. The Mitsubishi tank design allowed the failed transformer to sustain a high fault current magnitude for an extended period of time without a catastrophic tank rupture or fire. This allowed a more detailed teardown and root cause analysis helping to pin point the likely cause of the failure.

Concerns over high voltage bushings due to recent industry events required extensive analysis of the ABB bushing which was used within the North Anna GSU transformers. The design proved robust for this event. ABB proved that it could successfully sustain this type of failure condition by retesting the North Anna bushing after replacing the lower porcelain, and the resulting test results showed no signs of degradation.

The disassembly and teardown of the failed unit revealed a very well made shell-form design without deformation or problems with the core, coils, or tank structure. This design suggests it can handle significant thru fault energy.

Extra safety precautions are needed when working around bushings with damaged porcelain since they can be structurally unstable. The damaged 500 kV bushing within the North Anna unit still had the compressing force of the spring assembly, which was estimated to be close to 50,000 lbs. It is highly recommended that damaged portions of bushings be fully secured with thick protective wrapping, especially when the bushings are being handled or moved.

Based on the lessons learned with the failure investigation of the North Anna unit, the following transformer design standards will be applied on some existing critical ODAF base rated transformers (including the existing GSU transformers at North Anna) and on all future ODAF rated transformers:

Pressure transducers shall be installed near the cover of the transformers to enable on-line pressure monitoring. Each transducer shall have an isolation valve and bleeder port to allow for routine calibration and replacement without having to reduce the oil level in the main tank. The pressure transducers shall be wired into the existing PLC monitoring system and alarm logic shall be added to initiate an alarming.

Duel dehydrating breathers shall be installed on the conservator tanks to minimize single point of failure for the potential that the airflow through one breather becomes constrained or blocked. In addition, one pressure vacuum bleeder gauge shall be installed just above the breathers on the connecting piping to the conservator tank. Also, the connecting piping between the breathers and the conservator tank shall have a minimum one inch inner diameter to allow unrestricted air flow.

The isolation valves between the conservator tank and the main tank shall have positive indication of their position which shall allow visual confirmation during routine inspections that the valves are in the correct position.


11-12

ACKNOWLEDGEMENTS The authors of the paper would like to express gratitude to the following companies and individuals for their contributions in supporting the failure investigation.

Mitsubishi Electric Corporation Mitsubishi Electric Power Products, Inc. ABB North Anna Power Station Dominion Virginia Power Doble Engineering Laboratories, Inc. Mistras Acoustics Mr. Paul Russman, Power Transformer Consultant Mr. Ron Barker, Power Transformer Consultant Mr. Haden Kefauver, MPR Consultant

© 2011 Doble Engineering Company -78th Annual International Doble Client Conference All Rights Reserved

12-12

BIOGRAPHY C. Swinderman has been employed at Mitsubishi Electric Power Products, Inc. since 1999, and currently works as the Product Line Manager of the Transformer Department. He is a member of CIGRÉ and the IEEE Transformers Committee, currently serving as working group chair for the revision of IEEE 638 – Standard for the Qualification of Class 1E Transformers for Nuclear Power Generating Stations, as well as participating in a number of other working groups. Mr. Swinderman received his Bachelor of Science in Mechanical Engineering from the Pennsylvania State University.

M. Lamb has been employed at Dominion Virginia Power since 1988, and currently works as a Consulting Engineer in the Electric Transmission Operations Department. He is a member of CIGRÉ and the IEEE Transformers Committee. Mr. Lamb received his Bachelor of Science in Electrical Engineering from the Virginia Military Institute.

Mr. Griffin has been with Doble since 1979 and held several positions and is currently Vice President of Consulting and Testing Services. Since joining Doble, Mr. Griffin has published over 60 technical papers pertaining to testing of electrical insulating materials and laboratory diagnostics. He is a Fellow of ASTM and a member of Committee D-27 on Electrical Insulating Liquids and Gases. He was formerly ASTM Subcommittee Chairman on Physical Test, ASTM Section Chairman on Gases in Oil, and the Technical Advisor to the U.S. National Committee for participation in the International Electrotechnical Commission, Technical Committee 10, Fluids for Electrotechnical Applications. Mr. Griffin is a member of the IEEE Insulating Fluid Subcommittee of the Transformer Committee.

Documents

Relay