05000286/LER-2007-002
| Indian Point 3 | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(B), System Actuation 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| 2862007002R00 - NRC Website | |
Note: The Energy Industry Identification System Codes are identified within the brackets ().
DESCRIPTION OF EVENT
On April 6, 2007, during a hold at approximately 92% reactor power, after power ascension from an outage, an automatic reactor trip (RT) {JC} occurred at 1109 hours0.0128 days <br />0.308 hours <br />0.00183 weeks <br />4.219745e-4 months <br />, due to a turbine-generator trip as a result of a fault on the 31 main transformer {EL}. All control rods {AA} fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser {SG}. There was no radiation release.
The Emergency Diesel Generators (EDG) {EK} did not start as adequate offsite power remained available. Two of three 138 kV offsite power feeders to the Buchanan substation {FK} tripped as a result of the event. The Auxiliary Feedwater (AFW) System {BA} automatically started as expected due to Steam Generator (SG) {AB} low level from shrink effect. An investigation into the cause of the event and a post transient evaluation was initiated.
Prior to the event all Control Rods were fully withdrawn from the reactor core (except Control Bank D) and in manual, both Main Boiler Feedwater Pumps (MBFPs) {SJ} were in service, AFW Pumps (AFWPs) were in standby, the EDGs were in standby, and off-site power was in service. The plant was holding at approximately 92% reactor power for testing in accordance with 3PT-Q87B, "Channel Functional Test of Reactor Coolant Temperature Channel 421." A catastrophic fault occurred on the 31 transformer (XFMR} phase B bushing which was sensed by the generator protection system primary and backup lockout relays {86P and 86BU} and a turbine-generator trip signal was initiated that resulted in a RT. An investigation in the transformer yard discovered a failed 345 kV phase B bushing on the 31 main transformer and a fire with the transformer fire protection deluge system {KP} actuated. The 31 main transformer fire was reported to the control room (CR) at approximately 1111 hours0.0129 days <br />0.309 hours <br />0.00184 weeks <br />4.227355e-4 months <br />. Subsequently, the CR Shift Manager (SM) directed sounding of the fire alarm and dispatched the fire brigade (FB). The fire brigade leader reported to the CR, at approximately 1121 hours0.013 days <br />0.311 hours <br />0.00185 weeks <br />4.265405e-4 months <br />, that the fire was extinguished but the FB was continuing to apply foam. The fire was extinguished in less than 15 minutes therefore, the Emergency Plan (EP) Emergency Action Level (EAL) 8.2.1 was not applicable for declaration of an unusual event. However, at approximately 1140 hours0.0132 days <br />0.317 hours <br />0.00188 weeks <br />4.3377e-4 months <br />, the CR SM received reports that personnel saw an explosion occur at the main transformer. Based on the verbal report of an explosion, the entry condition (explosion) was met for EP EAL 8.2.2 and a Notification of Unusual Event (NUE) was declared at approximately 1143 hours0.0132 days <br />0.318 hours <br />0.00189 weeks <br />4.349115e-4 months <br />. The NUE was terminated at 1254 hours0.0145 days <br />0.348 hours <br />0.00207 weeks <br />4.77147e-4 months <br />.
On April 6, 2007, at 1159 hours0.0134 days <br />0.322 hours <br />0.00192 weeks <br />4.409995e-4 months <br />, a one hour emergency notification per 10CFR50.72(a)(1)(i) was made to the NRC (Log Number 43272) for declaration of an NUE based on EP EAL 8.2.2. At 1440 hours0.0167 days <br />0.4 hours <br />0.00238 weeks <br />5.4792e-4 months <br />, an update notification was made to report a four hour non-emergency notification for a RT while critical that included the eight hour non-emergency notification for actuation of the AFW system. The RT was reported under 10 CFR 50.72(b)(2)(iv)(B) and the AFW actuation reported under 10 CFR 50.72(b)(3)(iv)(A). The event was recorded in the Indian Point corrective action program (CAP) as CR-IP3-2007-01834. The trip of the breakers for two offsite feeders to the Buchanan substation was recorded in CR-IP2-2007-01533.
The 31 Main transformer, manufactured by Westinghouse {W120}, is one of two main generator output transformers designed to step up the three phase 22,000 volts output by the generator to 345,000 volts for power transmission to the electric power grid. The 32 main transformer was manufactured by General Electric (GE).
Cause of Event
The direct cause of the RT was a turbine-generator trip due to actuation of generator protection system primary and backup lockout relays (86P, 86BU) that sensed a fault from a failure of the 31 main transformer 345 kV phase B bushing.
The root cause was indeterminate as the catastrophic failure destroyed most of the evidence. Engineering postulates that the bushing fault developed internal to the bushing possibly due to thermal cycling of the bushing during its years of service that lead to gas bubbles (voids) in the bushing oil. The gas bubbles resulted in dielectric breakdown due to partial discharge until the breakdown was severe enough to result in failure to condense the voltage. The 345 kV then exited at the weakest point and arced to the steel transformer tank leaving a hole in the bushing conductor and rapid increase in combustible gases. The most probable cause was a design weakness associated with condenser type high voltage GE bushings used in Phase B whose design develops problems affecting dielectric insulation. Documented GE design weaknesses included: 1) design flaw where gaps existed at the ends of the internal insulation paper/core allowing for the formation of gas bubbles leading to partial discharge and increased dielectric losses, 2) the bushing condenser design incorporated alternate paper layers printed and plain where the ink developed capacitance properties allowing for voltage tracking across the paper causing corona action and burning, 3) the bushing flex seal design for thermal cycling would move and crack resulting in compromise of the seal, 4) age of the phase B GE Type U bushing which was an original early design with 30 years of operation.
Corrective Actions
The following corrective actions have been or will be performed under Entergy's Corrective Action Program to address the cause and prevent recurrence:
- The 31 main transformer was replaced with a spare transformer that uses a different bushing design.
- Testing and inspection was performed on the 32 main transformer, the replacement transformer for the failed 31 main transformer, the unit auxiliary transformer and Hi voltage equipment. Cleaning and replacement as necessary of degraded and failed components was performed.
- Engineering will establish Doble acceptance criteria for large transformers and include the criteria in applicable documents. The completion of an approved acceptance criteria is scheduled by August 31, 2007.
- Applicable transformer outage PM procedures will be revised to require Engineering review and trending of test data and to specify acceptance criteria for power factor (PF) and capacitance testing. Revisions of applicable procedures are scheduled to be revised as necessary by September 30, 2007.
- All available Doble data for transformers will be trended and access to the trend data provided on a common median. Scheduled completion date is September 30, 2007.
- An independent failure analysis of the failed bushing will be performed by an engineering contractor and the report results reviewed by engineering for any necessary corrective actions. Completion of engineering review is scheduled for November 2, 2007.
- An extent of condition was performed and concluded the issue is related to GE condenser Type U bushings which are only used on the main transformers.
The 32 transformer has two GE Type U bushings but are of a newer design which is considered free from the issues with the original design. The replacement transformer has different high voltage bushings that have an improved design and have not experienced similar problems. Unit 2 has two new Siemens main transformers installed in 2006 with Type COTA bushings manufactured by Trench. This design is different from the GE Type U and there has been no industry issues with the COTA type bushing design.
Event Analysis
The event is reportable under 10CFR50.73(a)(2)(iv)(A). The licensee shall report any event or condition that resulted in manual or automatic actuation of any of the systems listed under 10CFR50.73(a)(2)(iv)(B). Systems to which the requirements of 10CFR50.73(a)(2)(iv)(A) apply for this event include the Reactor Protection System (RPS) including RT and AFWS actuation. This event meets the reporting criteria because an automatic RT was initiated at 1109 hours0.0128 days <br />0.308 hours <br />0.00183 weeks <br />4.219745e-4 months <br />, on April 6, 2007, and the AFWS actuated as a result of the RT. The failure of the 31 main transformer did not result in the loss of any safety function. Two of three 138 kV offsite power breakers [Breaker F1 (Feeder 96951) and Breaker F7 (Feeder 95891)] to the Buchanan substation tripped as a result of the event. One offsite feeder (96952) to the Buchanan substation remained available therefore, there was no safety system functional failure reportable under 10CFR50.73(a)(2)(v).
Subsequent to the RT at 1109 hours0.0128 days <br />0.308 hours <br />0.00183 weeks <br />4.219745e-4 months <br />, operations was notified at approximately 2100 hours0.0243 days <br />0.583 hours <br />0.00347 weeks <br />7.9905e-4 months <br />, that 138 kV offsite power breaker Fl (Feeder 96951) and breaker F7 (Feeder 95891) had opened and were subsequently closed at 1215 hours0.0141 days <br />0.338 hours <br />0.00201 weeks <br />4.623075e-4 months <br />. Loss of the feeders required entry into Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1 Condition A. TS 3.8.1 required action A.1, is to perform surveillance requirement SR 3.8.1.1 within one hour due to not having independent offsite power feeds into the Buchanan substation for Indian Point Energy Center's (IPEC) 138 kV and 13.8 kV offsite feeders. The IPEC control room operators had not complied with the TS requirement as they were not notified of the condition by the Con Edison District Operator. The failure to perform TS SR 3.8.1.1 was not a TS prohibited condition. As a result of the RT, the required action of TS 3.8.1 Condition F.1 to be in Mode 3 in six hours was met, and the completion of SR 3.8.1.1 did not require the action of F.2 (Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />) as SR 3.8.1.1 was completed at 2135 hours0.0247 days <br />0.593 hours <br />0.00353 weeks <br />8.123675e-4 months <br />.
PAST SIMILAR EVENTS
A review of the past two years of Licensee Event Reports (LERs) for events that involved a RT from a failure of the high voltage electric power system identified no applicable LERs.
Safety Significance
This event had no effect on the health and safety of the public. There were no actual safety consequences for the event because the event was an uncomplicated RT with no other transients or accidents. Required primary safety systems performed as designed when the RT was initiated. There were no risk related components out of service at the time of the RT. The AFWS actuation was an expected reaction as a result of low SG water level due to SG void fraction (shrink), which occurs after automatic RT from full load. The AFWS actuated and provided required FW flow to the SGs. The AFWS capacity is sufficient to provide the minimum required FW flow to the SGs. There were no significant potential safety consequences of this event under reasonable and credible alternative conditions. This event was bounded by the analyzed event described in FSAR Section 14.1.8, "Loss of External Electrical Load." RCS pressure remained below the set point for pressurizer PORV or code safety valve operation and above the set point for automatic safety injection actuation. Following the RT, the plant was stabilized in hot standby.