05000286/LER-2002-003
| Indian Point Unit 3 | |
| Event date: | 11-15-2002 |
|---|---|
| Report date: | 01-14-2003 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv), System Actuation |
| 2862002003R00 - NRC Website | |
DESCRIPTION OF EVENT
Note: The Energy Industry Identification System Codes are identified within the brackets {) On November 15, 2002, at approximately 0957 hours0.0111 days <br />0.266 hours <br />0.00158 weeks <br />3.641385e-4 months <br />, while at 100% steady state reactor power, an automatic reactor trip (RT) occurred. The RT occurred due to the actuation of the reactor protection system (RPS) {JC) whose logic was satisfied by a main turbine trip (TT) {JD) signal. A main turbine trip occurred as a result of the actuation of the main generator primary (86P) and backup (86BU) lockout relays {86). The main generator trip actuation was caused by the actuation of the electrical protective relaying direct trip circuitry from the 345 KV {FK) main output breakers {BKR). The 345 KV {FK) main output breaker {BKR) No. 3 faulted resulting in main output breakers Nos. 1, 3, and 6 opening and electrically isolating plant output. The protection associated with the breakers actuated the lockout relays (86P and 86BU). Breaker No. 5 had opened approximately one minute prior to the event for unknown reasons.
Central Control Room (CCR) {NA) operators observed the rod bottom lights, RT First Out Annunciator (Turbine Trip), and TT First Out Annunciator (Generator Primary and Backup lockout Relays) {IB). CCR Operators then entered Emergency Operating Procedure E-0, "Reactor Trip or Safety Injection," at approximately 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br />, and then transitioned to procedure ES-0.1, "Reactor trip Response.
Primary systems which failed to function properly was No. 32 neutron source range detector {IG) which failed low. Secondary systems that failed to function properly were the 36 circulating water pump {KE) which tripped, the 34 circulating water pump which transferred to standby drive and valve MS-PCV-1175- 1 {SB) which failed to shut properly. Station offsite power was maintained throughout the event and there was no automatic start of the Emergency Diesel Generators {EK). All rods {AA) fully inserted. The Auxiliary Feed Water System (AFWS) (BA) automatically started as expected due to steam generator level changes. Main turbine generator (MTG) overspeed occurred as expected. MTG overspeed was verified to be within limits and no unexpected or abnormal vibrations were identified. At approximately 1110 hours0.0128 days <br />0.308 hours <br />0.00184 weeks <br />4.22355e-4 months <br />, CCR Operators transitioned to Plant Operating Procedure (POP) 3.1, "Plant Shutdown from 45% Power." The plant was stabilized in the hot shutdown "condition and the transient terminated. At approximately 1149 hours0.0133 days <br />0.319 hours <br />0.0019 weeks <br />4.371945e-4 months <br />, a four hour non-emergency notification (Incident Log No. 39375) was made to the NRC for a RPS actuation in accordance with 10CFR50.72(b)(2)(iv)(B). Operations recorded the event in the corrective action program as condition report CR-IP3-2002-04550. A post transient evaluation was performed (No. 02-02) on November 15, 2002.
Main output breaker No. 3 is a 345 KV, Type 345GA25-30, manufactured by ITE Imperial Corporation. There are six sets of contacts (fixed and moving) mounted inside each tank. The contacts are enclosed in high gas pressure chamber to quench the arc during contact disengagement between stationary and moving contacts.
CAUSE OF EVENT
The direct cause of the event was a RT due to the actuation of the reactor protection system by a main turbine trip that was the result of actuation of the main generator primary and backup lockout relays. The main generator trip actuation was caused by the actuation of the electrical protective relaying direct trip circuitry from the 345 KV main output breakers due to the failure of main output breaker No. 3. The apparent cause of breaker No. 3 failure was the phase to ground fault due to overheating caused by high resistance at the breaker contact surfaces. The high resistance at the breaker contacts were a result of breaker contact misalignment during previous maintenance in the spring 2001 refueling outage. Misalignment of the stationary and moving contacts caused overheating.
The overheating led to burning of the contacts, arcing inside the high pressure chamber causing Sulfur Hexafloride (SF6) insulating gas to lose its insulating value resulting in more arcing. Ultimately, a large arc caused a phase to ground fault resulting in a catastrophic failure of the breaker components. EPRI confirmed that operation of the breakers would not contribute any thing for misalignment. Therefore, engineering concluded the misalignment was most likely due to poor workmanship of the contract vendor. A review of vendor work determined that the same contractor that performed work on breaker No. 3 also worked on main output breaker No. 1 and 138 KV breaker No. BT5-6. Breaker No. 1 was tested and found to have elevated resistance readings on two of three phases. The cause of breaker No. 5 opening is being investigated by Con Edison.
CORRECTIVE ACTIONS
The following corrective actions have been or will be performed under the Corrective Action Plan (CAP) to address the causes of this event and prevent recurrence.
1. Corrective maintenance was performed on main output breaker No. 1 to bring it into manufacturer's specifications, the breaker tested and returned to service.
2. The capability of main output breaker No. 1 to support 100% power was verified prior to MTG sync to the grid. The unit was synchronized to the grid on November 21, 2002.
3. A monitoring plan was developed and implemented for main output breaker No. 1.
4. Main output breaker No. 3 was inspected, cleaned and refurbished and returned to service on December 13, 2002.
5. Breaker maintenance procedure BKR-008-ELC will be revised to include verification of contact alignment and recording of contact resistances before and after contact alignment.
6. An action plan will be developed to evaluate the reliability of the SF6 gas breakers installed at Indian Point 3 (Breakers 1, 3, BT5-6).