05000425/LER-2010-001
| Vogtle Electric Generatin. Plant - Unit 2 | |
| Event date: | 02-18-2010 |
|---|---|
| Report date: | 04-16-2010 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(vii)(D), Common Cause Inoperability 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident |
| 4252010001R00 - NRC Website | |
CONTINUATION SHEET
� 2010 - 001 - 0
A. REQUIREMENT FOR REPORT
The VEGP Emergency Core Cooling System (ECCS) consists of three subsystems: centrifugal charging (high head), safety injection (intermediate head), and residual heat removal (low head).
Each of the three subsystems consist of two 100 percent capacity trains that are interconnected and redundant such that either train is capable of supplying 100 percent of the required flow to mitigate the accident consequences. Technical Specification 3.5.2 requires two trains of ECCS to be Operable in Modes 1-3. The design of the residual heat removal (RHR) subsystem at VEGP is such that each RHR pump must be capable of injecting into all four cold legs. There are two MOVs installed on the discharge of the RHR pumps that can isolate flow to the cold legs. One MOV isolates RHR injection flow to loops 1 and 2 cold legs while the other MOV isolates RHR injection flow to loops 3 and 4 cold legs. During the time the RHR to cold legs 3 and 4 MOV was closed, the low head accident required ECCS flow to the four cold legs from either RHR pump could not be assured. Therefore this condition is reportable under the following sections of 10CFR50.73:
10CFR50.73(a)(2)(v)(D), "Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.
10CFR50.73(a)(2)(vii)(D), "Any event where a single cause or condition caused...two independent trains...to become inoperable in a single system designed to mitigate the consequences of an accident.
B. UNIT STATUS AT TIME OF EVENT
At the time of the event on January 5, 2010 Unit 2 was operating in Mode 1 at 100 percent rated thermal power. There was no other inoperable equipment that contributed to this event.
C. DESCRIPTION OF EVENT
Technical Specification surveillance requirement (SR) 3.3.4.2 verifies each required remote shutdown panel control circuit and transfer switch performs the intended function every 18 months. At VEGP, there are two procedures that implement this surveillance requirement. One procedure contains all of the required components on the A train shutdown panel and another procedure contains all of the required components on the B train shutdown panel. Many of the components on the shutdown panel are capable of being operated with the unit at power (e.g.
during system outages) while others require the unit to be shutdown.
To ensure all components on a given shutdown panel are tested, Operations department personnel maintain a "master" copy of each procedure in the control room and update the "master" procedure as individual components are tested. Once all components are tested, the procedure is signed off as completed and sent to Document Control for retention.
On February 18, 2010 in preparation for an upcoming system outage on RHR Train A, the operator was reviewing the A train remote shutdown panel test procedure to determine which components could be tested. During the review it was noticed that the procedure had been revised on January 11, 2010 to add a caution to preclude stroking the RHR pump discharge to loops 1 and 2 cold leg isolation valve while at power. Subsequently, the operator reviewed the B train shutdown procedure and found that it had also been revised on January 11, 2010 to add a caution to preclude stroking the RHR pump discharge to loops 3 and 4 cold leg isolation valve while at power. The procedure revisions were as a result of a Condition Report that was initiated in August 2009 due to a similar event that had almost occurred on Unit 1 but had been caught prior to the valves being stroked. Once the operator reviewed the master copy of the B train shutdown panel test procedure on February 18, 2010, it was determined that the RHR to loop 3 and 4 cold leg MOV had been stroked closed on January 5, 2010. The test was performed six days prior to the procedure being revised to caution the user that the valve could not be stroked with the unit at power.
To perform the remote shutdown test procedure on this component requires that control be transferred to the shutdown panel and the valve stroked from the open to close position and then back to the open position. Once the valve stroke sequence was completed at the shutdown panel, control was transferred back to the control room. To ensure the valve control circuitry was functioning properly, the valve was stroked from open to close and then back to the open position from the control room handswitch.
A review of valve position indication on the plant computer determined that the valve was not in the fully open position for approximately 30 seconds during each stroke. However, during the time the valve was not fully open, an operator was continuously available to open the valve had the need arisen.
D. CAUSE OF EVENT
The cause of this event was due to cognitive error by Operations department personnel applying fundamental knowledge of the Emergency Core Cooling System configuration needed to satisfy Technical Specification Limiting Condition of Operations (LCO) requirements. Also, the procedure used to perform the test was inadequate since at the time the valve was stroked, it did not contain a caution to alert the operator that the valve could not be stroked with the unit at power.
U.S. NUCLEAR REGULATORY COMMISSIONNRC FORM 366A LICENSEE EVENT REPORT (LER)(9.2oo7) CONTINUATION SHEET 2010 - 001 0
E. ANALYSIS OF EVENT
This event represents a loss of safety system function since during the brief period of time the valve was closed, emergency core cooling accident required flowrate from the low head RHR pumps could not be assured. However, based on a risk assessment of the valve being closed for the short duration involved, the increase in both core damage frequency (CDF) and large early release frequency (LERF) were found to be negligible. Additionally, there were no events which required an ECCS actuation during the time the valve was closed. Based on these considerations, there was no adverse affect on plant safety or on the health and safety of the public.
F. CORRECTIVE ACTIONS
1. A new procedure was developed for performing the remote shutdown surveillance test for the RHR cold leg injection MOVs. This procedure contains the necessary cautions to alert the user that the procedure cannot be performed in Modes 1, 2 and 3.
2. The individuals involved with this event were coached to ensure an understanding of the relationships between surveillance procedures, Technical Specification LCOs, and use and applicability of Technical Specification Bases.
G. ADDITIONAL INFORMATION
I. Failed Components:
None 2. Previous Similar Event:
Licensee Event Report 1-1996-002 involved a similar event on Unit 1 in which this valve was stroked with the unit at power. The corrective actions from that event included counseling the operations department personnel, conducting a shift briefing and covering this event as part of the "Lessons Learned" segment during licensed operator re-qualification training.
These corrective actions to prevent recurrence proved not to be effective in preventing this event since they were one time actions that did not address the fundamental operator knowledge gap on the configuration requirements for the emergency core cooling system to ensure compliance with the Technical Specifications and accident analysis assumptions and further did not institutionalize the knowledge into plant procedures.
3. Energy Industry Identification System Codes:
Residual Heat Removal Low Pressure Injection System-BP