05000412/LER-2008-001
| Docket Number | |
| 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 |
| Initial Reporting | |
| ENS 44239 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation |
| 4122008001R00 - NRC Website | |
PLANT AND SYSTEM IDENTIFICATION
Westinghouse - Pressurized Water Reactor {PWR} Main Feedwater System {SJ} Auxiliary Feedwater System {BA} Main Turbine {TA} Condenser {SG}
CONDITIONS PRIOR TO OCCURRENCE
Unit 2: Mode 1 at approximately 16 percent power.
There were no systems, structures, or components that were inoperable at the start of the event that contributed to the event. [It is now understood that the main feedwater pump recirculation flow control valve did not experience any failure, contrary to the preliminary conclusion originally provided on May 24, 2008 in the 10 CFR 50.72 notification EN 44239.]
DESCRIPTION OF EVENT
During plant startup at the conclusion of the 2R13 refueling outage on May 24, 2008, Beaver Valley Power Station (BVPS) Unit 2 was slowly increasing reactor power in preparation for synchronizing the Main Turbine onto the grid, with power at approximately 16 percent. The Main Turbine was offline with the condenser steam dump valves in steam pressure (automatic) mode and all three steam generator bypass feedwater regulation valves in automatic. control. At approximately 09:22, a slow reactor power increase was begun. At approximately 09:28, steam generator water levels in all three steam generators started to trend down. The control room operator commenced a series of multiple manual control actions to restore / maintain steam generator water levels. During this transient, steam generator main feedwater pump 'B' was in service and its recirculation valve was observed to be cycling open and closed. In addition, condenser steam dump valves were observed to be opening and closing in response to changes in steam generator pressure.
At approximately 09:38, with the 'A' steam generator feedwater flow control bypass valve in a full closed position, a steam generator water level swell was noted as the 'A' steam generator narrow range water level reached the Hi-Hi steam generator level alarm and the Engineered Safety Features (ESF) Feedwater Isolation setpoint ( this valid ESF high level setpoint (P-14), the running steam generator main feedwater pump tripped, the remaining steam generator bypass feedwater regulating valves closed, and the Feedwater Containment Isolation Valves closed. The two motor-driven Auxiliary Feedwater System pumps started, as designed, upon an automatic trip of all running Main Feedwater Pumps. The Feedwater Isolation signal also closes the main feedwater regulating valves (which were already closed) and trips the Main Turbine (which was offline).
DESCRIPTION OF EVENT (continued) At approximately 09:40, the control room crew reset the Feedwater Isolation signal and restarted the IV main feedwater pump. At approximately 09:41, the motor-driven Auxiliary Feedwater System pumps were stopped and placed back into automatic control. At approximately 09:43, normal feedwater flow was re-established to the steam generators.
The reactor remained stable at approximately 16% reactor power.
REPORTABILITY
The unplanned automatic initiation of a Feedwater Isolation signal and the resultant automatic initiation of the Auxiliary Feedwater System due to tripping of the Main Feedwater pump was an event reportable pursuant to 10 CFR 50.72(b)(3)(iv)(A) as a valid actuation of the PWR emergency feedwater system listed in 10 CFR 50.72(b)(3)(iv)(B)(6). The NRC was notified of this event at 15:06 on May 24, 2008 (NRC Event Notification 44239).
Similarly, this event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a valid actuation of the emergency feedwater system listed in 10 CFR 50.73(a)(2)(iv)(B)(6).
CAUSE OF EVENT
The Operations crew on duty during this event was unfamiliar with steam generator level control using bypass feed regulating valves at low power with the main turbine not latched and in response made excessive manual changes in feedwater flowrate. There were numerous broken barriers and causal factors that allowed this worker knowledge deficiency to exist. Since any one of these barriers and causal factors could have potentially prevented the inadvertent Auxiliary Feedwater System automatic initiation, the root cause is considered to be the common factor in all of these issues. Thus, the root cause of this event is that the Operations Management Team, including the Shift Manager, failed to ensure the startup crew was staged for success in operating the plant in a low power configuration.
SAFETY IMPLICATIONS
The safety significance of the feedwater isolation on May 24, 2008 was very low. Steam generator inventory remained above the low water level trip throughout this event and its restoration.
As designed, feedwater isolation occurred when the "A" steam generator indicated narrow range level reached the high level setpoint of greater than or equal to 92.2 percent.
Following initiation of the automatic feedwater isolation signal, all ESF equipment responded as expected. The running steam generator main feedwater pump tripped, the remaining steam generator bypass feedwater regulating valves closed, the Feedwater Containment Isolation Valves closed, and the two motor-driven Auxiliary Feedwater System pumps started, as designed. The feedwater isolation signal also closes the main feedwater regulating valves (which were already closed) and trips the Main Turbine (which was offline).
Following the unplanned actuation, the feedwater isolation signal was reset, normal feedwater flow was re-established via the "B" main feedwater pump, and auxiliary feedwater pumps were manually secured and placed back into automatic control. There were no adverse effects identified to the main steam system from the indicated high water level in the steam generators. The reactor remained stable at approximately 16% reactor power.
At the time of the BVPS Unit 2 feedwater isolation, the only out-of-service components modeled in the Unit 2 Probabilistic Risk Analysis were the "A" & "B" containment instrument air compressors, with containment instrument air being supplied from station instrument air through the open cross-tie valve 2IAC-MOV131. Additionally, with the main turbine and generator offline, the breakers associated with the fast bus transfer function were still transferred to the off-site power supplies. Also, since the reactor power level was less than 40 percent, Anticipated Transients Without Scram (ATWS) concerns are not postulated. Using these assumptions and assuming a postulated Total Loss of Main Feedwater Initiating Event (i.e., setting the Probability to 1.0), the Conditional Core Damage Probability is very small.
Based upon the above, the safety significance of the event condition was very low.
CORRECTIVE ACTIONS
1. The BVPS Licensed Operator Retraining program will be modified to include simulator and classroom sessions that address manual operations of the bypass feedwater regulating valves at low power level, with a periodic re-training frequency.
2. Plant criteria on Just-In-Time (JIT) Training will be revised to require all control room crews and operators involved in plant startup/shutdown to attend the JIT Training.
3. Supplemental actions will be performed based upon additional performance gap analysis and safety culture assessment results.
Completion of the above and other corrective actions are being tracked through the BVPS corrective action program.
PREVIOUS SIMILAR EVENTS
A review found no prior BVPS Unit 1 and one prior BVPS Unit 2 Licensee Event Report within the last ten years for an event involving an actuation of the Auxiliary Feedwater System due to high steam generator water level.
- BVPS Unit 2 LER 2000-001, "ESF Actuation of Feedwater Isolation While Shutting the Plant Down for Refueling." This LER event resulted from lack of procedural clarity combined with simulation training not being consistent with actual plant response. The previous corrective actions were ineffective because 1) previous training to correct personnel knowledge errors was only performed one time, and 2) previous reinforcement of expectations/standards resulted in unclear expectations relative to the hierarchy of procedures.