05000328/LER-2007-002
| Docket Numbersequential Revmonth Day Year Year Month Day Year 05000Number No. | |
| Event date: | 03-13-2007 |
|---|---|
| Report date: | 05-14-2007 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv), System Actuation 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| 3282007002R00 - NRC Website | |
I. PLANT CONDITION(S)
Unit 2 was operating at 100 percent power when the reactor trip occurred.
II. DESCRIPTION OF EVENT
A. Event:
On March 13, 2007, at 1527 Eastern standard time (EST) with Unit 2 operating at 100 percent power, the reactor was manually tripped as a result of partial loss of main feedwater flow to the steam generators (EIIS code AB). The immediate cause was failure of the 2A main feedwater pump control system (EIIS code SJ). Troubleshooting determined the problem to be within the 2A main feedwater speed indicating controller.
The root cause of the event was determined to be a faulty local/remote switch which is internal to the speed indicating controller.
B. Inoperable Structures, Components, or Systems that Contributed to the Event:
None.
C. Dates and Approximate Times of Major Occurrences:
March 13, 2007 Operations noticed that all four steam generator levels had at 15:22 EST begun to decrease and then steam generator level deviation alarms were received.
March 13, 2007 Operations noted the 2A main feedwater pump speed at —15:23 EST controller output was at zero output and the pump was at minimum speed.
March 13, 2007 Operations placed the 2A main feedwater pump speed at —15:24 EST controller in manual and attempted to raise pump speed.
The main feedwater pump speed did not increase.
March 13, 2007 Steam generator Loop 2 low-level alarm was received.
at —15:26 EST March 13, 2007 Operations initiated a manual reactor trip.
at —15:27 EST D. Other Systems or Secondary Functions Affected:
No other systems or secondary functions were affected by this event.
E. Method of Discovery:
During normal power operations, Operations noticed that all four steam generators levels had begun to decrease. This was followed by the receipt of steam generator level deviation alarms. It was noticed that 2A main feedwater pump speed controller was at zero output and the 2A main feedwater pump was at minimum speed.
F. Operator Actions:
Operations placed the 2A main feedwater pump speed controller in manual and attempted to raise pump speed. The main feedwater pump speed did not increase. After the Loop 2 steam generator low-level alarm was received, the Senior Reactor Operator directed that a manual reactor trip be initiated. Control Room personnel stabilized the unit in a safe condition and maintained the unit in hot standby, Mode 3.
G. Safety System Responses:
The plant responded to the reactor trip as designed.
Ill.CCAUSE OF THE EVENT A. Immediate Cause:
The immediate cause of the event was loss of process control to the 2A main feedwater pump resulting in a reduction in steam generator level and a subsequent manual reactor trip.
B. Root Cause:
The root cause of the event was a faulty local/remote switch which is internal to the 2A main feedwater pump speed indicating controller. This switch was found to be erratic and of poor quality.
C. Contributing Factor:
The K1 relay, which is internal to the main feedwater pump speed indicating controller, was determined to be a contributing cause. The K1 relay was found to be faulty.
IV. ANALYSIS OF THE EVENT
The plant systems responded to the reactor trip as designed. The reactor coolant system (RCS) average temperature was near 578.2 degrees F prior to the loss of main feedwater.
Following the reactor trip, the loss of nuclear heat generation resulted in a rapid decrease in RCS average temperature to 539 degrees F. As heat removal in the steam generators decreased as a result of increased steam pressure, the decrease in RCS temperature slowed. The introduction of cold auxiliary feedwater (AFW) resulted in a slower, but continued reduction in RCS temperature until AFW flow was reduced after the reactor trip.
RCS temperature then started to increase. RCS temperature remained within Technical Specification limits and bounded by the Safety Analysis Report (SAR) analysis.
The plant responded as expected for the conditions of the trip. No Technical Specification limits were exceeded and the SAR analysis of this event remained bounding.
V. ASSESSMENT OF SAFETY CONSEQUENCES
Based on the above "Analysis of The Event," this event did not adversely affect the health and safety of plant personnel or the general public.
VI. CORRECTIVE ACTIONS
A. Immediate Corrective Actions:
Control Room personnel responded as prescribed by emergency procedures. They diagnosed the plant condition and took necessary action to stabilize the unit in a safe condition. The 2A main feedwater speed controller was replaced by another controller that was procured, refurbished, bench calibrated, and installed in the plant.
B. Corrective Actions to Prevent Recurrence:
Corrective actions will include implementation of a design change to jumper the local/remote switch out of the circuit for the applicable controllers. Applicable preventative maintenance procedures are being reviewed to cycle the K1 relays at appropriate frequencies.
VII. ADDITIONAL INFORMATION
A. Failed Components:
The 2A main feedwater pump speed indicating controller failed as a result of a faulty local/remote switch and K1 relay which is internal to the 2A main feedwater pump speed indicating controller.
B. Previous LERs on Similar Events:
There have been no LERs on similar events in the last three years.
C. Additional Information:
None.
D. Safety System Functional Failure:
This event did not result in a safety system functional failure in accordance with 10 CFR 50.73(a)(2)(v).
E. Loss of Normal Heat Removal Consideration:
This condition did not result in a loss of normal heat removal.
VIII. COMMITMENTS
None.