05000327/LER-2010-002
| Docket Numbersequential Revmonth Day Year Year Month Day Yearnumber No. 05000 | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| Initial Reporting | |
| 3272010002R00 - NRC Website | |
I. PLANT COND1TION(S) SQN, Unit 1 was operating at approximately 26 percent power during power ascension following the Unit 1 Cycle 17 refueling outage that ended 11/15/2010 when the manual reactor trip was initiated.
II. DESCRIPTION OF EVENT
A. Event:
On November 16, 2010, at 2210 Eastern Standard Time (EST), SQN, Unit 1 was manually tripped based on decreasing steam generator (SG) [EIIS Code AB] level in Loop 4. Prior to the reactor trip, reactor power was at 26 percent and ascending following completion of the Unit 1 Cycle 17 refueling outage. At 2148, the main control room (MCR) was notified that a moisture separator reheater (MSR) safety valve [EIIS Code RV] had lifted and would not reseat. At 2206, the turbine was manually tripped to isolate the steam leak. Following the turbine trip, automatic SG level control [EllS Code JB] did not maintain SG level. Operations personnel took manual control; however, SG level could not be recovered. A manual reactor trip was initiated by Operations personnel as a result of a low narrow range SG level.
The feedwater level controller for the Loop 4 SG was unable to control the level because of the failure of a main steam dump valve controller [EIIS Code SB]. During a subsequent investigation, the main steam dump valve controller was found with the power plug partially disengaged.
During the refueling outage, the controller had been moved from one rack location to another to support the digital feedwater modification on SQN, Unit 1. This required the power cord to the controller to be unplugged, moved, and cables relocated. Upon reconnection of power, the power cord was not correctly plugged back into the controller. The controller function was not modified. There was no installation testing identified in the design change notice or the associated work order for the functionality of the controller.
B. Inoperable Structures, Components, or Systems that Contributed to the Event:
Main Steam Dump Valve Controller C. Dates and Approximate Times of Major Occurrences:
DateO Description November 16, 2010 The MCR was notified that a MSR safety relief valve had at 2148 ESTOlifted. Operators entered Abnormal Operating Procedure (AOP)-S.05, "Steam or Feedwater Leak.
2202 ESTOOperators entered AOP-C.03, "Rapid Shutdown or Load Reduction," as a result of being unable to isolate the steam leak.
2206 ESTOOperators initiated a manual turbine trip. Following the turbine trip, the Loop 4 SG level controller did not automatically control level. Operators took manual actions but SG level could not be recovered.
2210 ESTOOperators entered Emergency Procedure (E)-0, "Reactor Trip or Safety Injection," and initiated a manual reactor trip.
2236 ESTOOperators exited applicable emergency procedures, and entered General Operating (GO) Instructions 0-GO-6, "Power Reduction From 30 Percent Reactor Power to Hot Standby.
November 19, 2010 An inspection performed under a work order identified that the power plug for the main steam dump valve controller was partially disconnected.
D. Other Systems or Secondary Functions Affected:
No other systems or secondary functions were affected by this event.
E. Method of Discovery:
The MCR was notified that a MSR safety relief valve had lifted.
F. Operator Actions:
Upon notification that the MSR safety relief valve had lifted, Operations took actions as required by plant procedures and performed a manual turbine trip. Following the turbine trip, automatic SG level control did not maintain SG level. Operations took manual control; however, SG level could not be recovered. A manual reactor trip was initiated by the operating crew. After the reactor trip, the operating crew took actions necessary to stabilize the unit in a safe condition and maintained the unit in hot standby, Mode 3.
G. Safety System Responses:
The plant responded as expected for the conditions of the reactor trip.
CAUSE OF THE EVENT
A. Immediate Cause:
The cause of initiating a manual turbine trip was a MSR relief valve lifted because of foreign material lodged between the seat and the disk of the gland sealing steam check valve. The immediate cause of the reactor trip was that following the turbine trip the main steam dump valve controller did not operate to control steam flows. This led to a manual reactor trip when the Loop 4 SG level fell below the time delayed reactor trip setting.
B. Root Cause:
The root cause of the reactor trip was determined to be a failure to identify and perform adequate installation testing on a main steam dump valve controller following its Cycle 17 refueling outage. The failure to perform installation testing prevented the identification of the failure to properly connect the power cord to the steam dump controller resulting in a failure of the controller to perform its design function following the turbine trip.
C. Contributing Factor:
A contributing cause for this event was the failure to ensure that both of the locking devices engaged on the power cord when it was reattached. A thorough inspection would have identified that the power cable was not fully locked into place.
IV.� ANALYSIS OF THE EVENT SQN, Unit 1 reactor power was at 26 percent and ascending following completion of a scheduled refueling outage. Prior to the event, the reactor coolant system (RCS) pressure was approximately 2235 pounds per square inch gauge (psig). Following the turbine trip, RCS pressure peaked at 2267 psig before oscillating between 2190 and 2240 psig because of SG level swings. Following the reactor trip, the minimum RCS pressure was approximately 2117 psig, well above the pressure that would have initiated a safety injection signal (1870 psig). The RCS minimum temperature following the trip was approximately 533 degrees Fahrenheit and remained within technical specification (TS) limits. The minimum pressurizer level following the trip was 16 percent. This plant response was expected because of the low initial power level and low decay heat as the plant was in power ascension following a refueling outage. No TS limits were exceeded and the Updated Final Safety Analysis Report (UFSAR) analysis of this event remained bounding.
The UFSAR states that the plant should be able to withstand a turbine trip up to 50 percent power without requiring a reactor trip. During this event, a manual reactor trip was initiated by Operations personnel after manual actions were taken to recover SG level were unsuccessful.
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:
Corrective actions included performing an inspection of the main steam dump valve controller that identified the power cord was unplugged and plugging it back in. A visual inspection of the six control components that were moved as part of the digital feedwater modification was performed.
Testing was performed in the SQN simulator to verify that an unplugged main steam dump valve controller would cause the conditions and events that occurred prior to the manual reactor trip. The results confirmed that a partially disconnected power cord to the controller would have caused a loss of SG level control that necessitated the.trip.
B. Corrective Actions to Prevent Recurrence:
The corrective actions are being managed through the SQN Corrective Action Program.
Applicable plant procedures regarding modification installation and installation testing will be revised to add additional verifications and reviews.
VII. ADDITIONAL INFORMATION
A. Failed Components:
None.
B. Previous LERs on Similar Events:
A review of previous reportable events within the last three years identified that there has been a manual reactor trip following a turbine trip as a result of a MSR safety relief valve being unable to seat (LER 1-2009-004); however, there were no previous similar events that were a result of inadequate installation testing.
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. Unplanned Scram with Complications:
This condition did not result in an unplanned scram with complications.
VIII. COMMITMENTS
None.
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