05000328/LER-2012-001
| Docket Numbersequential Revmonth Day Year Year Month Day . Yearnumber No. | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| 3282012001R00 - NRC Website | |
I. PLANT CONDITION(S)
At the time of the event, SQN Unit 2 was operating at approximately 100 percent rated thermal power (RTP).
II. DESCRIPTION OF EVENT
A. Event:
On August 16, 2012, at approximately 1926 Daylight Savings Time (DST), Main Control Room (MCR) annunciator [EIIS-IB) alarmed, indicating low flow in reactor coolant system (RCS) [EIIS AB] loop 4. Reactor coolant pump 2-4 (RCP) [EIIS Code AB, P] tripped because a relay failure energized the trip coil of RCP 2-4 breaker. As a result of the low flow condition, the Unit 2 reactor [EIIS-JC] automatically tripped from approximately 100 percent power and was followed by an automatic turbine trip. MCR operators promptly initiated emergency operating procedures and responded to the event in accordance with plant procedures. They promptly diagnosed the plant conditions, took the actions necessary to stabilize the unit, and maintained the unit in hot standby, MODE 3.
A bridge and megger test on RCP 2-4 motor was successfully performed on August 17, 2012, validating the trip was not associated with a motor failure.
Unit 2 RCP 2-4 ground fault relay actuated without a valid signal. The relay energized the trip coil, which in turn, opened the breaker for RCP 2-4 and caused a low flow condition and reactor trip. During postmortem testing, TVA determined that a metal oxide varistor in the GR-5 relay, designated as device 50G on breaker locations that feed motors and transformers, failed, causing a standing trip signal.
Inspection of the 6900 volt breaker associated with Unit 2 RCP 2-4 discovered a standing trip on the breaker with the ground fault relay tripped; the relay flag was not energized. Bench testing of the GR-5 relay indicated that the relay failed and had a fixed trip signal. No evidence of damage on the relay was identified with the exception of some discoloration around a high wattage resistor.
On August 16, 2012, at 2209 DST, NRC was notified, in accordance with 10 CFR 50.72(b)(2)(iv)(B), due to reactor protection system actuation and 50.72(b)(3)(iv)(A), engineering safety feature actuation.
B. Inoperable Structures, Components, or Systems that Contributed to the Event None C. Dates and Approximate Times of Major Occurrences:
August 16, 2012 at 1926 DST RCP 2-4 Motor trip out August 16, 2012 at 1926 DST RCP Bus 4 Undervoltage annunciator August 16, 2012 at 1926 DST Unit 2 Reactor Trip and Turbine Trip August 17, 2012 at 1205 DST GR-5 ground fault relay removed and trip signal removed. Relay was replaced.
D. Other Systems or Secondary Functions Affected:
No other systems or secondary functions were affected by this event.
E. Method of Discovery:
The RCP trip and subsequent reactor and turbine trips annunciated on the MCR panels.
F. Operator Actions:
Operations personnel responded to the reactor trip by performing actions in accordance with Emergency Procedure E-0, "Reactor Trip or Safety Injection," and various plant procedures including, Emergency Subprocedure ES-0.1, "Reactor Trip Response." Following completion of ES-0.1 actions, operations implemented Abnormal Operating Procedure (AOP) R.04, "Reactor Coolant Pump Malfunctions.
The crew noted the RCP 2-4, 6900 volt circuit breaker opened leading to an undervoltage condition which caused the motor trip-out alarm.
G. Safety System Responses:
With the exception of, Steam Generator Number 4 Feedwater Inlet Flow Control Valve (EllS JB), which indicated dual position following the trip (validated locally to be closed),, safety related equipment operated as designed. Unit 2 entered MODE 3.
Ill.0 CAUSE OF THE EVENT
A. Immediate Cause:
The immediate cause of the reactor trip was the trip coil for the RCP 2-4 breaker energized due to the inadvertent operation of the GR-5 relay.
B. Root Cause:
The root cause was determined to be the Preventative Maintenance (PM) instructions and implementation frequency is inadequate on GR-5-relays in critical systems. The service life of the component was reached and there is no guidance to replace the relay in the PM.
C. Contributing Factor:
The Preventative Maintenance Optimization template for solid state protective relays recommends replacement every 8 to 10 years. A weakness in the preventative maintenance program was found and is being addressed to implement a program for lifecycle management practices for relays.
IV.0 ANALYSIS OF THE EVENT Prior to the event, SQN Unit 2 was operating in MODE 1 at approximately 100 percent RTP with RCS pressure and temperature near the nominal value of approximately 2233 pounds per square inch gauge (psig) and approximately 578 degrees Fahrenheit (F). Both the motor driven and the turbine driven auxiliary feedwater (AFW) [El IS BA] pumps and the atmospheric relief valves (ARV) were available.
SQN Technical Specification 3.2.5, that states, in part, "The following departure from nucleate boiling (DNB) parameters shall be maintained within the limits shown on Table 3.2-1: a. RCS average temperature, b. pressurizer pressure, and C. RCS total flow rate.
Following the reactor trip, RCS pressure rapidly decreased due to the decreasing RCS average temperature and the associated shrinking of coolant volume. The minimum RCS pressure was approximately 2010 psig, well above the pressure that would have initiated a safety injection signal (1870 psig). Pressurizer [EllS AB] pressure recovered gradually, rising to 2261 psig before dropping back to normal operating pressure.
As heat removal from the steam generators (SG) [EIIS AB] decreased as a result of the increased steam pressure, the decrease in RCS temperature slowed and the rate of coolant shrinkage decreased. This allowed operation of the pressurizer heaters to restore RCS pressure to its nominal value. Because the maximum RCS pressure was only slightly above its nominal value following the reactor trip, pressurizer safety relief valves and power operated relief valves [EIIS AB] did not actuate.
The DNB limit for RCS average temperature of less than or equal to 583 degrees F was not exceeded. The loss of nuclear heat generation resulted in a decrease in RCS temperature to approximately 534 degrees F.
The RCS loop 4 indicated flow decreased to approximately 12 to 18 percent flow near the time of the reactor trip due to the loss of RCP 2-4. At that time, RCS flow in the remaining three loops was approximately 113 percent flow. Forced flow was maintained by RCP's 2-1, 2-2 and 2-3 as indicated by the loop flow transmitters and also by a lack of change in loop temperatures.
The main feedwater flow rate was at nominal full power value prior to the reactor trip. When RCS average temperature dropped below 550 degrees F, main feedwater was isolated [EIIS SJ]. The AFW system was initiated following the reactor trip on SG low-low level. AFW flow in all loops was reduced below 300 gpm to mitigate the decrease in RCS average temperature and also due to recovering SG levels. AFW in loop 4 was subsequently decreased to approximately 0 gpm as the SG 4 level remained higher than the other loops due to the loss of RCP 2-4. The steam dump system and ARV's operated as expected to remove decay heat.
The Updated Final Safety Analysis Report (UFSAR) event most similar to this reactor trip is the Partial Loss of Forced Reactor Coolant Flow event described in UFSAR Section 15.2.5. In the analysis of this event, a partial loss of flow involving loss of two RCPs was assumed. The resultant RCS flow rate prior to the reactor trip was greater than RCS flow rate assumed in the Partial Loss of Forced Reactor Coolant Flow analysis.
The plant responded as expected for the conditions of the trip. No Technical Specification limits were exceeded and the UFSAR analysis of the event remained bounding.
V. ASSESSMENT OF SAFETY CONSEQUENCES
Based on the above "Analysis of The Event," following the trip all safety related equipment operated as designed, the AFW system actuated as expected and decay heat removal was provided using ARVs and the steam dump system. All DNB parameters remained within limits during this event. As a result, this event did not adversely affect the health and safety of plant personnel or the general public.
VI. CORRECTIVE ACTIONS
A. Immediate Corrective Actions:
Operations personnel responded to the reactor trip as prescribed by emergency procedures. Component testing was performed and the affected GR-5 relay was replaced on RCP 2-4 breaker.
B. Corrective Actions to Prevent Recurrence:
The following corrective actions to prevent recurrence were identified in the root cause analysis and are being tracked in accordance with the SQN Corrective Action Program.
1, The PM instructions for ABB/ITE relays in critical systems are being revised to a frequency of every five refueling cycles for relay replacement.
2.Replace the Unit 1 ABB/ITE relays classified as critical that have been in service greater than five refueling cycles, based on Operations review of critical components that are directly related to causing a plant trip or Limiting Condition for Operation (LCO) entry for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or less.
3.Replace the Unit 2 ABB/ITE relays classified as critical that have been in service greater than five refueling cycles, based on Operations review of critical components that are directly related to causing a plant trip or LCO entry for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or less.
VII. ADDITIONAL INFORMATION
A. Failed Components:
The failed component was a GR-5 ground fault relay, made by ABB.
B. Previous LERs on Similar Events:
A review of previous reportable events for the past three years did not identify any similar events.
C. Additional Information:
The corrective action document for this report is Problem Evaluation Report (PER) 596978.
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 event did not result in an unplanned scram with complications.
VIII. COMMITMENTS
None