05000440/LER-2015-001
| Perry Nuclear Power Plant | |
| Event date: | 06-16-2015 |
|---|---|
| Report date: | 08-11-2015 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| 4402015001R00 - NRC Website | |
Energy Industry Identification System (EIIS) codes are identified in the text as [XX]
INTRODUCTION
On June 16, 2015, at 0452 hours0.00523 days <br />0.126 hours <br />7.473545e-4 weeks <br />1.71986e-4 months <br /> the control room was notified that during performance of surveillance test SVI-R22-T5074, "Division 3 4160 Volt Bus Undervoltage/Degraded Voltage Channel Calibration and Logic System Functional Test", the degraded voltage time delay relay [2] was found outside of the Technical Specification (TS) allowable value. The Division 3 Emergency Diesel Generator (EDG) [EK] had previously been declared inoperable for performance of this surveillance test on June 15, 2015, at 0735 hours0.00851 days <br />0.204 hours <br />0.00122 weeks <br />2.796675e-4 months <br />. The Division 3 EDG supports the High Pressure Core Spray (HPCS) system [BG], which is a single train safety system. On June 16, 2015, at 1134 hours0.0131 days <br />0.315 hours <br />0.00187 weeks <br />4.31487e-4 months <br />, a notification was made to the NRC Operations Center (Reference ENF 51159) in accordance with 10 CFR 50.72(b)(3)(V)(D) for an event or condition that could have prevented the fulfillment of a safety function. The relay was recalibrated and successfully tested. The surveillance was completed and the Division 3 EDG was returned to operable status on June 16, 2015, at 1117 hours0.0129 days <br />0.31 hours <br />0.00185 weeks <br />4.250185e-4 months <br />.
This event is being reported in accordance with 10CFR50.73(a)(2)(v) as an event or condition that could have prevented the fulfillment of a safety function. The Division 3 EDG supports the HPCS Emergency Core Cooling System (ECCS) which performs a safety function to mitigate the consequences of an accident. The function of HPCS is credited for several operational transients or analyzed accidents described in Chapter 15 of the Updated Safety Analysis Report (USAR).
EVENT DESCRIPTION
On June 16, 2015, the plant was operating in Mode 1 at 100 percent Rated Thermal Power. The plant was in a normal electrical line-up with all EDGs and all ECCS operable, with the exception of the Division 3 EDG, which had been declared inoperable for performance of surveillance testing on June 15, 2015 at 0735 hours0.00851 days <br />0.204 hours <br />0.00122 weeks <br />2.796675e-4 months <br />. The Division 3 EDG supports the HPCS System, which is a single train safety system.
On June 16, 2015, at 0452 hours0.00523 days <br />0.126 hours <br />7.473545e-4 weeks <br />1.71986e-4 months <br />, the control room was notified that during performance of surveillance test SVI-R22-T5074, "Division 3 4160 Volt Bus Undervoltage/Degraded Voltage Channel Calibration and Logic System Functional Test", the degraded voltage time delay relay was found outside of the TS allowable value at 272.66 seconds. The allowable value for this relay per TS 3.3.8.1 is between 180 and 270 seconds.
This relay is part of the degraded bus voltage logic to remove a faulty source of power from the Division 3 Safety Bus (EH13) [EB] and replace it with the Division 3 EDG. If voltage on EH13 drops to 3.8 kV (95 percent of nominal voltage) for 12 seconds, the EH13 VOLTAGE DEGRADATION alarm is received in the Control Room. If a Division 3 Loss of Coolant Accident (LOCA) signal is present then after 12 seconds the automatic loss of voltage actions occur, which include starting the EDG, primary offsite power breakers to EH13 opening, and the now running EDG connecting to the EH13 bus.
With no LOCA signal present, the degraded voltage condition is permitted to exist for 4 minutes before the actions for the loss of voltage would occur. The relay in question is the 4 minute timer for the non- LOCA logic. Loss of voltage actions will also occur through a different relay logic when bus voltage drops to 3010 Vac (75 percent of nominal) and three seconds have elapsed.
The relay was recalibrated per plant procedures and successfully passed the as-left performance test.
The surveillance test was completed and the Division 3 EDG was returned to operable status on June 16, 2015, at 1117 hours0.0129 days <br />0.31 hours <br />0.00185 weeks <br />4.250185e-4 months <br />.
CAUSE OF EVENT
The cause of the Division 3 degraded voltage time delay relay setpoint being outside the TS allowable value was setpoint drift and the setpoint not being centered within the allowable value range. The calibration setpoint of 240 seconds is not centered within the allowable value of 180 to 270 seconds. It is biased to the upper limit of 270 seconds.
SVI-R22-T5074 is performed on a 24 month frequency. The relay was initially installed in 2008 with an as left value of 234.11 seconds. It was tested again in 2010 and 2013, with as left values of 240.3 and 250.16 seconds respectively. On both occasions, the relay was not recalibrated because it was in the leave-as-is-zone of 225 to 255 seconds. Other similar relays used in comparable applications were evaluated and no issues were identified.
EVENT ANALYSIS
The Division 3 degraded voltage time delay relay is designed to allow the operator sufficient time to manually correct a degraded voltage condition, prior to loss of voltage actions initiating, while protecting equipment that normally operates during a LOCA condition from sustained operation at degraded voltage levels. The setpoint is based on safety-relatedmotor degraded voltage operating capabilities from the motor manufacture's specification. The design basis calculation shows that the maximum upper time limit for this relay is 300 seconds. The TS value of 270 seconds is based on a conservative assessment of motor degraded voltage operating capability. The Degraded Voltage time delay relay being 2 seconds beyond the TS allowable limit of 270 seconds would not have prevented the relay from functioning and initiating a Loss of Bus signal. The as-found value was within the analytical limit of 300 seconds; therefore, this is not considered a Functional Failure.
Probabilistic Risk Assessment (PRA) modeling indicates that with a loss of power event with no initial injection capabilities, time to core damage is greater than 15 minutes. Injection prior to this time is successful in the prevention of core damage. As such, a delay of 2.66 seconds would have no impact to the accident sequence. In the condition encountered for this analysis, the Division 3 EDG would have automatically initiated, albeit slightly outside of its TS allowable band. In the context of the PRA, no functional failure of the automatic start capability would be modeled as the EDG would have started and loaded the bus, within a time frame acceptable to PRA criteria.
The analysis of this event indicates no impact to the PRA model, and therefore no corresponding change in core damage frequency (CDF), and no corresponding change in the large early release frequency (LERF). The lack of change to CDF and LERF values are well below the acceptable thresholds of 1.0E-06/yr and 1.0E-07/yr, respectively, as discussed in Regulatory Guide 1.174.
Therefore the risk of this event is considered small in accordance with the Regulatory Guidance.
CORRECTIVE ACTIONS
Corrective actions are in place to center the time delay relay within the allowable value and also to adjust the leave-as-is-zone to allow more margin to the allowable value. In addition, the relay will be removed and replaced. The relay will then be sent to an offsite vendor for continued troubleshooting, if a different failure mode is identified, a Licensee Event Report revision will be issued.
PREVIOUS SIMILAR EVENTS
A review of LERs and the corrective action database for the past three years identified no similar events.
COMMITMENTS
There are no regulatory commitments contained in this report. Actions described in this document represent intended or planned actions, are described for the NRC's information, and are not regulatory commitments.