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 Report dateSiteEvent description
05000440/LER-2017-0054 October 2017Perry

On August 14, 2017 at 2257, with both trains of the Annulus Exhaust Gas Treatment System (AEGTS) running in parallel, Secondary Containment vacuum momentarily degraded to 0.52" water gauge when AEGTS B was shutdown to Standby Readiness. After an approximately 15 second delay, AEGTS A responded to maintain the proper vacuum. Technical Specification (TS) Surveillance Requirement (SR) requires a minimum of 0.66" water gauge differential pressure to be maintained between ambient and annulus pressure. The failure to comply with SR caused Secondary Containment to be inoperable resulting in Technical Specification not being met.

The cause was determined to be equipment age-related degradation of the AEGIS A controller circuit card, which was subsequently replaced. There were no other event-related equipment malfunctions.

Since AEGTS is not a core damage mitigation system and is not credited in the PRA model to mitigate large and early containment releases, the inoperability of the AEGTS is determined to be of small safety significance. This event is being reported in accordance with 10CFR50.73(a)(2)(v)(C) and 10CFR50.73(a)(2)(v)(D) as an event or condition that could have prevented the fulfilment of a safety function.

05000440/LER-2017-0044 October 2017Perry

On August 8, 2017, at 1554 hours, while the plant was at 100 percent rated thermal power, during restoration from testing of the High Pressure Core Spray (HPCS) Suppression Pool (SP) Level High Instrumentation, unexpected as-left indications were found that impacted both of the required channels of instrumentation. With both SP level instruments inoperable, a loss of safety function existed.

While venting the sensing line, the HPCS system was aligned to the suppression pool water source. This source of water is HPCS's safety-related source of water. The automatic suction swap on high suppression pool level is implicitly assumed in the accident and transient analysis since it assumes that the HPCS suction source is the suppression pool.

Since the HPCS system was aligned to the suppression pool when the failure occurred, the assumptions of the accident analysis are met, and no safety system functional failure occurred.

The cause for the unexpected as-left indications is due to air entrained in the sensing line which came out of solution.

The safety significance of this event is considered to be small. This event is being reported under 50.73(a)(2)(v)(D) for a loss of safety function.

05000440/LER-2017-0011 May 2017PerryThe condition reported by this LER is the result of planned activities in support of Refueling Outage 1R16 at the Perry Nuclear Power Plant (PNPP) In Enforcement Guidance Memorandum (EGM) 11-003 Revision 3, the NRC provided enforcement guidance, applicable to boiling water reactor licensees, that addresses the reported condition Although this allowance is provided by the NRC's enforcement guidance, the planned activities are still considered reportable in accordance with 10CFR50 73(a)(2)(1)(B) as a condition prohibited by Technical Specifications From March 17, to March 24, 2017, PNPP conducted Operations with the Potential for Draining the Reactor Vessel (OPDRV) while in Mode 5 at zero percent power, without an operable Primary and Secondary Containment These activities were performed in accordance with the EGM 11-003, Revision 3, which allows the implementation of interim actions as an alternative to full compliance with Technical Specifications provided several conditions are met The OPDRV activities were planned activities that were completed following the guidance of the EGM and are considered to have low safety significance based on the interim actions taken Since these actions were preplanned, no cause determination was necessary As required by the EGM, a license amendment request will be submitted, based on the Technical Specifications Task Force traveler associated with generic resolution of this issue, by December 20, 2017
05000440/LER-2016-00424 February 2017Perry

On December 28, 2016, at 2119 hours (EST), standby liquid control (SLC) subsystem A was declared inoperable in accordance with the surveillance instruction for performance of a routine surveillance test. At 2229 hours, control room operators received an out-of-service alarm for SLC discharge valve B. With both subsystems inoperable, the SLC system was in a condition that required reporting under 10 CFR 50.72(b)(3)(v)(A) and 10 CFR 50.72(b)(3)(v)(D). At 2335 hours, the surveillance was completed and subsystem A was declared operable.

The cause for subsystem B inoperability was an indicated loss of continuity to one of the two firing circuits in the discharge valve due to a loose connection between a pin and jack on the connector. This was not a safety system functional failure since continuity was interrupted to only one of the two redundant firing circuits for discharge valve B and if an initiation signal was sent to the valve, it would have operated as designed and supported chemical injection to the vessel. The risk of this event is considered small in accordance with the regulatory guidance. The power supply cable was replaced and post maintenance testing was completed satisfactorily. The preventative maintenance task will be revised to include a step to inspect connection pins and jacks when changing the firing assembly. Additionally, the cable on the discharge valve for SLC subsystem A will be replaced and sent to FirstEnergy BETA Laboratory for analysis when the valve is replaced during the next refueling outage.

The analysis will be used to determine if a new preventative maintenance task is necessary for periodic replacement of these cables.

05000440/LER-2016-0028 April 2016Perry

On February 8, 2016, at 1503 hours, control room operators initiated a manual reactor protection system (RPS) actuation in response to rising temperature in the suppression pool. All control rods full inserted. Prior to the RPS actuation the plant was in mode 1 at approximately 96 percent rated thermal power. At 1500 hours, multiple safety relief valves (SRVs) partially opened due to an invalid reactor pressure vessel (RPV) pressure signal. Control room indications showed two SRVs remained open resulting in a suppression pool temperature rise. Suppression pool cooling was initiated and a plant cooldown to Mode 4 was initiated.

The direct cause of the event was a momentary pressure perturbation limited to the RPV B reference leg that caused the connected transmitters to sense RPV pressure and level changes that resulted in SRV actuation. Corrective actions include revision to plant procedures for operation of the RPV reference legs and associated purge panels, and changes to the time constants for the affected RPV transmitters.

The safety significance of this event is considered to be very small. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual actuation of the RPS.

05000440/LER-2016-0038 April 2016Perry

On February 11, 2016, at approximately 1505 hours with the plant in mode 4, an indicated loss of power to the division 1 4160 volt bus, EH11, occurred. An invalid undervoltage signal tripped the bus supply breaker, and the bus loads shed, as expected. The invalid undervoltage signal resulted in a loss of shutdown cooling. The division 1 diesel generator (DG) started and loaded the EH11 bus.

Subsequently the division 1 DG was manually shutdown due to cooling water not being available. This de-energized all division 1 equipment, including the train supplying shutdown cooling at the time. To comply with Technical Specification 3.4.10 the alternate decay heat removal (ADHR) system was credited as the alternate method of decay heat removal for the inoperable shutdown cooling system; even though other systems were available, the ADHR system was not filled and vented, thus, it was not immediately available. Shutdown cooling was re-established 42 minutes later from division 2.

A manufacturing defect in a fuse caused the event. A 10 CFR Part 21 report was filed by the supplier on March 22, 2016. This is being reported under 50.73(a)(2)(iv)(A) as an invalid actuation and 50.73(a)(2)(i)(B) for an operation or condition prohibited by technical specifications.

Corrective actions were taken to replace and analyze the defective fuse. Fuses with the same batch will be sent for analysis. The vendor's 10 CFR Part 21 analysis is also being tracked.

The safety significance is determined to be an event of very small risk significance based on a qualitative defensive in-depth risk assessment.

05000440/LER-2016-00123 March 2016Perry

At 2100 hours, on January 23, 2016, the Perry Nuclear Power Plant (PNPP) commenced a reactor shutdown to investigate unidentified leakage in the drywell. At 2122 hours, drywell unidentified leakage exceeded Technical Specification (TS) limits necessitating a plant shutdown as required by TSs. At 0357 hours, on January 24, 2016, while performing the shutdown required by plant TSs, the average power range monitors (APRM) became inoperable due to a calibration setpoint being out of tolerance in the nonconservative direction following a transfer of the reactor recirculation pumps to slow speed. This resulted in a loss of safety function for the APRMs. At 1007 hours, on January 24, 2016, with the plant at 8 percent power, during a feedwater shift to place the motor feed pump in service, reactor water level rose to the level 8 setpoint and the reactor protection system (RPS) automatically initiated, shutting down the reactor. Following the shutdown, a small leak was identified on the reactor recirculation loop "A" pump discharge valve vent line. The recirculation loop is part of the reactor coolant system; this resulted in a degraded condition and a condition prohibited by TS due to pressure boundary leakage.

The cause of the recirculation loop vent line leak was that the weld connecting the root appendage was not performed per the design drawing. The APRM calibration issue was caused by a change to the feedwater flow input to the heat balance. The cause of the reactor level rise and subsequent high water level scram was due to operator error in monitoring and manipulating feedwater system indications and controls.

The safety significance of this event is considered to be small. These events are being reported under; 50.73(a)(2)(i)(A), for completion of any plant shutdown required by the plant's TS; 50.73(a)(2)(ii)(A) for a condition resulting in the plant's principle safety barrier being seriously degraded; 50.73(a)(2)(i)(B) for a violation of Technical Specifications; 50.73(a)(2)(iv)(A) for actuation of the RPS while critical; and 50.73(a)(2)(v)(A) for a loss of safety function.

05000440/LER-2015-00111 August 2015Perry

On June 16, 2015, at 0452 hours, during performance of surveillance testing, a degraded voltage time delay relay was found outside of the Technical Specification allowable value.

The cause of the Division 3 degraded voltage time delay relay being outside the allowable value was setpoint drift and the calibration setpoint not being centered within the allowable value range. The relay was satisfactorily recalibrated in accordance with procedures and successfully passed the as-left performance test during the remainder of the surveillance testing and was made operable on June 16, 2015, at 1117 hours. Planned corrective actions include centering the time delay relay setpoint within the allowable value and relay removal for analysis and evaluation.

The safety significance of this event is considered to be small. The degraded voltage time delay relay initiates load shedding, isolates the Division 3 bus and starts the Division 3 Emergency Diesel Generator (EDG). The Division 3 EDG is the on-site power source for the High Pressure Core Spray System which is a single train system. Therefore, 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.

Additionally, as discussed in the Event Analysis section, this event is not considered a safety system functional failure because the as found setpoint was within the analytical design limit.

05000440/LER-2013-0049 December 2013Perry

On October 17, 2013, at 1300 hours, a review of industry operating experience regarding the impact of unfused Direct Current ammeter circuits in the Control Room determined the described condition to be applicable to the Perry Nuclear Power Plant resulting in a potentially unanalyzed condition with respect to 10 CFR 50 Appendix R analysis requirements. The original plant wiring design and associated safe shutdown analysis for the Class 1 E batteries control room ampere indications do not include overcurrent protection features to limit the fault current.

The cause of this event was determined to be a latent design error related to wiring and isolation that constituted a fire protection program deficiency which could adversely affect the ability to achieve and maintain safe shutdown of the plant in the unlikely event of a control room fire. A probabilistic risk assessment of this event determined the event to be of small safety significance.

The identified deficiency was corrected utilizing temporary modifications to the plant that eliminated the potential for a control room fire to induce a hot short. The corrective actions to permanently address this condition include the design and implementation of a permanent plant modification to isolate the indication circuits in the unlikely event of a control room fire.

This event is being reported in accordance with 10CFR50.73(a)(2)(ii)(B) as an unanalyzed condition.

05000440/LER-2013-0034 October 2013Perry

A planned power reduction commenced June 14, 2013, to inspect the Drywell for sources of unidentified leakage. Following a refueling outage completed in May 2013, the Drywell unidentified leakage was higher than levels prior to the outage. The Drywell inspection identified two leak sites, one of which was in the reactor coolant system (RCS) pressure boundary. A plant shutdown was conducted in accordance with Technical Specification 3.4.5, RCS Operational Leakage, to facilitate repairs. During the shutdown process and after the reactor was subcritical, the reactor protection system was actuated to insert the remaining withdrawn control rods.

The cause of the RCS pressure boundary leakage is a combination of stress corrosion cracking and fatigue or corrosion fatigue. A new vent valve assembly was fabricated and installed on the reactor recirculation system B flow control valve. Inspection of other vent and drain valves with similar configuration on the reactor recirculation system found no deficiencies. Design configuration options to address the cause will be evaluated.

The safety significance of this event is considered to be small. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(A), 10 CFR 50.73(a)(2)(ii)(A), and 10 CFR 50.73(a)(2)(iv)(A).

05000440/LER-2013-00223 May 2013Perry

On March 25, 2013, at approximately 1527 hours, maintenance personnel identified that a level instrument root valve for the control rod drive system, scram discharge volume (SDV) was closed and locked. With the valve in the closed position, the associated SDV float level switch, which provides input to the reactor protection system logic, could not perform its function and resulted in noncompliance with the Limiting Condition for Operation for Technical Specification

The cause of the event was a failure to follow procedures. During the last performance of a calibration surveillance test, the instrumentation and control technicians did not open the valve as required and left the valve in the closed position.

Independent verification of the valve position and locking device attachment failed to identify the error. Maintenance personnel promptly restored the valve to the locked open position. Corrective actions were administered through the internal performance management process. There were no system failures associated with this event.

The safety significance of this event is considered to be small. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as any operation or condition that was prohibited by the plant's Technical Specifications.

05000440/LER-2013-00121 March 2013Perry

On January 22, 2013, at 0332 hours, the reactor protection system (RPS) automatically actuated due to a loss of feedwater flow to the reactor pressure vessel (RPV). There were no complications during the shutdown as all control rods fully inserted and pressure was maintained by normal means. The High Pressure Core Spray (HPCS) and the Reactor Core Isolation Cooling (RCIC) systems actuated based on a valid reactor water level initiation and injected to restore RPV water level.

The cause of the event was failure of a balance-of-plant inverter/static transfer switch, which provides electrical power to the digital feedwater control system. A circuit card in the static transfer switch degraded, which affected operation of the inverter. The electrical loads serviced by the inverter/static transfer switch were placed on an alternate power source. This alignment will continue until permanent repairs are made which are currently scheduled for the next refueling outage.

The safety significance of this event is considered to be small. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in an automatic actuation of the RPS, HPCS, and RCIC systems, and Operational Requirements Manual section, which requires a Special Report submittal following an Emergency Core Cooling System actuation and injection into the reactor coolant system.

05000440/LER-2012-0022 August 2012Perry
05000440/LER-2011-00415 March 2012Perry

On November 16, 2011, at 2000 hours, it was determined that internal flooding calculation JL-083 contained undocumented assumptions regarding operator actions required to isolate a postulated Service Water system piping Moderate Energy Line Crack in the Control Complex Building.

The cause of this event was a calculation deficiency that credited operator actions to perform the appropriate system isolations without the actions being delineated in operating procedures. This deficiency existed since the original preparation and approval of the calculation (i.e., August 27, 1982). Corrective actions included development of procedural guidance to direct all required operator actions and installation of a temporary flood barrier. A permanent flood barrier will be installed in accordance with plant processes.

A probabilistic risk assessment was performed and this condition was determined to have small safety significance.

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(ii)(B) as a condition that resulted in the nuclear power plant being in an unanalyzed condition that significantly degraded plant safety.


05000440/LER-2011-00329 February 2012Perry

On October 18, 2011, at 0351 hours, the plant entered MODE 2 during plant startup. One of the two offsite power circuits required by Technical Specification (TS) 3.8.1, "AC Sources-Operating," was the delayed access circuit through the unit one auxiliary transformer. At 1619 hours, the manual disconnects for yard breakers S610 and S611 (isolation between offsite and onsite AC power distribution), were found to be open with danger tags installed. In this configuration, a TS Required Action was not performed within its designated Completion Time and a MODE change was made without satisfying the associated Limiting Condition for Operation (LCO). By 1730 hours, the danger tags were removed and the delayed access circuit was returned to OPERABLE status.

Switchyard equipment configuration, necessary to maintain reliable sources of offsite power, was not held to the same operational configuration standards required for plant controlled equipment, due to less than adequate policies governing the plant's switchyard configuration cognizance.

Corrective actions include completed and planned procedure revisions to ensure control room personnel are aware of switchyard configuration and training will be provided to appropriate plant personnel. The safety significance of this condition is considered to be small.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as any operation or condition which was prohibited by the plant's Technical Specifications.

05000440/LER-2011-0028 February 2012Perry

On September 26, 2011, at 0158 hours, the unit 1 startup transformer was taken out of service to perform scheduled maintenance. The unit 2 startup transformer and the manual unit 1 backfeed lineup were OPERABLE and were considered to be the two qualified offsite circuits required by Technical Specifications (TS). Further review of this configuration determined that the backfeed lineup could not be credited as a qualified offsite circuit. This review also revealed that required TS actions were not completed when the startup transformer was declared inoperable on September 26, 2011. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition which was prohibited by the plant's TS.

Transformer maintenance was secured and the unit 1 startup transformer was returned to service.

Subsequently the transformer tripped due to an internal fault.

On October 2, 2011, at 0100 hours, a planned shutdown was commenced to repair the unit 1 startup transformer. On October 2, 2011, at 1614 hours, plant shutdown was completed by manual actuation of the Reactor Protection System. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(A) for completion of any nuclear plant shutdown required by the plant's TS. Corrective actions for these events include approval of a License Amendment to clarify the use of a delayed access circuit as a qualified offsite circuit and installation of a replacement startup transformer. The safety significance of these events is considered to be small.

05000440/LER-2011-00123 August 2011Perrybe1ow
05000440/LER-2009-00120 August 2009Perry

On June 21, 2009, at.1750 hours, the reactor protection system (RPS) automatically actuated due to receipt of a turbine control valve fast closure signal.. All control rods fully inserted and there were no complications during the shutdown. Reactor coolant pressure and level were maintained within expected parameters.

The event was caused by receipt of an invalid high water level signal from moisture separator reheater (MSR) 1B instrumentation, whibh resulted in a main turbine trip, fast closure of the turbine control valves, and activation of the RPS. Incorrect adjustment of the MSR level switches following maintenance in the recent refueling outage was the direct cause for their actuation. Failure to evaluate industry operating experience, not documenting as-found deficiencies in the corrective action program, not considering non-safety equipment as important, and improper work package/procedure use and adherence contributed to this event.

The MSR level switches were subsequently adjusted and calibrated satisfactorily to assure proper operation. Maintenance procedures and templates will be revised to prevent recurrence of incorrect level switch adjustment.

The safety significance of this event is considered to be low. This event is reported in accordance with 10 CFR 50.73 (a)(2)(iv)(A) as an event or condition that resulted in a manual or automatic actuation of the reactor protection system including reactor scram or reactor trip.

05000440/LER-2006-0033 July 2006PerryOn May 2, 2006, while performing research for a calculation revision, it was discovered that one circuit of the Division 1 Emergency Diesel Generator (EDG) Control Room Pull-To-Lock (PTL) Control Switch was not designed to isolate the Control Room from the local Division 1 EDG controls in the event of a Control Room fire. At 1430 hours on May 4, 2006, with the plant in Mode 1 at 100% power, it was determined that this condition violated the Perry Nuclear Power Plant Fire Protection Program and could adversely affect plant shutdown in the case of a Control Room fire. A potential fire induced hot short in the EDG logic circuit could have resulted in a failure to start or a spurious trip of the EDG, even if control was transferred to local control. This condition has existed since 1989. Interim actions in the form of procedure changes have been completed to address this issue. A final resolution to this issue will be a design change to incorporate Appendix R Control Room isolation features to the EDG PTL control switch circuit. A telephone notification was made on May 4, 2006 at 1719 hours for this event. A follow-up written report is required within 60 days by the Operating License, paragraph 2.F and by Technical Specification 5.6.6.a. This event was determined to be of very low safety significance.
05000440/LER-2002-00313 January 2003Perry

On November 14, 2002, with the Perry Nuclear Power Plant operating in Mode 1 at 100 percent power, a review of the Emergency Closed Cooling Water (ECCW) Pump and Valve Operability Test instruction steps revealed that the system's two independent loops were temporarily interconnected through non-safety related chemical addition system piping to facilitate performance of reverse flow testing of the ECCW system pump discharge check valves. Interconnecting the two safety related, divisionally separated loops of ECCW through the non-safety related piping, created a configuration whereby a design basis accident, which includes a seismic event, could have resulted in loss of ECCW system inventory. The loss of system inventory could have resulted in the loss of ECCW cooling capability. Consequently, the safety systems supported by ECCW would have been unable to perform their residual heat removal and accident mitigating safety functions during the time the loops were interconnected The cause of this event was determined to be inadequate preparation, review and approval of the quarterly "ECC Pump and Valve Operability Test," Revision 7, made effective on November 18, 1998. The procedure has since been revised to eliminate reverse flow testing since it was determined that the ECCW system pump discharge check valves have no safety function to close in a design basis accident. Since the loops were cross-connected for only short periods of time for testing, this condition was considered to have low safety significance.

The interconnection of the two independent ECCW subsystems is considered a condition that could have prevented the fulfillment of a safety function of a system needed to remove residual heat in accordance with 10CFR50.73(a)(2)(v)(B) and mitigate the consequences of an accident in accordance with 10CFR50.73(a)(2)(v)(D). This condition is also considered an event whereby a single condition caused two independent trains to become inoperable in a single system designed to remove residual heat in accordance with 10CFR50.73(a)(2)(vii)(B) and mitigate the consequences of an event in accordance with 10CFR50.73(a)(2)(vii)(D).

05000440/LER-2001-00430 October 2001Perry

On October 1, 2001, it was determined that a non-conservative assumption for the steam carryover fraction of main steam has been applied in the General Electric methodology for calculating reactor core thermal power at the Perry Nuclear Power Plant (PNPP). This was documented in a General Electric Report entitled, "Impact of Steam Carryover Fraction on Process Computer Heat Balance Calculations, September 2001." This report states that the assumed carryover fraction in later model Boiling Water Reactors is non-conservative with respect to heat balance calculations. The potential effect of this non-conservative assumption is that the calculated core thermal power could be as much as approximately 0.082% lower than the actual core thermal power. Consequently, it is assumed that the plant has operated at reactor core power levels in excess of the licensed power level by approximately 0.082%, or approximately 3 megawatts thermal (MWth).

Due to the small magnitude of the carryover fraction input and the conservatism present in the core thermal power levels used for the safety analyses, the use of the non-conservative steam carryover fraction does not represent a safety issue. As a measure of conservatism, however, an administrative reactor power reduction of 4 MWth was implemented until the process computer thermal power calculation was modified to reflect the revised moisture carryover fraction.

This issue was reported to the NRC Operations Center via the Emergency Notification System at 1914 on October 1, 2001 (Notification number 38337). This written report is being submitted in accordance with PNPP Operating License Condition 2.F., as a potential violation of the Maximum Power Level specified in PNPP Operating License Condition 2.C.1.