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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.

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.

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.

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.

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).

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 7.6.2.1, which requires a Special Report submittal following an Emergency Core Cooling System actuation and injection into the reactor coolant system.

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.

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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.

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.

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).