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On November 5, 2016, at 0404, a Reactor Protection System (RPS) actuation occurred due to a valid scram discharge volume high water level signal. This actuation was the result of a Redundant Reactivity Control System (RRCS) Alternate Rod Insertion (ARI) signal that was inadvertently generated during testing. The reactor was in cold shutdown at the time of the RPS actuation, with all control rods inserted. The Reactor Coolant System (RCS) pressure was 830 psig to support excess flow check valve testing, and shutdown cooling was removed from service. When the RRCS/ARI actuated, the B reactor recirculation pump tripped as expected, and the scram air header depressurized as expected.

The depressurization of the scram air header is a design feature of the ARI. The ARI signal established the control rod drive (CRD) system scram flow path. This resulted in a high water level in the scram discharge volume (SDV), an expected response. High water level in the scram discharge volume is an actuation signal for the RPS.

This is a condition reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual or automatic actuation of a listed system. The cause of the RRCS/ARI actuation is inadequate procedural guidance which resulted in a personnel error associated with partial procedure performance.

On October 22, 2016, Hope Creek Generating Station (HCGS) received results that the 'as-found' set-point tests for safety relief valve (SRV) pilot stage assemblies had exceeded the lift setting tolerance prescribed in Technical Specification (TS) 3.4.2.1. The TS requires the SRV lift settings to be within +/- 3% of the nominal set-point value.

During the twentieth refueling outage (H1R20), all fourteen SRV pilot stage assemblies were removed for testing at an offsite facility. Between October 22 and October 28, 2016, HCGS received the test results for all fourteen of the SRV pilot valve assemblies. A total of ten of the fourteen SRV pilot stage assemblies experienced set-point drift outside of the TS 3.4.2.1 specified values. All of the valves failing to meet the limits were Target Rock Model 7567F two-stage SRVs. This is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by Technical Specifications.

The cause of the set-point drift for the ten SRV pilot stage assemblies is attributed to corrosion bonding between the pilot disc and seating surfaces, which is consistent with industry experience. This conclusion is based on previous cause evaluations and the repetitive nature of this condition at HCGS and within the BWR industry.

A review of plant conditions from April 2016, revealed a condition that could have prevented the fulfillment of a safety function. On April 7, 2016, at 0352, with the Hope Creek reactor operating at 100% power, the High Pressure Coolant Injection (HPCI) system turbine over-speed assembly did not respond as expected during post maintenance testing. The HPCI system was in the process of post maintenance testing following a planned maintenance window, and was inoperable at the time of the event. During system testing, the HPCI turbine was momentarily tripped by the over-speed assembly, and then reset itself with no operator action. Subsequent investigation found that the HPCI over-speed assembly reset spring did not have the correct preload. A review of the maintenance completed during the scheduled system outage determined that there was no maintenance performed on the over-speed assembly. Therefore, the condition could have been present prior to the start of the maintenance window on April 5, 2016 at 0205.

This report is being submitted under 10 CFR 50.73(a)(2)(v)(D), as an event or condition that could have prevented the fulfillment of a safety function of systems that are needed to mitigate the consequences of an accident. No specific cause was identified; however there is industry operating experience that the reset spring will relax over time, reducing the preload.

On June 2, 2015, Hope Creek Generating Station (HCGS) received initial results of the 'as-found' setpoint testing for the safety relief valve (SRV) pilot stage assemblies. The initial results indicated that three SRV pilot stage assemblies had exceeded the lift settings prescribed in Technical Specification (TS) 3.4.2.1. The TS requires the SRV lift settings to be within +/- 3% of the nominal setpoint value. During the nineteenth refueling outage (H1R19), all fourteen SRV pilot stage assemblies were removed for testing at an offsite facility. Between June 2 and June 10, 2015, HCGS received the test results for the remainder of the SRV pilot valve assemblies. A total of ten of the fourteen SRV pilot stage assemblies experienced setpoint drift outside of the TS 3.4.2.1 specified values. All of the valves failing to meet the limits were Target Rock Model 7567F two-stage SRVs. This is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by Technical Specifications.

The cause of the setpoint drift for the ten SRV pilot stage assemblies is attributed to corrosion bonding between the pilot disc and seating surfaces, which is consistent with industry experience. This conclusion is based on previous cause evaluations and the repetitive nature of this condition at HCGS and within the BWR industry.

Technical evaluations performed to assess the aggregate safety significance of ten SRVs with out of tolerance initial lift setpoints concluded that this condition had no safety significance.

On April 14, April 15, April 17, April 20, April 27, and April 29, 2015, with Hope Creek Generating Station (HCGS) in a planned refueling outage and the reactor cavity flooded in OPCON 5, HCGS performed operations with a potential to drain the reactor vessel (OPDRV) without an operable secondary containment. These operations are prohibited by Technical Specification (TS) 3.6.5.1; however, recent NRC guidance provided in Enforcement Guidance Memorandum (EGM) 11-003, Revision 2, allowed the implementation of interim actions as an alternative to full compliance. These actions were compiled in a plant procedure for the OPDRV activities performed at HCGS during Refueling Outage (H1R19) in April 2015.

These OPDRV activities were planned activities that were completed under the guidance of plant procedures and confirmed to have low safety significance based on the interim actions taken. Since these actions were deliberate, no cause determination was necessary. Consistent with the guidance provided in EGM 11-003, Revision 2, HCGS will submit a license amendment request to adopt a Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue within four months after the issuance of the Notice of Availability of the TSTF traveler.

These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

A review of plant conditions from June 2013, revealed two instances of an operation or condition that was prohibited by Technical Specifications. The reportable conditions were the result of improper operability assessment when the B Filtration, Recirculation and Ventilation System (FRVS) recirculation unit failed to start on a manual start demand on 6/24/13. As a result, two instances of Tech Spec non-compliance were identified.

The first occurred on 6/10/13, and the second on 6/17/13. This was discovered during a review conducted in February 2015. In addition, routine Emergency Diesel Generator (EDG) activities created a condition that could have prevented the fulfillment of a safety function due to the failure to recognize the B FRVS recirculation unit inoperability.

The conditions were determined to be reportable per 10 CFR 50.73(a)(2)(i)(B) as any operation or condition prohibited by Technical Specifications and per 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented fulfillment of a safety function to mitigate the consequences of an accident.

On December 5, 2013, at 03:25 EST, Hope Creek Unit 1 automatically scrammed from approximately 75 percent rated thermal power due to a main turbine trip that was caused by a high level in the 'A' moisture separator (MS).

The MS high level control loop was in the process of being tuned when the dump valve cycled repeatedly and subsequently failed closed. The main turbine trip automatic reactor scram resulted in a trip of both reactor recirculation pumps. The plant was stabilized in hot shutdown Operational Condition 3. During the recovery of the recirculation pumps, the digital electro-hydraulic control system was mis-operated which caused the turbine bypass valves to cycle. This caused reactor level to swell above Level 8 then shrink below Level 3 resulting in a second actuation of the reactor protection system.

A root cause evaluation determined the cause of the MS dump valve failure was thermal binding.

MS dump valve control has been modified from a modulating function to a full open function on high level to prevent valve cycling. The root cause determined that the MS dump valve clearances need to be modified to prevent thermal binding.

This is an event reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the reactor protection system.

On November 22, 2013, Hope Creek Generating Station (HCGS) received results of the 'as-found' setpoint testing for the safety relief valve (SRV) pilot stage assemblies. The results indicated that five SRV pilot stage assemblies' setpoints had exceeded the lift settings prescribed in the Limiting Condition for Operation (LCO) for Technical Specification (TS) 3.4.2.1. The TS LCO requires the SRV lift settings to be within +/- 3% of the nominal setpoint value. All five of the valves failing to meet the limits were Target Rock Model 7567F two-stage SRVs. During the eighteenth refueling outage (H1R18), all 14 SRV pilot stage assemblies were removed and tested at an offsite test facility. A total of five of the 14 SRV pilot stage assemblies experienced setpoint drift outside of the TS 3.4.2.1 specified values. This is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by Technical Specifications.

The cause of the setpoint drift for the five SRV pilot stage assemblies is attributed to corrosion bonding between the pilot disc and seating surfaces, which is consistent with industry experience. This conclusion is based on previous cause evaluations and the repetitive nature of this condition at HCGS and within the BWR industry.

There was no actual safety consequence associated with this event.

On October 18, 2013, Hope Creek Generating Station (HCGS) was notified by NWS Technologies that the solenoid operated valve (SOV) (S/N 481) associated with the pilot valve assembly for safety relief valve (SRV) 1ABHV-F013P (SRV-P) failed its required 'as-found' functional and air-leakage testing. The SOV failure affected the operability of the relief valve function and the low-low set function of SRV-P required by Technical Specification (TS) 3.4.2.2. The SOV was sent to an external vendor for failure analysis. On December 12, 2013, HCGS received the results of the failure analysis confirming that the SOV failure occurred at some point during the operating cycle. Technical Specification 3.4.2.2 requires the relief valve function and the low-low set function for the SRV-H and SRV-P to be OPERABLE in Operational Condition 1, 2, and 3. With one SRV inoperable, the TS action requires that the valve be restored to operable within 14 days or be in Hot Shutdown within the next 12 hours and in Cold Shutdown in the following 24 hours. Therefore, the SRV-P was inoperable for a period longer than the TS allowed outage time. This condition Is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition which was prohibited by the plant's Technical Specifications.

The cause of the SOV's failure was determined to be a manufacturer's assembly error. The anti-rotation pin that secures the adjustable plunger in place was not installed. Without the pin, the plunger was allowed to rotate and unthread until contacting the internal stop, which prevented the solenoid from picking up when energized.

Corrective actions included replacing the failed single SOV.

Hope Creek Generating Station 05000354

On June 13, 2013, Hope Creek Unit 1 was in Operational Condition (OPCON) 3 following a scram that occurred on June 12, 2013. At approximately 02:52 EDT, during the initial drywell walk down, operators observed water leaking from the 'B' Residual Heat Removal (RHR) Shutdown Cooling Return Vent Line. The source of the leak was identified as a through-wall flaw at the pipe/weld interface on the upstream side of the 'B' RHR vent line outboard isolation valve (BC-V597), which is inside the reactor coolant system pressure boundary. The estimated leakage rate through the through-wall flaw was determined to be less than one gallon per minute. The RHR vent line is 1" ASME Class 1 piping.

Corrective actions included replacing the vent line, including both inboard (BC-V589) and outboard (BC-V597) isolation valves, during the forced outage.

The cause of the leak was determined to be a human performance deficiency in completion of work in the drywell. A failure analysis performed by an external vendor indicated that the through-wall flaw was caused by grinding.

This condition is reportable under 10 CFR 50.73(a)(2)(ii)(A) for a condition that resulted in a principal safety barrier being seriously degraded. Based on the visual inspection performed during the drywell walkdown, the leak existed during plant operation. The Technical Specification limits Reactor Coolant System pressure boundary leakage to zero; therefore, this condition is also reportable under 10 CFR 50.73(a)(2)(i)(B) for a Condition Prohibited by Technical Specifications.

At 11:15 a.m., on April 8, 2013, the High Pressure Coolant Injection (HPCI) system was declared INOPERABLE during the performance of HC.IC-FT.BJ-0007 "Logic System Function Test - Containment High Pressure/Low Water Level/Reactor High Water Level HPCI Actuation." During the test, l&C technicians inserted a reactor low water level initiation (Level 2) signal to initiate a start of the HPCI Auxiliary Oil Pump (10-P-213). The operator noted that the HPCI Stop Valve (FV-4880) did not open as expected and observed that the HPCI Auxiliary Oil Pump (HCPI AOP) failed to start. Upon recognizing the HPCI AOP failure to start, the Shift Manager declared the HPCI system INOPERABLE.

Troubleshooting identified that the HPCI AOP control relay (1 BJYY-K056-E41 A), a normally de-energized relay, had failed. The relay was replaced and the HPCI AOP start signal was successfully retested. Upon completion of the functional test at 6:18 p.m., the Shift Manager declared, the HPCI system OPERABLE.

The cause of the relay failure was age-related. The failure analysis reported that the relay coil had electrically opened. There was no indication of stress or fatigue of the wire.

This condition is reportable under 10 CFR 50.73(a)(2)(v)(D) for a condition that could have prevented fulfillment of a safety function of structures or systems that are needed to mitigate the consequences of an accident.

Hope Creek Generating Station 05000354

On January 19, 2008, during the performance of 18 month Technical Specification (TS) Surveillance Requirement 4.4.1.1.3 to demonstrate operability of the reactor recirculation pump Motor Generator (MG) set scoop tube mechanical and electrical stops, the "A" and "B" MG set mechanical and electrical stops were found ncn- conservatively high. In accordance with the surveillance procedure, the stop set points were adjusted to their proper settings.

An eight-hour notification was made for this event under the provisions of 10CFR50.72(b) (3)(v)(D).

An apparent cause evaluation was conducted.

Corrective actions include adjusting the stop set points to their proper settings, review of the Recirculation System trending program to identify any near term changes needed to ensure compliance with TS 4.4.1.3, benchmarking of the Recirculation System trending program, and consideration of revision of the TS BASES.

A similar LER, Hope Creek, LER 2000-010-000, described the "B" recirculation pump motor-generator set stops as being set non-conservatively high: The LER was retracted after further investigation showed an error was made in the calibration of the stops and the Technical Specification required set point values for the stops were never exceeded.

NRC FORM 366 (9-2007) ) PRINTED ON RECYCLED PAPER

On January 12, 2004, at 1015 hours during the performance of 18-month Technical Specification calibration of the 'C' channel Reactor Building Exhaust (RBE) radiation monitor, the 'A' channel RBE radiation monitor actuated resulting in an actuation of the Primary Containment Isolation System (PCIS). The actuation of PCIS caused the isolation of the Primary Containment Instrument Gas (PCIG) supply to the inboard Main Steam Isolation Valves (MSIVs). Prior to restoration of the PCIG system, the 'D' and 'B' inboard MSIVs began to drift closed. Anticipating the receipt of an automatic scram, the Reactor Operator (RO) manually scrammed the reactor by placing the mode switch to the shutdown position at 1048 hours. Shortly after the scram, the 'A' and 'C' MSIVs began to drift closed. At 1051, PCIG was restored and the inboard MSIVs returned to the open position. The inboard MSIVs never went fully closed which ensured that the main condenser remained available throughout the event for reactor heat removal. Following the manual scram, a low reactor water level scram signal was received (Level 3, +12.5 inches) as expected. At 2123 hours, a second invalid actuation of the PCIS occurred due to equipment related problems.

The cause of the PCIS actuation that led to the manual scram is attributed to a loose LEMO connector on the 'A' channel RBE radiation monitor that allowed intermittent contact when a nearby conduit was used as a hand hold to gain access to the 'C' channel RBE radiation monitor for surveillance testing. The apparent cause of the second invalid PCIS actuation is attributed to faulty Bailey cards associated with the RBE high radiation input to PCIS. The corrective actions associated with this event consist of procedure enhancements, emphasizing standards with maintenance personnel, re- evaluation of the scheduling of surveillance testing, and the repair/replacement of equipment.

This event is being reported in accordance with 10CFR50.73(a)(2)(iv)(A).

On June 22, 2002 at approximately 1417, Hope Creek Generating Station experienced an automatic reactor scram as a result of a turbine trip due to high moisture separator (MS) level. The high MS level resulted from failure of the level controls to adequately respond to the transient, due in part to two phase flow in the drain path. The initiating event that ultimately resulted in the scram was failure of a logic card that caused a secondary condensate pump (SCP) to trip. The automatic reactor scram was successful, but anomalous control rod position indications immediately after the scram prompted operators to initiate alternate rod insertion in accordance with procedures. Condensate flow to feedwater heaters 1 and 2 isolated due to high heater feedwater level; operators manually established bypass flow. Cooldown was in accordance with Technical Specification limits and there were no safety consequences as a result of this event.

Corrective actions include replacement of the SCP logic card, corrective maintenance of the normal MS drain control loop and adjustments to the MS dump valve controls to improve response time.

This event is reportable under 10 CFR 50.73 (a)(2)(iv)(A) as an actuation of the reactor protection system.

On June 22, 2001, the 'C' emergency diesel generator (EDG) heat exchanger cooling water outlet relief valve opened when two pumps were operating in the 'A' Safety Auxiliaries Cooling System (SACS) loop. The relief valve was set to open at 120 psig instead of the design setpoint of 150 psig.

During a postulated design basis event, pressure could have exceeded the lift setpoint, causing the valve to open. If automatic makeup to the 'A' SACS loop head tank was not available, operator action would be required to identify and correct the condition before loss of inventory resulted in loop inoperability. At the time of discovery, scheduled maintenance prevented the 'B' train of the Control Room Emergency Filtration (CREF) System from performing its design function. Thus, it is possible that neither CREF train would have been available during a postulated design basis event. The root cause was the failure to update the Bill of Material for relief valve 1EGPSV-2409C as part of a design change package. Upon discovery, the 'A' SACS loop was placed in a configuration that ensured system pressure would not exceed the lift setpoint for 1 EGPSV-2409C. The relief valves on the 'A', 'B', and 'D' EDGs were verified to have the correct lift setpoint. The 'B' CREF train was returned to OPERABLE status. Relief valve 1EGPSV-2409C was replaced with a valve with the correct lift setpoint.