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 Report dateSiteEvent description
05000354/LER-2016-00513 March 2017Hope Creek

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.

05000354/LER-2016-0038 March 2017Hope Creek

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.

05000354/LER-2016-00420 December 2016Hope Creek

On October 23, October 24, and October 31, 2016, 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, NRC guidance provided in Enforcement Guidance Memorandum (EGM) 11-003, Revision 3, 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 (HR20) in October 2016.

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 3, HCGS will submit a license amendment request to adopt a Technical Specification 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.

05000354/LER-2016-00230 November 2016Hope Creek

On August 6, 2016, at 21:34, with the Hope Creek reactor operating at 100% power, the High Pressure Coolant Injection (HPCI) system turbine governor valve did not respond as expected during system surveillance testing.

The system was declared inoperable and an 8-hour immediate notification was made under 10 CFR 50.72 (B)(3)(v)(d). Subsequent investigation found that HPCI turbine governor was not functioning due to corrosion products in the governor, preventing movement of the pilot valve. Additional research determined that the turbine governor did not respond properly on July 3, 2016 during the collection of an oil sample. Based on this, the HPCI system was inoperable for a period of 39 days from July 3, 2016, until August 11, 2016, when repairs to the governor were completed. The HPCI system Technical Specification has an allowed outage time of 14 days.

This report is being submitted under 10 CFR 50.73(a)(2)(i)(B), as a condition which is prohibited by the plant's Technical Specifications, and 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. The cause of the event is the accumulation of corrosion products in the HPCI turbine governor due to excessive moisture content in the HPCI system control oil.

05000354/LER-2016-0014 October 2016Hope Creek

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.

05000354/LER-2015-0036 July 2015Hope Creek

From May 4 through 5, 2015, during a planned Reactor Pressure Vessel (RPV) pressure test following RPV reassembly from refuel outage H1R19, Hope Creek Generating Station (HCGS) did not comply with Technical Specification Action Statement 3.5.2, action a. The plant lineup to support the RPV pressure test is classified as an Operation With the Potential to Drain the Vessel (OPDRV).

Technical Specification (TS) 3.5.2, ECCS Shutdown, requires that at least two Low Pressure ECCS subsystems be OPERABLE in Operational Condition 4. The TS requires that with only one ECCS subsystem operable, two subsystems shall be restored to operable status within four hours or suspend all OPDRVs. Contrary to this requirement, HCGS conducted the RPV pressure test OPDRV activity with only one low pressure ECCS subsystem operable. This condition existed from May 4 at 0400 until May 5 at 1042, a period of 30 hours and 42 minutes. TS compliance was restored on May 5 at 1042 when a second low pressure ECCS system was returned to OPERABLE.

The cause of the event was determined to be failure to properly assess the operability status of all the ECCS subsystems which could be used to meet TS 3.5.2.

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

05000354/LER-2015-00130 June 2015Hope Creek

On 03/31/2015 at 1342, the breaker for 'A' Core Spray Pump failed to close during normal surveillance testing.

No alarms were received in the Main Control Room when the start pushbutton was depressed. A second start attempt had the same results. Technical Specification (TS) 3.5.1.a was entered for one inoperable Core Spray Subsystem. The breaker was replaced and the surveillance was satisfactorily performed. 'A' Core Spray Subsystem was declared OPERABLE on 03/31/2015 at 2000 and the TS was exited.

Initial troubleshooting indicated that the failure in the breaker most likely existed since the last breaker operation in January 2015. Failure analysis concluded that the spring in the breaker control device failed due to cyclic fatigue, preventing the breaker from closing. Consequently, 'A' Core Spray Subsystem was inoperable for longer than the TS allowed outage time. Therefore, the condition was determined to be reportable per 10 CFR 50.73(a)(2)(i)(B) as any operation or condition prohibited by TS. During the review of this event, it was determined that 'B' Core Spray Subsystem was inoperable from 02/09/2015 at 0300 until 02/10/2015 at 1532 (36 hours and 32 minutes) when planned maintenance was performed on the 'B' Emergency Diesel Generator (EDG).

This condition is reportable per 10 CFR 50.73(a)(2)(v) as an event or condition that could have prevented the fulfillment of a safety function.

05000354/LER-2015-00210 June 2015Hope Creek

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.

05000354/LER-2013-01125 March 2015Hope Creek

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.

05000354/LER-2015-0055 January 2015Hope Creek

On September 28, 2015, at 20:46, with the Hope Creek reactor operating at 100% power, a human error during surveillance testing resulted in the actuation of the Redundant Reactivity Control System (RRCS), and subsequently, an automatic reactor scram on a valid low water level signal. At the time of the transient, a surveillance test of division 1 of the RRCS system was in progress. The test simulates a high reactor pressure signal. Plant data show the signal was entered in both channels of division 1 of the RRCS system. The resulting system actuation caused a trip of both Reactor Recirculation Pumps, and the actuation of the Alternate Rod Insertion (ARI) function of the RRCS system. As a result of these two actuations, reactor power lowered, causing reactor water level to lower to the Reactor Protection System (RPS) trip set point of +12.5 inches. The RPS initiated an automatic reactor scram. Reactor operators recovered water level to within the desired band using the feedwater system. Reactor pressure was maintained using turbine bypass valves discharging to the main condenser.

This report is being submitted under 10 CFR 50.73(a)(2)(iv)(A), as an event or condition that resulted in the actuation of the Reactor Protection System.

05000354/LER-2013-0094 April 2014Hope Creek

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.

05000354/LER-2013-01014 March 2014Hope Creek

On 12/20/13 at 1303, while the B Control Room Chiller was out of service in support of maintenance, the A Control Room Chiller was manually secured due to excessive fluctuations in load. The Technical Specification action statement (TS 3.7.2.2 Action a.2) for both Control Room Air Conditioning subsystems inoperable was entered.

Concurrent inoperability of both control room chillers is reportable per 50.73 (a)(2)(v)(D), an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident .

At 2120 on 12/20/13 the B Control Area Ventilation Train and Chiller were placed in service for post maintenance testing, returned to an operable status , and the action statement was exited. Throughout the time both chillers were inoperable, the control room temperature was maintained below the TS limit of 90 degrees F.

The A Control Room Chiller excessive load fluctuations were determined to be the result of an inoperable chiller condenser pressure control valve. The valve inoperability was due to an age-related positioner component failure caused by a legacy issue with implementation of a design change. The failed positioner was replaced and the A Control Area Ventilation Train and Chiller were returned to operable status.

05000354/LER-2013-00716 January 2014Hope Creek

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.

05000354/LER-2013-00624 December 2013Hope Creek

On October 31, 2013, at approximately 09:30, during a refueling outage, the Reactor Water Cleanup (RWCU) system was placed in letdown to radwaste to control reactor pressure vessel (RPV) inventory. Because the automatic isolation function was not available for either valve in the drain-down path, the guidance in Enforcement Guidance Memorandum (EGM) 11-003, Revision 1 could not be utilized. EGM 11-003, Revision 1 states: "The addition and removal of small volumes of water inventory from the RPV, for example control rod drive cooling water, is considered steady-state water level control and not an OPDRV provided the instrumentation and valves for automatic isolation of the drain-down path remain available." This placed the plant in an operation with the potential to drain the reactor vessel (OPDRV). Technical Specification 3.6.5.1 requires secondary containment to be set if the plant is in an OPDRV. Secondary containment was not set; therefore, the plant was in a condition prohibited by Technical Specifications.

The Shift Manager identified the condition at 16:31. The condition was corrected at 17:21 by placing an inoperable level channel in a tripped condition, which restored the instrumentation and valve for automatic isolation of the drain path.

This event 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.

05000354/LER-2013-00517 December 2013Hope Creek

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

05000354/LER-2013-00410 December 2013Hope Creek

On October 15, October 20, and October 23, 2013, With Hope Creek Generating Station (HCGS) in a planned refueling outage and the reactor cavity flooded up 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) 3.6.4.1; however, recent NRC guidance provided in Enforcement Guidance Memorandum (EGM) 11-003, Revision 1, 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 (H1R18) in October 2013.

These OPDRV activities were planned activities that were completed under the guidance of plant procedures and confirmed to have low safety significante 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 1, 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.

05000354/LER-2013-00212 October 2013Hope Creek

On June 12, 2013, at 13:33, Hope Creek Unit 1 was manually scrammed from approximately 100 percent rated thermal power due to degrading main condenser vacuum. This condition occurred due to the trip of the 'B' circulating water (CW) pump with the 'B' CW discharge valve stuck in the full-open position. Operators initiated a manual scram when condenser vacuum reached 6.5 inches of mercury absolute (HgA). During the scram response, the operating reactor feed pump tripped due to degrading vacuum and the operators manually placed the reactor core isolation cooling (RCIC) system in service for reactor inventory control. Operators completed the scram response procedures and placed the plant in a stabilized hot shutdown condition.

Immediate corrective actions included replacing the 'B' CW discharge valve and replacing the auxiliary relay card for the 'B' CW pump trip during the forced outage. Additional corrective actions include establishing a program for performing failure analysis, "metallic whisker" evaluations, and trending of circuit card failures in accordance with INPO and EPRI recommendations, and establishing a preventative maintenance program for replacement of the Bailey auxiliary relay cards.

The cause of the 'B' CW pump trip was due to conductive filament growth that bridged across two solder traces on the auxiliary relay card, creating a short circuit, and generating a CW pump trip signal.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a valid manual actuation of the reactor protection system and manual initiation of the RCIC system.

05000354/LER-2013-0036 September 2013Hope Creek

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.

05000354/LER-2013-0015 June 2013Hope Creek

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

05000354/LER-2004-00218 March 2004Hope Creek

On January 21, 2004, while reviewing corrective action and maintenance records, it was determined that a violation of Technical Specification (TS) 3.7.2, Control Room Emergency Filtration system (CREF) (VI) had occurred. The discovery was based on conclusions reached regarding past maintenance activities and performance documentation. TS 3.7.2, requires that two independent CREF subsystems to be operable. With one subsystem inoperable the inoperable unit must be made operable within 7 days.

On September 10 and 11, 2003 maintenance was performed on the BK400 chiller due to erratic behavior of the chiller. The unit was placed back in service and continued to operate until September 19, 2003 at which time it was placed in standby due to system realignment. On October 2, the BK400 was required to start. Shortly following the call to start, the chiller tripped on low evaporator refrigerant pressure. Corrective maintenance performed on October 3, 2003 found that the float arm had become disengaged. The chiller was repaired and returned to service.

Operability screening conducted at that time did not identify the chiller as potentially inoperative for more than 7 days.

There were no safety consequences associated with this event because one CREF subsystem was operable at all times. Also, during the period of assumed inoperability of the subsystem there were no radiological releases which would have required operation of the standby CREF to protect personnel in the control room envelope.

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

05000354/LER-2004-00111 March 2004Hope Creek

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).

05000354/LER-2003-0052 July 2003Hope Creek

On February 24, 2003, during fuel rack lubrication on "B" Hope Creek Emergency Diesel Generator Engine (EDG) the number two fuel injection pump rack was found stuck and the unit declared inoperable at 02:20. Immediate corrective action was to replace fuel pump on number two cylinder.

The "B" EDG was retumed to an operable status at 21:17 on February 25, 2003. Subsequent to this an investigation was conducted into the timeliness of identification of the failed fuel injector. The conclusion based upon the failure mechanism was that the diesel was inoperable from the time the diesel was taken out of service for the monthly surveillance test, which occurred at 16:37 on February 22, 2003. Technical Specification 3.8.1.1 Action b states that the "K or "B" EDG must be returned to an operable condition within 72 hours. The apparent cause associated with being in a condition not allowed by TS 3.8.1.1 Action b was personnel error. This event is reportable in accordance with 10CFR50.73(a)(2)(i)(B) as any event, which was prohibited by the plant's Technical Specifications.

RC FORM 366 (7-2001)

05000354/LER-2003-00419 June 2003Hope CreekDuring Refueling Outage R11, Hope Creek operated in a condition prohibited by Technical Specifications (TS). On April 22 at 2036 when a Tagging Order was implemented, the Reactor Protection System and the manual scram switches were effectively rendered inoperable. At that time, Action 9 of TS Table 3.3.1-1 item 12 should have been implemented and was not fully implemented because the Mode Switch was not locked in SHUTDOWN as required. This condition existed until 1950 on April 26 when the Mode Switch was locked in SHUTDOWN. The apparent cause for this event was a lack of proper review of TS when the equipment was tagged out and removed from service. Subsequent shifts failed to identify the error. There were no safety consequences associated with this event since, at the time that the tagging operation was in effect, a full scram was implemented, all control rods were inserted, a control rod withdrawal block was in effect, and there were no activities scheduled or in progress that involved core alterations. This event will be provided to the Operations Training Review Group for inclusion in the Licensed Operator Requalification Program.
05000354/LER-2001-01028 February 2002Hope CreekOn 12/20/01, it was noted that local power range monitor (LPRM) 48-41A was providing an upscale input to the rod block monitoring (RBM) system despite being bypassed. LPRM 48-41A failed low on 12/12/01 and had been bypassed in accordance with plant procedures. The cause of the erroneous input to the RBM was a failed LPRM card in the 10-C-608, Power Range Monitoring Panel. The LPRM card was pulled to eliminate the erroneous signal. The effect of the erroneous upscale output from LPRM 48-41A was to cause the RBM channel "A" gain change circuit to produce a lower than required gain, so that RBM channel "A" may not have been capable of imposing a rod block when required for 15 control rods in the vicinity of LPRM 48-41A. Since this condition existed for longer than the time permitted by TS 3.1.4.3, it is reportable as a condition prohibited by plant Technical Specifications in accordance with 10 CFR 50.73(a)(2)(i)(B). There were no safety consequences associated with this event. The applicable operating procedure will be revised to add a step requiring that the four rod display be checked when bypassing an LPRM to confirm that the output for the bypassed LPRM is zero.