IR 05000354/2024010

Comprehensive Engineering Team Inspection Report 05000354/2024010

ML25065A001
Person / Time
Site:	Hope Creek
Issue date:	03/06/2025
From:	Erin Carfang Division of Operating Reactors
To:	Mcfeaters C Public Service Enterprise Group
References
IR 2024010
Download: ML25065A001 (1)

Text

March 6, 2025

SUBJECT:

HOPE CREEK GENERATING STATION - COMPREHENSIVE ENGINEERING TEAM INSPECTION REPORT 05000354/2024010

Dear Charles McFeaters:

On February 14, 2025, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station and discussed the results of this inspection with Eric Larson, Site Vice President, and other members of your staff. The results of this inspection are documented in the enclosed report.

Three findings of very low safety significance (Green) are documented in this report. Two of these findings involved violations of NRC requirements, one was determined to be Severity Level IV. We are treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or the significance or severity of the violations documented in this inspection report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Resident Inspector at Hope Creek Generating Station.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; and the NRC Resident Inspector at Hope Creek Generating Station. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, Erin E. Carfang, Chief Engineering Branch 1 Division of Operating Reactor Safety

Docket No. 05000354 License No. NPF-57

Enclosure:

As stated

Inspection Report

Docket Number:

05000354

License Number:

NPF-57

Report Number:

05000354/2024010

Licensee:

PSEG Nuclear, LLC

Facility:

Hope Creek Generating Station

Location:

Hancocks Bridge, NJ

Inspection Dates:

December 02, 2024 to February 14, 2025

Inspectors:

E. Chen, Reactor Inspector

N. Floyd, Senior Reactor Inspector

J. Kulp, Senior Reactor Inspector

K. Mangan, Senior Reactor Inspector

S. McClay, Reactor Inspector

E. Miller, Senior Reactor Inspector

J. Schoppy, Senior Reactor Inspector

Approved By:

Erin E. Carfang, Chief

Engineering Branch 1

Division of Operating Reactor Safety

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting a comprehensive engineering team inspection at Hope Creek Generating Station, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

List of Findings and Violations

Failure to Properly Adhere to Procedure Requirements Related to Performance Monitoring of the Service Water Cable Vault Dewatering System (SSWCVDS)

Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green FIN 05000354/2024010-01 Open/Closed

[H.8] -

Procedure Adherence 71111.21M The team identified a Green finding for PSEGs failure to properly adhere to procedure requirements. Specifically, chemistry technicians failed to follow the guidance in HC.CH-SO.LE-0002, Operation of the Station Service Water Cable Vault Dewatering System, associated with initiating a corrective action notification (NOTF) to manually measure water level when the level in a cable vault could not be determined.

Inadequate Preventive Maintenance Strategy to Ensure the High-Pressure Coolant Injection (HPCI) Temperature Control Valve (TCV) Would Perform Its Safety Function Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000354/2024010-02 Open/Closed None (NPP)71111.21M The team identified a Green finding and associated non-cited violation (NCV) of Technical Specification (TS) 6.8, "Procedures and Programs," because PSEG did not establish procedures covering activities recommended in Appendix A of Regulatory Guide 1.33,

Revision 2, February 1978. Specifically, PSEG did not have a preventive maintenance strategy for the HPCI system lube oil TCV. The team identified that PSEG canceled the 5-year replacement preventive maintenance activity for the TCV in 2006, and did not establish a new maintenance strategy for the valve.

Change to Emergency Diesel Generator (EDG) Operating Procedure Without Obtaining a License Amendment Cornerstone Significance/Severity Cross-Cutting Aspect Report Section Mitigating Systems Green Severity Level IV NCV 05000354/2024010-03 Open/Closed

[H.6] - Design Margins 71111.21M The team identified a Green finding and associated Severity Level IV non-cited violation (NCV) of 10 CFR 50.59, Changes, Tests, and Experiments, when PSEG did not obtain a license amendment prior to changing the EDG operating procedure. The team determined the change affected the Hope Creek TSs, and the change resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, and component (SSC) important to safety previously evaluated in the updated final safety analysis report (UFSAR). The team also identified a violation of TS 3.8.1, A.C. Sources, also occurred as a result of the performance deficiency.

Additional Tracking Items

None.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

REACTOR SAFETY

===71111.21M - Comprehensive Engineering Team Inspection

The inspectors evaluated the following components and listed applicable attributes, permanent modifications, and operating experience:

Structures, Systems, and Components (SSCs) (IP Section 03.01)===

Structures, Systems, and Components (SSCs) (IP Section 03.01) (8 Samples)

For each component sample listed below, the team reviewed licensing and design basis documents and a sampling of applicable operator actions, periodic testing results, corrective action program documents, internal and external operating experience, preventive and corrective maintenance work orders, modifications, and aging management programs.

Additionally, the team performed walkdowns of the component or procedure and conducted interviews with licensee personnel.

The team used the attributes contained in IP 71111.21M, Appendix A, "Component Review Attributes," such as those listed below as guidance. Specifically, the team evaluated these attributes in the course of applying 71111.21M, Appendix B, "Component Design Review Considerations" and 71111.21M, Appendix C, "Component Walkdown Considerations."

(1) Loss of Station Service Water Initiating Event

• Energy sources (fuel, air, steam, electricity), including those used for control functions, will be available and adequate during accident/event conditions

• Operating procedures (normal, abnormal, or emergency) are consistent with operator actions for accident/event conditions

• Instrumentation and alarms are available to operators for making necessary decisions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Performance capability of selected components have not been degraded through modifications

• Potential degradation is monitored or prevented

• Equipment is adequately protected from environmental hazards

• Walkdown of service water, fire system and circulating water systems, and associated building

• Observed simulator response and operator actions during loss of service water scenario

The team used Appendix B guidance for Valves, Pumps, Instrumentation, and As-Built System.

(2) High-Pressure Coolant Injection Pump and Turbine

• Process medium (water, air, electrical signal) will be available and unimpeded during accident/event conditions

• Energy sources (fuel, air, steam, electricity), including those used for control functions, will be available and adequate during accident/event conditions

• Component controls will be functional and provide desired control during accident/event conditions

• Operating procedures (normal, abnormal, or emergency) are consistent with operator actions for accident/event conditions

• Instrumentation and alarms are available to operators for making necessary decisions

• Installed configuration will support its design basis function under accident/event conditions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Performance capability of selected components have not been degraded through modifications

• Acceptance criteria for tested parameters are supported by calculations or other engineering documents to ensure that design and licensing bases are met

• Tests and/or analyses validate component operation under accident/event conditions

• Potential degradation is monitored or prevented

• Equipment is adequately protected from environmental hazards

The team used Appendix B guidance for Valves, Pumps, Instrumentation, and As-Built System.

(3) Rupture of Fire Protection Piping in the Diesel Control Building Initiating Event

• Energy sources (fuel, air, steam, electricity), including those used for control functions, will be available and adequate during accident/event conditions

• Component controls will be functional and provide desired control during accident/event conditions

• Operating procedures (normal, abnormal, or emergency) are consistent with operator actions for accident/event conditions

• Instrumentation and alarms are available to operators for making necessary decisions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Performance capability of selected components have not been degraded through modifications

• Acceptance criteria for tested parameters are supported by calculations or other engineering documents to ensure that design and licensing bases are met

• Potential degradation is monitored or prevented

• Equipment is adequately protected from environmental hazards

The team used Appendix B guidance for Valves, Pumps, Instrumentation, and As-Built System.

(4) Allowed Outage Time Diesel Generator

• Electrical power will be available and unimpeded during accident/event conditions

• Component controls will be functional and provide desired control during accident/event conditions

• Operating procedures are consistent with operator actions for accident/event conditions

• Instrumentation and alarms are available to operators for making necessary decisions

• Installed configuration will support its design basis function under accident/event conditions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Performance capability of selected components have not been degraded through modifications

• Acceptance criteria for tested parameters are supported by calculations or other engineering documents to ensure that design and licensing bases are met

• Tests and/or analyses validate component operation under accident/event conditions

• Potential degradation is monitored or prevented

• Equipment is adequately protected from environmental hazards

The team used Appendix B guidance for Instrumentation, Circuit Breakers and Fuses, Cables, Electrical Loads, and As-Built System.

(5) Torus Vent Valve (HV-11541) and Damper HV-4964

• Process medium (water, air, electrical signal) will be available and unimpeded during accident/event conditions

• Energy sources (fuel, air, steam, electricity), including those used for control functions, will be available and adequate during accident/event conditions

• Component controls will be functional and provide desired control during accident/event conditions

• Operating procedures (normal, abnormal, or emergency) are consistent with operator actions for accident/event conditions

• Instrumentation and alarms are available to operators for making necessary decisions

• Installed configuration will support its design basis function under accident/event conditions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Acceptance criteria for tested parameters are supported by calculations or other engineering documents to ensure that design and licensing bases are met

• Tests and/or analyses validate component operation under accident/event conditions

• Potential degradation is monitored or prevented

The team used Appendix B guidance for Valves, Pumps, Instrumentation, and As-Built System.

(6) A and B Station Service Water Pump Motors and 4KV Power Supply Cables

• Process medium (water, air, electrical signal) will be available and unimpeded during accident/event conditions

• Installed configuration will support its design basis function under accident/event conditions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Acceptance criteria for tested parameters are supported by calculations or other engineering documents to ensure that design and licensing bases are met

• Tests and/or analyses validate component operation under accident/event conditions

• Potential degradation is monitored or prevented

• Equipment is adequately protected from environmental hazards

The team used Appendix B guidance for Instrumentation, Circuit Breakers and Fuses, Cables, Electrical Loads, Motor Control Centers, and As-Built System.

(7) A Safety Relief Valve (H1SN-1SNPSV-F013A) and Operator Actions to Depressurize

• Process medium (water, air, electrical signal) will be available and unimpeded during accident/event conditions

• Energy sources (fuel, air, steam, electricity), including those used for control functions, will be available and adequate during accident/event conditions

• Component controls will be functional and provide desired control during accident/event conditions

• Operating procedures (normal, abnormal, or emergency) are consistent with operator actions for accident/event conditions

• Instrumentation and alarms are available to operators for making necessary decisions

• Installed configuration will support its design basis function under accident/event conditions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Performance capability of selected components have not been degraded through modifications

• Acceptance criteria for tested parameters are supported by calculations or other engineering documents to ensure that design and licensing bases are met

• Tests and/or analyses validate component operation under accident/event conditions

• Potential degradation is monitored or prevented

The team used Appendix B guidance for Valves, Pumps, Instrumentation, and As-Built System.

(8) B.5.b Diesel Driven Pump

• Process medium will be available and unimpeded during accident/event conditions

• Energy sources (fuel, electricity), including those used for control functions, will be available and adequate during accident/event conditions

• Component controls will be functional and provide desired control during accident/event conditions

• Operating procedures (normal, abnormal, or emergency) are consistent with operator actions for accident/event conditions

• Installed configuration will support its design basis function under accident/event conditions

• Component operation and alignments are consistent with design and licensing basis assumptions

• Design bases and design assumptions have been appropriately translated into design calculations and procedures

• Acceptance criteria for tested parameters are supported by calculations or other engineering documents to ensure that design and licensing bases are met

• Tests and/or analyses validate component operation under accident/event conditions

• Potential degradation is monitored or prevented

• Equipment is adequately protected from environmental hazards

The team used Appendix B guidance for Valves, Pumps, Instrumentation, and As-Built System.

Modifications (IP Section 03.02) (4 Samples)

(1)

===80098425, Motor Control Center 10B222 Compartment Replacement (2)80130356, Maximum Pressure Difference Across Valve H1BC-BC-HV-F003A (3)80136393, Reactor Water Cleanup Alternate Nondestructive Examination Requirements - Line 1-BG-008 (4)80121547, EDG Voltage Regulator Manual/Auto Relay Replacement

10 CFR 50.59 Evaluations/Screening (IP Section 03.03)===

(1) H2021-022, Hope Creek Reactor Auxiliaries Cooling System Isolation Single Point Vulnerability Mitigation 50.59 Evaluation, dated 3/3/21

(2) H2021-024, Residual Heat Removal Alternate Cooling Modes 50.59 Screen, dated 2/28/21

(3) H2021-053, Revision 1, EDGs Operation 50.59 Screen, dated 9/3/24

(4) H2021-070, Revise the Diesel Fuel Oil Particulate Limit 50.59 Screen, dated 4/24/21

(5) H2021-087, Meteorological Tower Instrumentation Replacement 50.59 Screen, dated 7/9/21

(6) H2021-090, Defeat the 'B' & 'C' Reactor Feedpump Turbine Low Low Suction Pressure Trip (80129612), dated 9/14/21

(7) H2021-091, Safety Relief Valve 50.59 Screen, dated 6/29/21

(8) H2021-094, Replacement of 20 kVA 1E Inverters 1CD481 and 1CD482 50.59 Evaluation, dated 8/13/21

(9) H2021-119, Hope Creek Reactor Recirculation Pump Discharge Valve Runback Removal 50.59 Screen, dated 11/3/21

(10) H2022-034, Water Hammer Stress Analysis of the Hope Creek Fire Protection System for Riser RB2 in Reactor Building and Riser #10 in Turbine Building 50.59 Screen, dated 5/3/22

(11) H2022-043, Non-Conforming Elbow on Reactor Water Cleanup Line 1-BG-008 50.59 Screen, dated 5/25/22

(12) H2022-053, Documentation of the Silver Run Electric Transmission Line as a Source of Offsite Power 50.59 Screen, dated 7/28/23

(13) H2022-118, Hope Creek Safety Communication 11-07 Evaluation Finite Break Opening Time 50.59 Screen, dated 11/21/22

(14) H2023-031, H-1-CG-MDC-1795, Revision 7, Control Rod Drop Radiological Consequences 50.59 Evaluation, dated 5/3/23

Operating Experience Samples (IP Section 03.04) (2 Samples)

(1) NRC Information Notice 2018-07: Pump/Turbine Bearing Oil Sight Glass Problems

(2) Corrective Actions for Component Design Bases Inspection finding NCV 05000354/2015007-01

INSPECTION RESULTS

Failure to Properly Adhere to Procedure Requirements Related to Performance Monitoring of the Service Water Cable Vault Dewatering System (SSWCVDS)

Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems

Green FIN 05000354/2024010-01 Open/Closed

[H.8] -

Procedure Adherence 71111.21M The team identified a Green finding for PSEGs failure to properly adhere to procedure requirements. Specifically, chemistry technicians failed to follow the guidance in HC.CH-SO.LE-0002, Operation of the Station Service Water Cable Vault Dewatering System, associated with initiating a corrective action notification (NOTF) to manually measure water level when the level in a cable vault could not be determined.

Description:

PSEG personnel implemented Design Change Package 80103378 in May 2011, to install an automatic dewatering system for station service water electrical manhole cable vaults 102,103, and 105. PSEG personnel installed the system in response to Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients, and as a corrective action for a 2009 design control violation for failing to maintain the safety-related buried cables in an environment for which they were designed (not submerged) documented in NRC Inspection Report 05000354/2009004 (ML093160532). In addition, PSEG staff credited the design change package in their internal response to NRC Information Notice 2010-26, Submerged Electrical Cables. The purpose of the station SSWCVDS is to mitigate the long-term aging effects water has on the safety-related 4kV service water motor cables in the cable vault. Chemistry technicians monitor SSWCVDS performance weekly in accordance with HC.CH-SO.LE-0002, Operation of the Station Service Water Cable Vault Dewatering System, to ensure proper functioning of the system.

During the inspection, the team requested documentation of chemistrys monitoring logs and any SSWCVDS corrective action NOTFs associated with the safety-related service water cable vaults. Upon further review, including interviews with PSEG supervision, the team noted significant unavailability of the monitoring system in the previous four years and numerous prolonged periods of cable submergence (i.e., actual high water level conditions in the vaults). Based on the records available for review, the team noted that SSWCVDS unavailability trended from approximately 17 percent in 2021, to approximately 58 percent in 2024. The team also noted that PSEG staff initiated only one NOTF related to SSWCVDS performance during the period January 1, 2021 through October 31, 2024, and that the NOTF was not initiated following the weekly monitoring check per the procedure. The team noted that HC.CH-SO.LE-0002, Section 3.1, states NOTIFY the Control Room Prior to placing the SSWCVDS in or out of service. In/out of service times should be recorded in ESOMs, and Section 3.5 states If water level in a cable vault cannot be determined, INITIATE a notification to manually measure water level IAW HC.MD-PM.ZZ-0022, SSW Electrical Manhole Water Inspection, until level instrumentation is restored." In response to the teams inquiry, PSEG staff did not find any entries in 2024 related to SSWCVDS in the ESOMS (Electronic Shift Operations Management System) logs. Thus, based on the teams review as noted above, the team identified longstanding and widespread examples of PSEGs failure to adequately follow the requirements of HC.CH-SO.LE-0002 which directly contributed to longstanding submergence of safety-related 4kV cables with little to minimal PSEG corrective action program engagement.

In response to the teams observations and concerns, PSEG initiated several corrective action NOTFs to address PSEG staff performance and SSWCVDS equipment deficiencies including NOTFs 20983829, 20983757, 20983758, and 20984138. PSEG personnel concluded that the safety-related service water pump motors remained fully operable based on the satisfactory TAN-DELTA electrical test results for the service water cables. The team independently reviewed the TAN-DELTA test and trend results, including a verification that the testing was completed within the specified periodicity, and concluded that Tan-DELTA testing results were within the acceptance criteria and no indication of adverse trend. The team determined the PSEG staffs operability assessment was reasonable.

Corrective Actions: PSEG personnel entered the issue into their corrective action program, performed walkdowns, and completed evaluations.

Corrective Action References: NOTFs 20983829, 20983757, 20983758, and 20984138

Performance Assessment:

Performance Deficiency: The team determined that PSEGs failure to properly adhere to procedure requirements was a performance deficiency that was within the licensees ability to foresee and correct.

Screening: The inspectors determined the performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, by not following the chemistry procedure direction to properly monitor and maintain the cables in a dry condition, the cables could be unknowingly submerged and potentially impact the ability of the safety-related service water pump motors to perform their specified safety functions in the event of an accident.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Exhibit 2, Mitigating Systems Screening Questions, the finding screened as of very low safety significance (Green) because it

(1) did not involve a deficiency affecting the design or qualification of a mitigating SSC that affected its operability or probabilistic risk assessment (PRA) functionality;

(2) was not a degraded condition that represented a loss of the PRA function of a single train TS system for greater than its TS allowed outage time;

(3) did not represent a loss of the PRA function of one train of a multi-train TS system for greater than its TS allowed outage time;

(4) did not represent a loss of the PRA function of two separate TS systems for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />;

(5) did not represent a loss of a PRA system and/or function as defined in the Plant Risk Information Book or the licensees PRA for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and

(6) did not represent a loss of the PRA function of one or more non-TS trains of equipment designated as risk-significant in accordance with the licensees maintenance rule program for greater than three days.

Cross-Cutting Aspect: H.8 - Procedure Adherence: Individuals follow processes, procedures, and work instructions. The finding had a cross-cutting aspect in the Human Performance, cross-cutting area of Procedure Adherence because PSEG staff's failure to follow procedure requirements contained in HC.CH-SO.LE-0002 to initiate a NOTF, when the cable vault water level could not be determined and communicated with control room to allow operation to be captured in the ESOMS log, when the system was removed from and/or restored to service.

Enforcement:

Inspectors did not identify a violation of regulatory requirements associated with this finding.

Inadequate Preventive Maintenance Strategy to Ensure the High-Pressure Coolant Injection (HPCI) Temperature Control Valve (TCV) Would Perform Its Safety Function Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems

Green NCV 05000354/2024010-02 Open/Closed

None (NPP)71111.21M The team identified a Green finding and associated non-cited violation (NCV) of Technical Specification (TS) 6.8, "Procedures and Programs," because PSEG did not establish procedures covering activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Specifically, PSEG did not have a preventive maintenance strategy for the HPCI system lube oil TCV. The team identified that PSEG canceled the five-year replacement preventive maintenance activity for the TCV in 2006 and did not establish a new maintenance strategy for the valve.

Description:

The team observed the performance of the HPCI system during the quarterly inservice test (IST) on December 5, 2024. PSEG staff used procedure HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - OP204 and OP217 - Inservice Test, Revision 71, to perform the testing of the system to meet the Hope Creek TS surveillance test and associated IST requirements. During the test, the team noted the temperature of the lube oil leaving the lube oil cooler indicated 140 degrees Fahrenheit (degF) based on the analog temperature gauge. After the test, the team reviewed the completed test procedure and found that operators recorded 140 degF in Step 4.1.28.2 for Bearing Supply Oil Temperature, consistent with the teams observation.

The team reviewed previous HPCI surveillance test results and noted that the bearing supply oil temperature for the last three quarterly tests were recorded as 132, 136 and 138 degF.

The team also reviewed a sample of IST results from 2008 to present and found that the lube oil supply temperature ranged from 120-142 degF. Additionally, the team reviewed the temperature history of the condensate storage tank, which is the cooling water for the HPCI lube oil cooler during the surveillance tests and noted the condensate storage tank temperature ranged from 80-95 degF over the previous two-year period. The condensate storage tank temperature was 88 degF during the December 2024 test.

The team reviewed the design and operation of the HPCI lube oil system. The bearing supply oil temperature is the combined temperature of the lube oil after it exits the lube oil cooler (i.e., heat exchanger) and mixes with the lube oil that has bypassed the cooler. The lube oil system has a TCV located after the lube oil cooler that is designed to control lube oil temperature between 120 and 140 degF by porting lube oil through and/or around the cooler.

When lube oil is below 120 degF, the TCV is positioned to bypass the heat exchanger and as lube oil temperature increases, the TCV redirects lube oil through the heat exchanger until reaching a lube oil bearing supply temperature of 140 degF, at which point all lube oil flows through the heat exchanger. The TCV movement is controlled by an internal piston that re-positions when paraffin wax melts and expands within the valve internals due to increasing lube oil temperature. The team noted the vendor recommended the valve internals should be replaced every six to ten years as part of a preventive maintenance activity to address age-related degradation of the O-rings and paraffin wax.

In response to questions by the team regarding the preventive maintenance activities for the TCV, PSEG staff stated the maintenance activity associated with the TCV was designated as an environmental qualification activity in 2006 (PM EQMSIS M001-HPCI-022). The preventive maintenance replaced the valve internals every five years. However, because the TCV does not have electrical components, PSEG staff determined an environmental qualification activity was not required and the preventive maintenance was canceled. The team was informed that the last time the valve internals had been replaced was September 2008. PSEG staff stated that the preventive maintenance would be replaced with a condition-based monitoring maintenance strategy and further stated that surveillance testing performed on the HPCI system was adequate to evaluate the performance of the TCV. Specifically, Any degradation will be detected and the degraded components replaced.

The team then assessed the adequacy of the condition-based monitoring program. The team reviewed the IST surveillance procedure and found the bearing supply lube oil temperature from the system lube oil temperature gauge was required to be recorded during the HPCI surveillance. The procedure stated to contact engineering if the temperature exceeded 140 degF. The team determined that the 140 degF limit was based on guidance in the HPCI maintenance manual and had been placed in the procedure in 1995. The manual states:

"The turbines are designed to operate with any brand of high-quality turbine oil. The recommended oil viscosity is 150 SSU at 100°F (38°C) for forced-feed lubrication systems.

Minimum oil temperature for operation is 60°F (16°C). During normal surveillance testing, maximum operating oil temperature should not exceed 140°F (60°C), supply to the bearings, or 160°F (72°C), drain from the bearings. A bearing drain temperature of 180°F (82°C) is anticipated for maximum design basis conditions."

The team reviewed PSEG design basis calculations and associated 2004 testing of the lube oil cooler (i.e., heat exchanger) documented in H-1-BJ-MDC-1997, "HPCI Lube Oil System Analysis," Revision 0. The team noted the documented design testing and calculations determined the maximum HPCI lube oil bearing supply temperature was 128 degF with a 95 degF condensate storage tank temperature. Additionally, the testing showed that the TCV was positioned such that 8 gallons per minute lube oil flowed through the cooler (18 gallons per minute was bypassed around the cooler) to maintain lube oil bearing supply temperature at 128 degF during the test. The team noted that the calculation supported the vendors evaluation of the lube oil cooler's capacity. Specifically, PSEGs calculations showed the lube oil cooler would maintain lube oil supply temperatures below HPCI system design temperature limits assuming all lube oil flow going through the cooler (i.e., TCV fully opened)when HPCI was required to take suction from the torus at design basis temperatures (140-170 degF torus temperature).

The team also reviewed PSEGs procedures associated with preventive maintenance activities. The procedure in effect during the 2006 decision to cancel the TCV periodic replacement was MA-AA-716-210, Revision 4, Performance Centered Maintenance Process. Step 2.1 defines condition monitoring as Continuous or periodic monitoring, trending, and diagnosis of equipment and components using techniques such as vibration monitoring, temperature monitoring, lube oil analysis, leak rates, acoustics, ultrasonics, motor analysis, etc., to forecast equipment failures. Condition Monitoring results are used to monitor and trend equipment performance so that planned maintenance can be performed prior to equipment failure. Step 2.19 defines preventive maintenance as Maintenance performed with the intent of preventing a component or sub-component from failing to perform its function. Activities which are preplanned and directed at preventing inservice failures. It includes actions needed to ensure that plant equipment, including special tools, continues to operate properly by detection or prevention of actual or impending failure or substandard performance. Normally, these activities are scheduled for performance at set frequencies (i.e., time directed) but may also be initiated based upon a specific event or set of plant conditions (i.e., condition directed). The inspectors noted the HPCI TCV was classified as a critical component, but PSEG did not establish any preventive maintenance activities contrary to the procedure. The current procedure in effect is ER-AA-210, Revision 4, Preventative Maintenance (PM) Program. The inspectors noted that the activities for preventive maintenance and condition monitoring are the same as the procedure that was in effect in 2006 when the TCV preventive maintenance was changed, and therefore, the same requirements apply for a critical component.

The team observed that PSEG had not performed a technical analysis to determine whether the IST temperature limit of 140 degF was adequate to assess performance of the TCV. The team also found that PSEG did not perform trending of condensate storage tank and HPCI lube oil temperatures, which would be part of condition monitoring. The team noted the TCV was not listed in the preventive maintenance program template, and the lube oil temperature gauge had an error of 12 degF during the test. Finally, when reviewing the corrective actions taken during a 2020 surveillance test when lube oil temperature exceeded 140 degF (142 degF measured), PSEG staff concluded that it was not an adverse condition. The team observed that with a condensate storage tank supply temperature of 88 degF (December 2024 test value), the lube oil discharge temperature should have been less than 128 degF based on PSEG design calculations and previous tests, not the measured temperature of 140 degF. PSEGs monitoring program did not conclude that this was an adverse condition.

The team concluded PSEG did not establish a preventive maintenance strategy to prevent the TCV, a critical component, from failing to perform its function after canceling the periodic replacement in 2006. Specifically, there was not a condition monitoring or a conditioned-based maintenance program that could be credited as a preventive maintenance strategy to evaluate age-related degradation of internal HPCI TCV elements, and there was no preventive maintenance to replace the valve internals at an adequately evaluated time interval.

Corrective Actions: PSEG staff generated a condition report (i.e., NOTF) to identify the TCV had no preventive maintenance associated with it and planned actions to implement a time-based replacement strategy for the component.

Corrective Action References: NOTF 20983620

Performance Assessment:

Performance Deficiency: The team determined that PSEGs failure to establish a preventive maintenance strategy to ensure the HPCI lube oil TCV, a critical component, would perform its safety function under all design bases conditions was a performance deficiency and was within PSEG's ability to foresee and correct.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, exceeding the previously analyzed time period for replacement without an analysis and not establishing an appropriate monitoring program or refurbishment plan caused reasonable doubt on the continual ability and reliability of the HPCI system to perform its safety-related function. The issue is similar to the more than minor guidance in example 13.a of IMC 0612, Appendix E, Examples of Minor Issues.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined the finding to be of very low safety significance (Green) because the HPCI system maintained its operability as demonstrated through the functioning of the TCV captured by digital temperature indicators in the previous surveillance test.

Cross-Cutting Aspect: Not Present Performance. No cross-cutting aspect was assigned to this finding because the inspectors determined the finding did not reflect present licensee performance.

Enforcement:

Violation: TS 6.8.1 requires, in part, that written procedures recommended in Appendix A of Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Revision 2, February 1978, shall be established, implemented, and maintained. Regulatory Guide 1.33, Appendix A, Section 9, Procedures for Performing Maintenance, states in 9.b., that preventive maintenance schedules should be developed to specify, in part, the inspection or replacement of parts that have a specific lifetime.

Contrary to the above, since September 2008, PSEG did not establish a preventive maintenance schedule associated with the replacement or inspection of parts. In 2006, PSEG canceled the preventive maintenance replacement of the HPCI lube oil TCV internals, originally scheduled on a five frequency, and did not establish a maintenance strategy to address age-related degradation of the valve internal components in order to identify and correct degradation of the TCV that could lead to failure of the HPCI system during design basis events.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Change to Emergency Diesel Generator (EDG) Operating Procedure Without Obtaining a License Amendment Cornerstone Significance/Severity Cross-Cutting Aspect Report Section Mitigating Systems

Green Severity Level IV NCV 05000354/2024010-03 Open/Closed

[H.6] - Design Margins 71111.21M The team identified a Green finding and associated Severity Level IV non-cited violation (NCV) of 10 CFR 50.59, Changes, Tests, and Experiments, when PSEG did not obtain a license amendment prior to changing the EDG operating procedure. The team determined the change affected the Hope Creek TSs, and the change resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, and component (SSC) important to safety previously evaluated in the updated final safety analysis report (UFSAR). The team identified a violation of TS 3.8.1, A.C. Sources, also occurred as a result of the performance deficiency.

Description:

The team reviewed procedure HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 78, which incorporated a new Section 4.15 Jacket Water Expansion Tank Makeup Using SACS. The change allowed the use of the safety auxiliaries cooling system (SACS) water inventory to refill the EDG jacket water system in the event of excessive leakage from the EDG jacket water system. The updated procedure provided guidance to transfer the water via installation of a temporary hose connected to the SACS and manual operation of SACS drain valves allowing water from the SACS head tank to refill the EDG jacket water head tank. The team noted the procedure did not identify any restrictions or limitations related to its use. As a result, PSEG operators could use the procedure to maintain the EDG operable with identified leakage from the jacket water cooling system and allowed operators to use the procedure during design basis events to restore jacket water level resulting from system leakage.

The team reviewed the design and licensing basis of the affected systems and noted that the UFSAR credited the demineralized water system as the normal fill method for the EDG jacket water system, but this fill method would not be available during a loss of offsite power. The team noted the UFSAR stated the EDG jacket water head tank was designed to have adequate inventory to ensure operability of the EDG for the mission time during an event. The team also noted the USFAR-described design function for SACS did not include refill of the EDG jacket water system to maintain or restore EDG operability.

The team reviewed PSEGs 50.59 screen, H2021-053-R1, dated September 12, 2024, for changes to the EDG operating procedure that evaluated whether the change could be made by PSEG as outlined in 10 CFR 50.59. PSEG staff concluded there was no adverse impact on the EDG or SACS systems and, therefore, the change could be made without a license amendment. Based on the conclusion in the screen, PSEG did not perform a 50.59 evaluation.

The team noted SACS was designed with American Society of Mechanical Engineers class 3 piping and components, and the Hope Creak design and licensing basis assumed a single failure of an SSC following a design basis accident. USFAR Section 1.2.2.1.2, Safety Design Criteria, states 11. Essential safety actions are provided by systems of sufficient redundance and independence such that no single failure of active components, or of passive components in certain cases, results in the complete failure of a system. The team identified the change to the procedure required a SACS American Society of Mechanical Engineers class 3 boundary valve and end cap [EDG Lube Oil Heat Exchanger Tube Side Drain Valve 1-KJ-V543(V544, V545, V546)] to be opened and then credited manual operator action to close the valve following the refill of the jacket water system. The team also identified that an assumed single failure of the operator to reclose the valve or failure of the valve to close could result in loss of the SACS which would cause the failure of multiple SSCs including two EDGs. As a result, the team concluded that the change was adverse to the SSC function and an evaluation needed to be performed to assess the questions outlined in 10 CFR 50.59.

As a result of the teams questions, PSEG staff entered the issue into the corrective action program and performed a 10 CFR 50.59 evaluation to address the teams concerns in accordance with PSEG procedures LS-AA-104 and LS-AA-104-1000. The team noted both procedures stated the guidance in Nuclear Energy Institute 96-07, Revision 1, Guidelines for 10 CFR 50.59 Implementation, should be used for evaluating changes. The team also noted that Nuclear Energy Institute 96-07 had been previously approved by the NRC for evaluating changes in accordance with 10 CFR 50.59. The team reviewed PSEGs 50.59 evaluation documented in H2021-053, Revision 2, dated January 17, 2025, and observed the following:

• Question ii - The team determined PSEGs conclusion that there was no increase in the likelihood of occurrence of a malfunction of the EDG or SACS system was not consistent with the guidance. Specifically, the change introduced a common mode failure of two EDGs, and the conclusion that the operator or valve could not fail was not consistent with the single failure design standard, and therefore, was a departure from the performance standards as outlined in the General Design Criteria (Appendix A to Part 50). Additionally, the change would reduce system separation and independence which are also considered more than minimal because the failure of the operator or valve could result in the loss of two EDGs. Finally, the team found that the probability of failure of the operator action or the valve increased the probability of failure of two EDGs by greater than a factor of 2. As a result, the team concluded that question ii should be answered yes requiring NRC approval for the change.

• Question vi - The team determined PSEGs conclusion that there was not a possibility of a malfunction with a different result than previously evaluated was not consistent with the guidance. Specifically, the proposed change increased the likelihood of a malfunction previously thought to be incredible - failure of a passive boundary versus failure of an operator action, and the procedure introduces a credible common mode failure because failure of the valve to close would result in loss of two EDGs.

The team noted the intent of the procedure change was to credit its use to maintain EDG operability; however, the team observed the 50.59 safety evaluation stated the procedure could not be credited for all design basis events. As a result, the team identified that the change would impact TS and would require NRC review and approval as stated in 10 CFR 50.59(c)(1). The teams review of the 50.59 screen, H2021-053, Revision 1, associated with this change identified that the purpose of the procedure change and screen was to credit the actions outlined in the procedure change to ensure EDG operability when jacket water leakage was identified. However, the team found in the 50.59 evaluation, H2021-053, Revision 2, that PSEG staff did not state the EDGs could be considered Operable if a jacket water leak was identified, and instead, stated Operations would determine the EDG operability when crediting this procedure. Additionally, PSEG staff stated there would be inadequate water inventory in the SACS system during certain design basis events which would preclude the use of the procedure steps. As a result, the team determined that the procedure could not be used to maintain operability of an EDG unless the seismic with loss of offsite power design basis event was removed from the Hope Creek design basis.

Finally, the team reviewed NOTF 2098003 and NOTF 20980081 written following the identification of leaks from the jacket water pump mechanical seal and the jacket water hose in November 2024. As documented in NOTF 20980081, PSEG staff concluded: The 'C' EDG is OPERABLE and able to meet all design functions based upon a leak rate of 210 ml/min, based on the combination of available sources of makeup the automatic makeup capabilities of the demineralized water system, and procedurally driven compensatory measures available in HC.OP-SO.KJ-0001, Section 4.15, to augment the normal source of makeup The team noted that PSEG staff did not have a basis to conclude the EDG was operable because Section 4.15 of the procedure HC.OP-SO.KJ-0001 could not be credited for all design basis events. The team determined that PSEG staff incorrectly credited the use of the procedure to maintain the operability of the C EDG, and the TS 3.8.1.1 Actions for one EDG inoperable were not taken.

Corrective Actions: In response to the teams observation on the 50.59 screen, PSEG staff implemented an immediate standing order to not use the new steps in the EDG operating procedure until completion of the associated 50.59 evaluation. PSEG subsequently voided the 50.59 evaluation H2021-053 and planned actions to revise HC.OP-SO.KJ-0001 to eliminate the procedural steps to credit SACS as a makeup water source for the EDG jacket water system when jacket water leaks exist.

Corrective Action References: NOTF 20986948

Performance Assessment:

Performance Deficiency: The inspectors determined PSEG's failure to obtain a license amendment prior to implementing a change to the EDG operating procedure in accordance with 10 CFR 50.59(c) was a performance deficiency. Specifically, PSEG staff incorrectly determined the procedure change did not result in any adverse impacts when the change actually resulted in more than a minimal likelihood of occurrence of a failure of safety-related equipment.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the revised operating procedure resulted in a more than a minimal likelihood of occurrence of a failure of the SACS and EDGs during a seismic event with a loss of offsite power, and PSEG staff utilized the procedure to incorrectly declare the C EDG operable while it had a jacket water system leak.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined this finding to be of very low safety significance (Green) in accordance with Exhibit 2, because

(1) it did not involve a deficiency affecting the design or qualification of a mitigating SSC that affected its operability or PRA functionality;

(2) it was not a degraded condition that represented a loss of the PRA function of a single train TS system for greater than its TS allowed outage time;

(3) it did not represent a loss of the PRA function of one train of a multi-train TS system for greater than its TS allowed outage time;

(4) it did not represent a loss of the PRA function of two separate TS systems for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />;

(5) it did not represent a loss of a PRA system and/or function as defined in the Plant Risk Information Book or the licensees PRA for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and

(6) it did not represent a loss of the PRA function of one or more non-TS trains of equipment designated as risk-significant in accordance with Constellation's maintenance rule program for greater than three days.

Cross-Cutting Aspect: H.6 - Design Margins: The organization operates and maintains equipment within design margins. Margins are carefully guarded and changed only through a systematic and rigorous process. Special attention is placed on maintaining fission product barriers, defense-in-depth, and safety-related equipment. Specifically, PSEG staff did not carefully guard the design margin of safety-related equipment and did not minimize repeat jacket water leaks associated with the EDGs.

Enforcement:

The ROPs significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it is necessary to address this violation which impedes the NRCs ability to regulate using traditional enforcement to adequately deter non-compliance.

Severity: In accordance with the example in paragraph 6.1.d.2 of the NRC Enforcement Policy, the inspectors determined the traditional enforcement violation was characterized as Severity Level IV because the violation resulted in a condition that was determined to have very low safety significance (Green in the significance determination process).

Violation: 10 CFR 50.59 (c)(1) states, in part, a licensee may make changes in the procedures as described in the final safety analysis report (as updated) without obtaining a license amendment pursuant to Sec. 50.90 only if:

(i) An amendment to the technical specifications incorporated in the license is not required, and

(ii) The change, test, or experiment does not meet any of the criteria in paragraph (c)(2) of this section.

10 CFR 50.59(c)(2)(ii) requires, in part, that a licensee shall obtain a license amendment pursuant to Sec. 50.90 prior to implementing a proposed change that would result in more than a minimal increase in the likelihood of occurrence of a malfunction of a SSC important to safety previously evaluated in the final safety analysis report (as updated).

TS 3.8.1.1 requires, in part, as a minimum, the following A.C. electrical power sources shall be OPERABLE, b. Four separate and independent diesel generators. TS 3.8.1.1 ACTION states, in part, b. With one diesel generator of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the above required A.C. offsite sources by performing Surveillance Requirement 4.8.1.1.1.a within one hour and at least once per eight hours thereafter. If the diesel generator became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.4 separately for each diesel generator within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s* unless the absence of any potential common mode failure for the remaining diesel generators is demonstrated.

Contrary to the above, on September 12, 2024, PSEG changed EDG operating procedure HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, to Revision 78, without obtaining a license amendment pursuant to Sec. 50.90 when the change resulted in more than a minimal increase in the likelihood of the occurrence of a malfunction of an SSC important to safety previously evaluated in the final safety analysis report (as updated). On November 7, 2024, PSEG incorrectly credited the use of procedure HC.OP-SO.KJ-0001 to maintain the operability of the C EDG when a leak on the C EDG jacket water system was discovered and did not perform the required TS 3.8.1.1. actions. Specifically, with the C EDG inoperable, PSEG did not demonstrate the OPERABILITY of the other required A.C.

offsite sources by performing Surveillance Requirement 4.8.1.1.1.a within one hour and at least once per eight hours thereafter.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

• On February 14, 2025, the inspectors presented the comprehensive engineering team inspection results to Eric Larson, Site Vice President, and other members of the licensee staff.

• On December 13, 2024, the inspectors presented the preliminary inspection results to Eric Larson, Site Vice President, and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71111.21M Calculations

MIDACALC Results 1BC-HV-F003A

Revision 4a

19-0018

Maximum Flood Level in Control/Diesel Generator Areas

Revision 9

AB-0083

PSEG Nuclear LLC Generating Station EPU SRV Actuation

Under Station Blackout Conditions

Revision 0

BC-0060

Pressure Difference Across Valve H1BC -BC-HV-F003A

Revision 2

E-9

Standby Class 1E Diesel Generator Sizing

Revision 1

H-1-BJ-MDC-

2004

HPCI Pump Assembly Hydraulic Model

Revision 1

H-1-CG-MDC-

1795

Control Rod Drop Accident Radiological Consequences

Revision 7

Corrective Action

Documents

20597701

20875520

20881741

20886112

20886336

20886549

20886880

20887922

20899135

20902187

20902421

20906927

20912332

20924408

20924911

20927300

20934526

20935538

20939955

20943873

20945527

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

20964925

20966623

20968384

20971223

20979794

20980003

20980004

20980081

Corrective Action

Documents

Resulting from

Inspection

20982586

20982600

20983237

20983241

20983242

20983247

20983250

20983257

20983542

20983545

20983578

20983579

20983581

20983582

20983586

20983605

20983612

20983618

20983620

20983621

20983625

20983638

20983644

20983645

20983649

20983675

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

20983688

20983757

20983758

20983821

20983829

20983839

20983844

20983850

20983865

20983879

20983881

20983882

20983887

20983896

20983899

20984024

20984026

20984121

20984127

20984132

20984133

20984138

Drawings

M-12-1

Safety Auxiliaries Cooling Auxiliary Building P&ID

Revision 31

M-22-0 Sh. 3

Fire Protection Fire Water Reactor and Auxiliary Buildings

Revision 17

M-55-1

High-Pressure Coolant Injection P&ID

Revision 40

M-56-1

HPCI Pump Turbine P&ID

Revision 34

Engineering

Evaluations

238637-0020

HPCI Oil Cooling Technical Evaluation

dated

2/16/24

80107159

Operator Response Time Validation for HC.FP-SO.KC-0001

dated

7/18/18

OE 325514

Potential Unanalyzed Release Path with Significant

Radiological Consequences for Control Rod Drop Accident

(CRDA)

dated

11/2/16

Miscellaneous

H-1-PH-EDS-

480V MCC Compartment Replacement Specification

Revision 4

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

29

H-1-PN-KQA-

0001

Qualitative Assessment

Revision 0

HC.IC-CC.KL-

0003

Containment Instrument Gas Low Low Pressure 1KLPSLL-

5132A

performed

9/6/24

HC.IC-CC.KL-

0004

Containment Instrument Gas Low Low Pressure 1KLPSLL-

5132B

performed

9/20/24

HC.OP-IS.BJ-

0001

HPCI Main and Booster Pump Set - OP 204 and OP 217 -

Inservice Test

performed

9/6/24

HC.OP-LR.ZZ-

0003

Leakage Test of Safety/Relief Valve Accumulators

performed

4/5/24

HC.OP-PT.GS-

0001

Hardened Containment Vent System (HCVS) Periodic Valve

Test

performed

10/17/22

LR-N18-0013

License Amendment Request (LAR) to Amend the Hope

Creek Technical Specifications (TS) to Revise Actions for

Inoperable Emergency Diesel Generator (EDG) A or B

dated

3/128/18

NRC Information Notice 2010-26

Submerged Electrical Cables

dated

2/2/10

PM148Q-0012

Preparation and Installation of the Composite Type Rupture

Disc (Light Lip and Heavy Lip) in 30 Degree Seat, 7I Insert,

Full Bolted and Union Type Holders

Revision 0

VTD 323602

Nuclear Maintenance Applications Center: Terry Turbine

Maintenance Guide, High-Pressure Coolant Injection (HPCI)

Application

2013

VTD 430868

HL 160M Dri-Prime Pumps

Revision 4

VTD 432429

Target Rock Safety/Relief Valve Model 0867F-001

Revision 2

VTD 433052

Equipment Dynamic Qualification

Revision 1

VTD PN0-B31-

4010-0014

Reactor Recirculation System

Revision 6

Procedures

CY-AB-140-410

Hope Creek Station Diesel Fuel Oil Testing Program

Revision 10

ER-AA-3003

Cable Condition Monitoring and Aging Management

Program

Revision 3

HC.OP-

AB.COOL-0005

Total Loss of Station Service Water

Revision 6

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

HC.OP-AB.ZZ-

01350SBOFC

Station Blackout / ELAP Flow Chart

Revision 45

HC.OP-EO.ZZ-

0318

Containment Venting

Revision 14

HC.OP-IS.BJ-

0001

HPCI Main and Booster Pump Set - OP 204 and OP 217 -

Inservice Test

Revision 71

HC.OP-PT-NB-

4160

AOT Diesel Generators Periodic Test

Revision 5

HC.OP-SO.KJ-

0001

EDG Operation Procedure

Revision 81

OP-AA-111-101-

1001

Use and Development of Operating Logs

Revision 7

Work Orders

229336

258860

30341669

30343353

30385156

30397649

30398588

60151273

60158554