IR 05000354/2024002

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Integrated Inspection Report 05000354/2024002
ML24211A161
Person / Time
Site: Hope Creek PSEG icon.png
Issue date: 07/30/2024
From: Brice Bickett
NRC/RGN-I/DORS
To: Mcfeaters C
Public Service Enterprise Group
References
IR 2024002
Download: ML24211A161 (1)
v • d • e


Text

July 30, 2024

SUBJECT:

HOPE CREEK GENERATING STATION - INTEGRATED INSPECTION REPORT 05000354/2024002

Dear Charles McFeaters:

On June 30, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station. On July 17, 2024, the NRC inspectors discussed the results of this inspection with Robert DeNight, 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. 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 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, Brice A. Bickett, Chief Projects Branch 3 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: 05000354/2024002

Enterprise Identifier: I-2024-002- 0037

Licensee: PSEG Nuclear, LLC - N09

Facility: Hope Creek Generating Station

Location: Hancocks Bridge, NJ

Inspection Dates: April 01, 2024 to June 30, 2024

Inspectors: J. Patel, Senior Resident Inspector J. Bresson, Resident Inspector R. Rolph, Senior Health Physicist A. Tran, Resident Inspector A. Turilin, Reactor Inspector

Approved By: Brice A. Bickett, Chief Projects Branch 3 Division of Operating Reactor Safety

Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated 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 Maintain Reactor Pressure Vessel Level Within Desired Band During Cooldown and Depressurization Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green None (NPP) 71111.20 NCV 05000354/2024002-01 Open/Closed A self-revealed Green finding and associated non-cited violation (NCV) of Hope Creek Generating Station (Hope Creek) Technical Specification (TS) 6.8, Procedures and Programs, was identified for the licensees failure to maintain written procedures as required by Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Revision 2, Appendix A, Section 4. Specifically, PSEG failed to maintain HC.OP-IO.ZZ-0004,

Shutdown From Rated Power to Cold Shutdown, Revision 122, resulting in the fai lure to maintain reactor pressure vessel (RPV) level within the required level band during plant cooldown and depressurization.

Failure to Create and Implement a Foreign Material Exclusion Plan Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 71152A FIN 05000354/2024002- 02 Complacency Open/Closed A self-revealed Green finding was identified when the licensee failed to create and implement a Foreign Material Exclusion (FME) plan. Specifically, the licensee failed to create and implement a FME plan for repairs of the #4 Turbine Control Valve (TCV) as required by MA-AA-716-008, "Foreign Material Exclusion Program."

Failure to Implement Troubleshooting Procedure Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.11] - 71152A NCV 05000354/2024002-03 Challenge the Open/Closed Unknown A self-revealed Green finding and associated non-cited violation (NCV) of 10 CFR 50,

Appendix B, Criterion V, Instructions, Procedures and Drawings, were identified when the licensee failed to enter complex troubleshooting. Specifically, contrary to quality procedure MA-AA- 716-004, Conduct of Troubleshooting, the licensee did not enter complex troubleshooting following equipment failures that resulted in major degradation of balance of plant equipment.

Additional Tracking Items

Type Issue Number Title Report Section Status LER 05000354/2023-003-00 LER 2023-003-00 for Hope 71153 Closed Creek Generating Station,

Inadvertent Main Turbine Control Valve Closure Caused Reactor Scram

LER 05000354/2023-003-01 LER 2023-003-01 for Hope 71153 Closed Creek Generating Station,

Inadvertent Main Turbine Control Valve Closure Caused Reactor Scram

NOV 05000354/2023090-01 Nuclear Control Room 92702 Closed Operator Inattentive While At Nuclear Control Console EA-23- 073

PLANT STATUS

The Hope Creek Generating Station (Hope Creek) began the inspection period at approximately 84 percent power, entering an end-of-cycle coastdown period. On April 3, 2024, the unit commenced a shutdown for a planned refueling outage (H1R25). The unit commenced startup on May 11, 2024, and reached rated thermal power on May 16, 2024. On May 20, 2024, the unit reduced power to 82 percent to perform maintenance on the C reactor feedwater pump.

Following the maintenance, the unit returned to rated thermal power on June 13, 2024 and remained at or near rated thermal power for the remainder of the inspection period.

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 performed activities described in IMC 2515, Appendix D, Plant Status, observed risk significant activities, and completed on -site portions of IPs. 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

71111.01 - Adverse Weather Protection

Seasonal Extreme Weather Sample (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated the licensees readiness for seasonal extreme hot weather conditions during the week of June 24, 2024.

71111.04 - Equipment Alignment

Partial Walkdown Sample (IP Section 03.01) (4 Samples)

The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:

(1) Safety-related 4.16 kilovolt (kV) bus 10A401 during maintenance on 10A402 bus, April 8, 2024
(2) 'A' station service water train during 'B' station service water loop work window, April 12, 2024
(3) High-pressure coolant injection system, June 13, 2024
(4) Keep filled system for emergency core cooling system during condensate transfer to

'D' residual heat removal pump discharge header check valve maintenance, June 18, 2024

71111.05 - Fire Protection

Fire Area Walkdown and Inspection Sample (IP Section 03.01) (6 Samples)

The inspectors evaluated the implementation of the fire protection program by conducting a walkdown and performing a review to verify program compliance, equipment functionality, material condition, and operational readiness of the following fire areas:

(1) Torus area in FP-HC-3415, April 18, 2024
(2) High-pressure coolant injection, 250VDC motor control center room, pre-fire plan FP-HC-3413, June 13, 2024
(3) Reactor core isolation cooling 250VDC motor control center room, pre-fire plan FP-HC-3412, June 18, 2024
(4) Lower control equipment room, pre-fire plan FP-HC-3532, June 28, 2024
(5) Electrical access area, pre-fire plan FP-HC-3533, June 28, 2024
(6) Safety-related Class 1E switchgear rooms, pre-fire plan FP-HC-3541, June 28, 2024

71111.07A - Heat Exchanger/Sink Performance

Annual Review (IP Section 03.01) (1 Sample)

The inspectors evaluated readiness and performance of:

(1) B1 and B2 safety auxiliary cooling system heat exchangers

71111.08G - Inservice Inspection Activities (BWR)

BWR Inservice Inspection Activities Sample - Nondestructive Examination and Welding

Activities (IP Section 03.01)

Main article: IP 71111.08G

The inspectors evaluated boiling water reactor nondestructive testing by reviewing the following examinations from April 8 - 12, 2024:

(1)

  • Manual ultronic tti of -5ircilzloaf

-- 12VCA - -5 (Nondestrtive E*aminatitCGS -- -

  • General visual examinations of the containment, including accessible portions of the drywell and torus surfaces (Nondestructive Examination Report HCGS-VE- 24- 001)
  • H1R25 torus project underwater cleaning, inspections and coating repair, RCN- 122 (WO 30264763)
  • Reviewed problem identification and resolution performance to evaluate and defer manual ultrasonic testing of reactor vessel bottom head drain line component 1- BG-100-641-L1 (90- degree elbow, FAC# G502) to the next refueling outage

71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance

Licensed Operator Performance in the Actual Plant/Main Control Room (IP Section 03.01) (1 Sample)

(1) The inspectors observed and evaluated licensed operator performance in the main control room during a plant shutdown for a refueling outage on April 3, 2024.

Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)

(1) The inspectors observed and evaluated licensed operator performance in the simulator during licensed operator requalification training on June 6, 2024.

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (1 Sample)

The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:

(1) 'D' emergency diesel generator trip of output breaker due to failure of overexcitation relay, June 20, 2024

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management Sample (IP Section 03.01) (5 Samples)

The inspectors evaluated the accuracy and completeness of risk assessments for the following planned and emergent work activities to ensure configuration changes and appropriate work controls were addressed:

(1) Planned risk during unavailability of 'B' loop shutdown cooling, 'C/D' source range monitors), and intermediate-range monitors, week of April 8, 2024
(2) Elevated risk during lowered inventory in RPV, April 27, 2024
(3) Emergent unavailability of 'C' reactor feed pump, week of May 20, 2024
(4) Planned inoperability of 'B' emergency diesel generator, week of June 10, 2024
(5) Review of risk assessment for planned maintenance activities onset of hot weather alert, week of June 17, 2024

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) (5 Samples)

The inspectors evaluated the licensee's justifications and actions associated with the following operability determinations and functionality assessments:

(1) B2 safety auxiliaries cooling system heat exchanger silting, April 10, 2024
(2) 'A' channel source range monitor erratic indication during refuel operation, April 12-14, 2024
(3) Reactor vessel metal temperature indication, May 2, 2024
(4) Salt service water rupture disc piping silting, May 10, 2024
(5) Reactor core isolation coolant trip rod spring elongated, May 18, 2024

71111.18 - Plant Modifications

Temporary Modifications and/or Permanent Modifications (IP Section 03.01 and/or 03.02) (1 Sample)

The inspectors evaluated the following temporary or permanent modifications:

(1) Loss of stator water cooling turbine and recirculate runback elimination modification (80136073), May 29, 2024

71111.20 - Refueling and Other Outage Activities

Refueling/Other Outage Sample (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated refueling outage H1R25 activities from April 3 - May 14, 2024.

71111.24 - Testing and Maintenance of Equipment Important to Risk

The inspectors evaluated the following testing and maintenance activities to verify system operability and/or functionality:

Post-Maintenance Testing (PMT) (IP Section 03.01) (4 Samples)

(1) Inboard main steam isolation valves following actuator replacement, week of April 22, 2024
(2) Reactor water cleanup drain line flange, downstream of reactor coolant pressure boundary valves, leak repair, May 10, 2024
(3) Reactor core isolation coolant outboard steam isolation valve F008, May 18, 2024
(4) 'B' emergency diesel generator following planned maintenance, June 11, 2024

Surveillance Testing (IP Section 03.01) (4 Samples)

(1) HC.MD-ST.PJ-0008, "250 Volts Station Batteries Service Test Using BCT-2000 with Windows Software and Associated Surveillance Testing," April 16, 2024
(2) HC.OP-ST.KJ-0006, "Integrated Emergency Diesel Generator 1BG400 Test,"

April 22, 2024

(3) HC.RE-ST.BF-0001, "Control Rod Scram Time Surveillance," April 30, 2024
(4) HC.OP-LR.ZZ-0004, "Primary Containment Integrated Leak Rate Test,"

May 2-3, 2024

Containment Isolation Valve (CIV) Testing (IP Section 03.01) (1 Sample)

(1) HC.OP-LR.AB-0001/2/3/4, "Main Steam Isolation Valve Local Leak Rate Tests," April 8,

RADIATION SAFETY

71124.01 - Radiological Hazard Assessment and Exposure Controls

Radiological Hazard Assessment (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated how the licensee identifies the magnitude and extent of radiation levels, the concentrations and quantities of radioactive materials, and how the licensee assesses radiological hazards.

Instructions to Workers (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated how the licensee instructs workers on plant-related radiological hazards and the radiation protection requirements intended to protect workers from those hazards.

Contamination and Radioactive Material Control (IP Section 03.03) (2 Samples)

The inspectors observed/evaluated the following licensee processes for monitoring and controlling contamination and radioactive material:

(1) The inspectors evaluated/observed the licensee's control of radiological hazards in the clean area inside the radiological control area for the generator rewind work.
(2) The inspectors observed the controls established at the radiation protection control point during the refueling shutdown.

Radiological Hazards Control and Work Coverage (IP Section 03.04) (4 Samples)

The inspectors evaluated the licensee's control of radiological hazards for the following radiological work:

(1) Turbine building condenser work
(2) Reactor building refuel floor activities during the refueling shutdown
(3) Replacement of the reactor water cleanup piping
(4) Under vessel work to replace low power radiation monitors

High Radiation Area and Very High Radiation Area Controls (IP Section 03.05) (3 Samples)

The inspectors evaluated licensee controls of the following high radiation areas (HRAs) and very high radiation areas (VHRAs):

(1) Traversing incore detector room
(2) Spent resin pump room
(3) Cleanup phase separator room

Radiation Worker Performance and Radiation Protection Technician Proficiency (IP Section 03.06) (1 Sample)

(1) The inspectors evaluated radiation worker and radiation protection technician performance as it pertains to radiation protection requirements.

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification

The inspectors verified licensee performance indicators submittals listed below:

MS05: Safety System Functional Failures (SSFFs) Sample (IP Section 02.04)===

Main article: IP 71151
(1) April 1, 2023 through March 31, 2024

MS06: Emergency AC Power Systems (IP Section 02.05) (1 Sample)

(1) April 1, 2023 through March 31, 2024

BI01: Reactor Coolant System (RCS) Specific Activity Sample (IP Section 02.10) (1 Sample)

(1) April 1, 2023 through March 31, 2024

BI02: RCS Leak Rate Sample (IP Section 02.11) (1 Sample)

(1) April 1, 2023 through March 31, 2024

71152A - Annual Follow-Up Problem Identification and Resolution Annual Follow-Up of Selected Issues (Section 03.03)

Main article: IP 71152

The inspectors reviewed the licensees implementation of its corrective action program related to the following issues:

(1) Review of Root Cause Evaluation (RCE) 70233173 and corrective actions associated with the inadequate restoration of TCV resulting in plant scram.

71152S - Semiannual Trend Problem Identification and Resolution Semiannual Trend Review (Section 03.02)

Main article: IP 71152
(1) The inspectors reviewed PSEG's corrective action program for trends that might be indicative of a more significant safety issue.

71153 - Follow-Up of Events and Notices of Enforcement Discretion Event Report (IP Section 03.02)

Main article: IP 71153

The inspectors evaluated the following licensees event reporting determinations to ensure it complied with reporting requirements.

(1) LER 05000354/2023-003-00, 01, "Inadvertent Main Turbine Control Valve Closure Caused Reactor Scram," (ML24043A168), and updated LER submittal

===05000354/2023-003-01 (ML24079A283). The inspection conclusions associated with these LERs are documented in this report under Inspection Results Section 71152.

These LERs are closed.

OTHER ACTIVITIES

- TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNORMAL

92702 - Follow-Up on Traditional Enforcement Actions Including Violations, Deviations, Confirmatory Action Letters, and Orders

Follow-Up on Traditional Enforcement Actions Including Violations, Deviations, Confirmatory Action Letters, and Orders===

Main article: IP 05000
(1) Follow-up on corrective actions associated with the Notice of Violation (NOV)

(05000354/2023090-01). In the NOV (05000354/2023090- 01) cover letter, PSEG was not required to provide a docketed response to the cited violation. The inspectors used IP 92702, Follow-up on Traditional Enforcement Actions including Violations, Deviations, Confirmatory Action Letters, and Orders, to review PSEGs apparent cause evaluation and completion of planned corrective actions associated with the violation. In combination with the NRCs previous determination, as noted in the NOV letter, that the cause for the violation, completed corrective actions, and the date when full compliance was achieved, inspectors determined all were adequately addressed. This NOV is closed.

INSPECTION RESULTS

Failure to Maintain Reactor Pressure Vessel Level Within Desired Band During Cooldown and Depressurization Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green None (NPP) 71111.20 NCV 05000354/2024002 - 01 Open/Closed A self- revealed Green finding and associated non- cited violation (NCV) of Hope Creek Generating Station (Hope Creek) Technical Specification (TS) 6.8, Procedures and Programs, was identified for the licensees failure to maintain written procedures as required by Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Revision 2, Appendix A, Section 4.

Specifically, PSEG failed to maintain HC.OP- IO.ZZ - 0004, Shu tdown From Rated Power to Cold Shutdown, Revision 122, resulting in the failure to maintain reactor pressure vessel (RPV) level within the required level band during plant cooldown and depressurization.

Description:

The Hope Creek condensate system includes three one -third capacity, vertical, centrifugal, motor- driven primary condensate pumps (PCPs) and three one - third capacity, horizontal, centrifugal, motor - driven secondary condensate pumps (SCPs). The PCPs receive condensate from a common header interconnecting three condenser hotwells, and the discharge from these pumps provides driving flow through the condensate cleanup system before entering the condensate demineralizer system. The SCPs restore the system driving head lost in the purification process, and their discharge is directed through five stages of feedwater heating before delivery to the reactor feed pump suction. The SCPs also provide the required net positive suction head for the reactor feed pumps. During plant cooldown and depressuri zation, when the reactor feed pumps are not available to feed the RPV, the PCPs and SCPs provide the required feedwater to the RPV for level control.

On April 3, 2024, Hope Creek initiated a plant shutdown in accordance with procedure HC.OP-IO.ZZ-0004, Revision 122, to commence the refueling outage RF25. During the shutdown process, at approximately 30 percent rated thermal power, the procedure directed operators to stop one PCP and one SCP. After achieving Mode 3, Hot Shutdown, and entering reactor cooldown and depressurization, at an RPV pressure of approximately 500 psig, the procedure directed the removal of the remaining reactor feed pumps from service and the removal of the second SCP from service.

Subsequently, while in the reactor cooldown and depressurization process, operators performed Step 4.2.12, which stated that when the RPV pressure is reduced to 140 psig, and if not required, then stop a PCP and SCP. Operators implemented the procedure, and in accordance with the step, they secured the second PCP and the last remaining SCP.

Specifically, at 1900 on April 3, 2024, the A PCP and 'B' SCP were secured, and the RPV level began to lower with only the 'B' PCP in service.

The operators noted in the main control room that when the 'A' PCP was secured, the discharge pressure of the primary condensate header was 170 psig, and the reactor feed pump discharge header pressure was 130 psig. With an RPV pressure of 140 psig, the B PCP did not have sufficient driving pressure to provide sufficient flow to maintain the RPV level. Operators took manual control and actions were taken to arrest the cooldown rate and restart the 'A' PCP to restore the RPV level. During this event, the RPV level lowered from 35 inches to 23 inches until the second PCP was restarted.

PSEG generated Notification (NOTF) 20961933 in their corrective action program and completed a performance analysis. In their analysis, PSEG concluded that procedure HC.OP-IO.ZZ-0004 was inadequate in providing guidance for securing the second PCP and the last remaining SCP at a pressure of 140 psig, as it resulted in an unexpected RPV level response during the plant shutdown. PSEG reviewed the past performance of this procedure and analyzed historical trends of recent plant shutdowns to gather data on the RPV pressure previously used when performing this step. These data reviews indicated that operators historically secured condensate pumps to leave one PCP feeding the RPV at an RPV pressure of less than 100 psig.

Additionally, PSEG documented in their performance analysis that during the shutdown for entry into refueling outage RF21 in 2018, a similar issue was identified when the last SCP was secured. At that time, the procedure directed securing the pumps at an RPV pressure of 150 psig. As a corrective action, the procedure was revised to change this directive to 140 psig. The inspectors reviewed the change documents associated with the procedure revision to 140 psig RPV pressure for the removal of the condensate pump. The inspectors determined that the change documents did not provide a technical basis, such as the performance of a hydraulic analysis that reviewed pump discharge pressure and considered total pressure loss from system piping and static head, to assess whether the removal of in-service pumps at an RPV pressure of 140 psig and feeding the RPV with only one PCP would be sufficient to maintain the RPV level during the cooldown and depressurization phase.

Corrective Actions: PSEGs immediate corrective action was to revise procedure HC.OP-IO.ZZ-0004, specifically Step 4.2.12. The revised procedure now directs operators to secure a PCP and SCP when RPV pressure is reduced to 100 psig, and if they are not required.

Corrective Action References: 70234861

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEGs failure to maintain procedure HC.OP-IO.ZZ-0004, Shutdown From Rated Power to Cold Shutdown, Revision 122, was a performance deficiency that was within their ability to foresee and correct and should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Procedure Quality attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, this event caused the RPV level to drop from 35 inches to 23 inches, which was an unexpected plant response. Consequently, this caused an unnecessary challenge to operators and required them to take manual actions, intervened to stop the RPV level from dropping further. They were required to secure the cooldown and restart the second PCP to restore the level within the range.

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 1, Initiating Events Screening Questions, the finding screened to Green, very low safety significance, because this performance deficiency did not cause reactor trip and did not cause loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, that is loss of condenser or feedwater. The inspectors evaluated the applicability of IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, and determined that Appendix G was not applicable for this finding because the shutdown cooling system to remove residual heat was not in service, and the conditions required to place that system in service were not met.

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: Hope Creek TS 6.8.1, Procedures and Programs, requires in part that written procedure shall be established, implemented, and maintained covering the application procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, Section 4, states, in part, that instructions for energizing, filling, venting, draining, startup, shutdown, and changing modes of operation should be prepared, as appropriate, for the condensate system (hotwell to feedwater pumps). Contrary to this, as of April 3, 2024, PSEG failed to maintain procedure HC.OP-IO.ZZ-0004, Shutdown From Rated Power to Cold Shutdown, Revision 122, resulting in the failure to maintain RPV level within the required level band during plant cooldown and depressurization.

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

Failure to Create and Implement a Foreign Material Exclusion Plan Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 71152A FIN 05000354/2024002- 02 Complacency Open/Closed A self- revealed Green finding was identified when the licensee failed to create and implement a Foreign Material Exclusion (FME) plan. Specifically, the licensee failed to create and implement a FME plan for repairs of the #4 Turbine Control Valve (TCV) as required by MA-AA- 716 -008, "Foreign Material Exclusion Program."

Description:

On December 11, 2023, an electrohydraulic control (EHC) leak was discovered on the #4 TCV. Power was reduced to 90 percent to close the #4 TCV and EHC was isolated to stop the leak. Overnight, it was determined that a section of EHC piping would need to be removed to repair the leak and the initial method of removal was unsuccessful. Subsequently, it became evident that the piping would need to be cut out and that grinding and burring would be needed to complete the piping's removal.

The inspectors reviewed MA- AA716 - 008, Foreign Material Exclusion Program, which discusses the establishment of Foreign Material Exclusion Areas (FMEA) to prevent the introduction of foreign material into a system during maintenance activities. According to Section 2.10, an FME plan is the supplemental instructions that describe unique FME challenges and specific controls required for work activities that involve breaching a system/component. Section 2.20 defines FMEA 1 (High Risk FMEA) as, The highest level of FME control imposed on a system or component. Section 2.17 states that FMEA 2 (Standard risk FMEA) is an FMEA established for breaches that do not meet the requirements for FMEA 1 but need some form of FME boundaries and work practices applied.

The inspectors determined that there were two procedures directing PSEG to create an FME plan for these repairs and that the FME plan would have driven the repair's classification as FMEA1. Specifically, MA - AA- 716- 008, Section 4.2.8.1, in part, directs the development of an FME plans for more complex and critical activities commensurate with the probability and consequences of foreign material intrusion. MA- AA- 716- 008 Attachment 4, Project Plan Requirements, indicated that an FME plan should have been developed for the repairs.

Additionally, according to OP- AA- 107, Integrated Risk Management, the repairs should have been classified as Medium Risk for FME risk and would have also driven the development of an FME plan in accordance with MA - AA- 716 - 008. PSEG did not perform a risk determination and did not develop an FME plan for the repairs. PSEG documented in the RCE that during interviews with personnel after the event, it was revealed that some believed the repair work was FMEA 1, while others believed the work was FMEA 2 or did not know which it was.

After the completion of the repairs on December 14, 2023, fill and vents were performed on the EHC systems using the troubleshooting plan. During the fill and vents evolution, the #4 TCV unexpectedly opened 20 percent and work was halted. Based on PSEG's operating experience, it was not expected to observe significant movement on TCVs during fill and vent evolutions. During this evolution, PSEG contacted their vendor and provided that movement between 5 to 10 percent was normal and PSEG decided to complete the fill and vents steps of the troubleshooting plan. The final step of the procedure involved removing the "Test On" signal from the #4 TCV, with no anticipated movement; however, upon signal removal, the #4 TCV unexpectedly went fully open. This was later discovered, via failure analysis and documented in the RCE, to be due to internal damage caused by foreign material introduced in the EHC system. Consequently, the #4 TCV remained stuck in the fully open position until additional troubleshooting and repairs were completed.

Corrective Actions: PSEG's immediate corrective action was to replace the #4 TCV components and perform multiple high- flow flushes to ensure that the foreign material was removed from the system. Subsequently, PSEG completed a RCE to assess and address the issue of the repair work orders not having an appropriate FME plan.

Corrective Action References: 70233173

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEGs failure to create and implement a FME plan as required by MA-AA- 716-008, "Foreign Material Exclusion Program," was a performance deficiency because it was within PSEGs ability to foresee and correct and should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to create an FME plan allowed for the introduction of foreign material into the TCV EHC system, resulting in the unexpected opening of the #4 TCV and the associated reactor power change.

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 1, Initiating Events Screening Questions, the inspectors determined that the finding was of very low safety significance, Green, because it did not cause a reactor trip, or the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.

Cross-Cutting Aspect: H.12 - Avoid Complacency: Individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Individuals implement appropriate error reduction tools.

Enforcement:

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

Failure to Implement Troubleshooting Procedure Cornerstone Significance Cross- Cutting Report Aspect Section Initiating Events Green [H.11] - 71152A NCV 05000354/2024002 - 03 Challenge the Open/Closed Unknown A self- revealed Green finding and associated non- cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified when the licensee failed to enter complex troubleshooting. Specifically, contrary to quality procedure MA- AA- 716 - 004, Conduct of Troubleshooting, the licensee did not enter complex troubleshooting following equipment failures that result in major degradation of balance of plant equipment.

Description:

On December 14, 2023, the #4 TCV unexpectedly stroked full open during restoration from repairs. PSEG decided to close the #4 TCV by manually actuating the fast -

acting solenoid (FAS), which they believed would result in a controlled closure; however, when PSEG performed this step in accordance with the simple troubleshooting plan, it resulted in the rapid closure of the #4 TCV, which caused the reactor scram on flow-biased high neutron flux.

Subsequently, PSEG conducted a RCE to determine the underlying cause of the issue. It was identified that the root cause involved broken or missing barriers in multiple processes.

Specifically, PSEG found that the troubleshooting process, evaluation tool, and operational decision- making tool were not appropriately followed when the OCC engaged the OEM vendor to discuss potential causes and solutions for the #4 TCV's unexpected movement, ultimately leading to the decision to close the #4 TCV by manually manipulating the FAS.

Regarding the troubleshooting process, inspectors reviewed PSEG procedure, MA-AA- 716-004, "Conduct of Troubleshooting," Section 4.2.3, which stipulates that a transition to complex troubleshooting from simple or focused troubleshooting should occur whenever equipment failures result in major degradation of safety-related or balance of plant equipment. The inspectors concluded that, given the significant degradation of the #4 TCV, evidenced by its unexpected full stroke open and continued mispositioning under the plant conditions at that time, the process should have transitioned to complex troubleshooting. This transition would have necessitated additional review, evaluations, and decision- making processes.

Following this event, PSEG reviewed their internal operating experience and found that the method used to manually actuate the FAS would not close the associated valve in a controlled manner. Specifically, the RCE 95- 065 evaluated a shutoff valve leak on the main steam turbine stop valve (MSV) #2. During the repair, a temporary FAS override bracket was installed on the MSV #2 FAS actuated and MSV #2 went fully closed immediately.

Documents related to the RCE were in the references for the procedure to isolate turbine valves, but applicable cautions and notes recommended in the RCE were not incorporated into the procedure.

Corrective Actions: PSEG's immediate corrective action was to replace the valve components, including the servo valve, the FAS valve, and the shutoff valve. Subsequently, PSEG completed a RCE to identify the cause and has taken or planned additional corrective actions to address it.

Corrective Action References: 70233173

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEGs failure to enter complex troubleshooting following unexpected movement of the #4 TCV as required by MA-AA- 716-004, Conduct of Troubleshooting, was a performance deficiency because it was within PSEGs ability to foresee and correct and should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, PSEG did not enter complex troubleshooting when the #4 TCV unexpectedly stroked open and remained mispositioned. As a result, PSEG did not properly evaluate the decision to close the #4 TCV by manually manipulating the FAS. The manual manipulation of the FAS caused the #4 TCV to rapidly go full closed, in turn causing the reactor to scram. Additionally, the inspectors referenced the NRC Inspection Manual Chapter 0612, Appendix E, Examples of Minor Issues, and determined that example 4.b was similar and informed the more than minor decision, because the procedural error resulted in a reactor scram.

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 1, Initiating Events Screening Questions, the inspectors determined that the finding was of very low safety significance, Green, because it caused a reactor scram but did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.

Cross-Cutting Aspect: H.11 - Challenge the Unknown: Individuals stop when faced with uncertain conditions. Risks are evaluated and managed before proceeding. Specifically, PSEG did not properly evaluate the risk of manually actuating the FAS to close the #4 TCV.

Enforcement:

Violation: 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

Quality procedure MA- AA-716- 004, Conduct of Troubleshooting, Section 4.2.3, states, in part, that complex troubleshooting should be entered at any time when there are equipment failures that result in major degradation of safety-related or balance of plant equipment.

Contrary to the above, on December 14, 2023, the licensee did not perform an activity affecting quality in accordance with the procedure. Specifically, PSEG did not enter the troubleshooting process as required byMA-AA- 716-004 when the #4 TCV went partially open nor when the #4 TCV subsequently went full open.

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

Observation: Inadvertent Closure of Turbine Control Valve Resulting in Unit 71152A Scram PSEG performed a RCE to evaluate why the repair plan for the #4 TCV EHC leak did not address FME and the plan to close the #4 TCV did not correctly predict the valve stroke time and plant response.

The inspectors reviewed the RCE 70233173, associated procedures, corrective action program documentation, and proposed and/or completed corrective actions implemented by PSEG due to the event. The inspectors noted that the licensee performed an evaluation of the event, extent of condition, and relevant operating experience.

The inspectors noted a weakness in the implementation of OP-AA-107, "Integrated Risk Management," throughout the event. Specifically, the FME requirements for the work were not reevaluated prior to recommencing work on the EHC pipe repair after the scope of the repair had changed and no risk evaluation was performed. Performing the risk evaluation would have provided PSEG an additional opportunity to recognize the need to implement greater FME controls prior to resuming work. Additionally, for deciding on how to close the #4 TCV, a high risk challenge meeting was performed; but the proposed method of closure was not evaluated by a formal process such as the Operation Technical Decision- Making Process, READE, or a Technical Evaluation.

The inspectors identified two performance deficiencies of very low safety significance, or Green, which are documented in this report.

Observation: Semi-Annual Trend Observations 71152S The inspectors performed a semi-annual review of site issues to identify trends that might indicate the existence of more significant safety concerns. As part of this review, the inspectors included repetitive or closely related issues documented by PSEG in their corrective action program database, trend reports, major equipment problem lists, system health reports, and maintenance or corrective action program backlog. The inspectors noted a negative trend in human performance behaviors related to procedure use and adherence.

In some cases, the procedures being followed were inadequate and were not questioned or challenged by station personnel. Examples of issues that inform this trend include:

  • Condensate water from the feedwater heaters was incorrectly drained into the condenser water boxes (NOTF 20961710, 20962541)
  • The 500kV bus section was energized without primary and backup protection (NOTF 20962246)
  • During startup from a refueling outage, the outboard main steam isolation valves before-seat drains were found open, resulting in a temperature rise in the reactor building equipment drain sump and causing the sump pumps to trip (NOTFs 20964932, 20964927, 20964928)
  • A relay jumper installed incorrectly during functional testing of the 10A402 ground relay resulted in blown fuses (NOTF 20963122)
  • Maintenance technicians missed a procedure step while performing HC.IC-CC.SB-0011 (NOTF 20964264)

PSEG evaluated each of these examples individually and completed Attachment 6, "Safety Human Performance Response Template," in accordance with the procedure OP-AA- 106-101- 1001, "Event Response Guidelines," and entered the appropriate corrective action processes to address each. PSEG is planning to perform a common cause evaluation (NOTF 20969853) to address this trend. The NRC inspectors did not identify any findings or violations of more than minor significance during this semi-annual trend review.

EXIT MEETINGS AND DEBRIEFS

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

  • On July 17, 2024, the inspectors presented the integrated inspection results to Robert DeNight, Site Vice President, and other members of the licensee staff.
  • On April 11, 2024, the inspectors presented the inservice inspection results to Robert DeNight, Vice President, and other members of the licensee staff.
  • On May 16, 2024, the inspectors presented the IP 71124.01 radiation hazards inspection results to Robert DeNight, Site Vice President, and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.08G Engineering 80134314 RWCU BHDL Elbow G502 FEA Report 0

Changes

Miscellaneous FAC Manager 1-BG-100-641-L1, FAC# G502 10/06/2022

Fitness for

Service Analysis

Results

SR-1700 Class 1 Stress Report 8

Work Orders 60128181 Bottom Head Drain Line Elbow Autumn

2016

18

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