IR 05000354/2024003

Integrated Inspection Report 05000354/2024003

ML24297A057
Person / Time
Site:	Hope Creek
Issue date:	10/23/2024
From:	Brice Bickett NRC/RGN-I/DORS
To:	Mcfeaters C Public Service Enterprise Group
References
IR 2024003
Download: ML24297A057 (1)

Text

October 23, 2024

SUBJECT:

HOPE CREEK GENERATING STATION - INTEGRATED INSPECTION REPORT 05000354/2024003

Dear Charles McFeaters:

On September 30, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station. On October 22, 2024, the NRC inspectors discussed the results of this inspection with Robert McLaughlin, Plant Manager, and other members of your staff. The results of this inspection are documented in the enclosed report.

Two findings of very low safety significance (Green) are documented in this report. One of these findings involved a violation of NRC requirements. We are treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation or the significance or severity of the violation 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: 05000354/2024003

Enterprise Identifier: I-2024-003- 0036

Licensee: PSEG Nuclear, LLC - N09

Facility: Hope Creek Generating Station

Location: Hancocks Bridge, NJ

Inspection Dates: July 01, 2024 to September 30, 2024

Inspectors: P. Finney, Senior Resident Inspector J. Bresson, Resident Inspector J. Kulp, Senior Reactor Inspector R. Rolph, Senior Health Physicist

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

Inappropriate Application of Technical Specifications (TS)

Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.1] - 71111.11Q Systems FIN 05000354/2024003- 01 Resources Open/Closed Inspectors identified a Green finding of PSEGs procedure OP-HC-108-115, "Operability Assessment and Equipment Control Program," Revision 3, when licensed operators did not enter the appropriate TS limiting condition for operation (LCO) action statements during a lockout of the C 4 kilovolt (kV) bus.

Inadequate Procedure Use Results in Residual Heat Removal (RHR) Pump Start and Low Pressure Coolant Injection (LPCI) Valve Opening Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.14] - 71111.24 Systems NCV 05000354/2024003-02 Conservative Open/Closed Bias A self-revealed Green finding and associated non-cited violation (NCV) of TS 6.8.1,

"Procedures and Programs," was identified when PSEG technicians improperly implemented an RHR Division 3 injection valve permissive channel calibration procedure.

Additional Tracking Items

None.

PLANT STATUS

Hope Creek Unit 1 began the inspection period at rated thermal power.

On September 13, 2024, the unit was reduced to 70 percent to troubleshoot 'B' north waterbox condenser tube leakage. The unit was returned to 100 precent on September 15, 2024. On September 17, 2024, Unit 1 was reduced to 82 percent to troubleshoot and repair turbine control valve #2 and was returned to 100 percent on September 18, 2024. On October 3, 2024, Unit 1 was reduced to 81 percent to troubleshoot 'A' south waterbox condenser tube leakage.

The unit was returned to rated thermal power the following day 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.

71111.04 - Equipment Alignment

Partial Walkdown Sample (IP Section 03.01) (3 Samples)

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

(1) Station service water Division II during 'C' station service water maintenance, August 5, 2024

(2) 'A' standby liquid control during 'B' standby liquid control maintenance, September 10, 2024

(3) 'A' RHR train following heat exchanger outlet valve maintenance, September 30, 2024

71111.05 - Fire Protection

Fire Area Walkdown and Inspection Sample (IP Section 03.01) (5 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) Emergency diesel generator (EDG) rooms during 'C' EDG maintenance, pre-fire plan 3531, July 9, 2024

(2) High pressure coolant injection and reactor core isolation cooling rooms, pre-fire plans 3412 and 3413, during reactor core isolation cooling planned inoperability, August 20, 2024

(3) Control equipment mezzanine area, pre-fire plan 3542, September 3, 2024

(4) Control, equipment, heating ventilation and cooling, inverter and battery rooms, pre-fire plan 3562, September 5, 2024

(5) Turbine generator exciter areas using Nine Mile Point exciter breaker fire operating experience, pre-fire plans 3131 and 3151, September 24, 2024

Fire Brigade Drill Performance Sample (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated the onsite fire brigade training and performance during an unannounced fire drill in non-1E DC switchgear, pre -fire plan 3513, on August 26, 2024.

71111.06 - Flood Protection Measures

Flooding Sample (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated internal flooding mitigation protections when the reactor building sump overflowed and was impaired with the adjacent 'D' core spray protected on July 8, 2024.

71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance

Licensed Operator Performance in the Actual Plant/Main Control Room (IP Section 03.01) (2 Samples)

(1) The inspectors observed and evaluated licensed operator performance in the main control room during the unplanned loss of 'C' 4kV vital bus on August 9, 2024.

(2) The inspectors observed and evaluated licensed operator performance in the main control room during power ascension and reduction with #2 turbine control valve inoperable and under-instruction watches on September 17, 2024.

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (2 Samples)

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

(1) 'C' main steam line elevated radiation readings, July 22, 2024

(2) 4kV system following loss of the 'C' 4kV bus, August 15, 2024

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management Sample (IP Section 03.01) (4 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 'A' RHR suction breaker inspections, July 31, 2024

(2) Emergent risk during loss of multiple balance of plant bezel indications, August 6, 2024

(3) Planned and emergent risk during 'A' EDG work and subsequent inoperability for a lube oil pressure trip, August 27, 2024

(4) Emergent risk during 'A' EDG hot restart loss of field flash, August 29, 2024

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) (3 Samples)

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

(1) 'C' RHR LPCI discharge valve opening during testing, July 24, 2024

(2) Operability of various components upon loss of 'C' 4kV bus, August 14, 2024

(3) Division 3 core spray normal and emergency time delay relays, September 9, 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) Permanent modification of TS implementation procedure, HC-OP-108-115, September 12, 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) (9 Samples)

(1) 'C' RHR injection valve permissive testing following inadvertent opening, July 10, 2024

(2) 'C' EDG work window to include failure of manual voltage regulator and field current indication during retest, July 15, 2024

(3) 'C' station service water pump following cable determination for planned maintenance, August 8, 2024

(4) 'A' EDG hot restart after fuel rack positioner replacement and trip on low lube oil pressure, August 29, 2024

(5) 'B' standby liquid control following 36-month squib valve maintenance, September 11, 2024 (6) #2 turbine control valve following fast-acting solenoid, fuse replacement, and wiring repair, September 18, 2024

(7) Safety auxiliary cooling system heat exchanger A1 outlet valve following diagnostic testing, September 25, 2024

(8) Division 3 core spray following normal power relay replacement, September 26, 2024

(9) 'C' station service water intake structure ventilation following failure from moisture in the cabinet, September 26, 2024

Surveillance Testing (IP Section 03.01) (1 Sample)

(1) 'C' RHR pump surveillance, September 4, 2024

Inservice Testing (IST) (IP Section 03.01) (1 Sample)

(1) Reactor core isolation cooling pump inservice test, August 22, 2024

Reactor Coolant System Leakage Detection Testing (IP Section 03.01) (1 Sample)

(1) Shutdown cooling suction header reactor coolant system leakage, July 29, 2024

71114.06 - Drill Evaluation

Required Emergency Preparedness Drill (1 Sample)

(1) The inspectors evaluated the conduct of a routine PSEG emergency preparedness drill, H24-01, on August 13,

71124.03 - In-Plant Airborne Radioactivity Control and Mitigation

Permanent Ventilation Systems (IP Section 03.01) (2 Samples)

The inspectors evaluated the configuration of the following permanently installed ventilation systems:

(1) North plant vent

(2) South plant vent

Temporary Ventilation Systems (IP Section 03.02) (1 Sample)

The inspectors evaluated the configuration of the following temporary ventilation systems:

(1) Decontamination room, high-efficiency particulate air ventilation unit

Use of Respiratory Protection Devices (IP Section 03.03) (1 Sample)

(1) The inspectors evaluated the licensees use of respiratory protection devices.

Self-Contained Breathing Apparatus for Emergency Use (IP Section 03.04) (1 Sample)

(1) The inspectors evaluated the licensees use and maintenance of self-contained breathing apparatuses.

71124.04 - Occupational Dose Assessment

Source Term Characterization (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated licensee performance as it pertains to radioactive source term characterization.

External Dosimetry (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated how the licensee processes, stores, and uses external dosimetry.

Internal Dosimetry (IP Section 03.03) (2 Samples)

The inspectors evaluated the following internal dose assessments:

(1) Internal dose assessment for ID#22-012, March 11, 2023

(2) Internal dose assessment for ID#14-591, April 7, 2024

Special Dosimetric Situations (IP Section 03.04) (2 Samples)

The inspectors evaluated the following special dosimetric situations:

(1) A declared pregnant worker, January 1, 2022 to August 31, 2022

(2) A declared pregnant worker, July 10, 2023 to December 31,

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification

The inspectors verified licensee performance indicators submittals listed below:

MS07: High Pressure Injection Systems (IP Section 02.06)===

(1) July 1, 2023 through June 30, 2024

MS08: Heat Removal Systems (IP Section 02.07) (1 Sample)

(1) July 1, 2023 through June 30, 2024

MS09: Residual Heat Removal Systems (IP Section 02.08) (1 Sample)

(1) July 1, 2023 through June 30, 2024

MS10: Cooling Water Support Systems (IP Section 02.09) (1 Sample)

(1) July 1, 2023 through June 30, 2024

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

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

(1) The inspector reviewed the licensee's Equipment Reliability Evaluation (ERE)

===70231633 and corrective actions associated with the 'B' EDG not achieving 110 percent of rated load during surveillance testing on September 13, 2023.

71153 - Follow-Up of Events and Notices of Enforcement Discretion

Event Follow-Up (IP Section 03.01)===

(1) The inspectors evaluated the unplanned loss of the 'C' 4kV vital bus on August 9,

INSPECTION RESULTS

Inappropriate Application of Technical Specifications (TS)

Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H. 1 ] - 71111.11Q Systems FIN 05000354/2024003- 01 Resources Open/Closed Inspectors identified a Green finding of PSEGs procedure OP-HC-108 -115, "Operability Assessment and Equipment Control Program," Revision 3, when licensed operators did not enter the appropriate TS limiting condition for operation (LCO) action statements during a lockout of the C 4 kilovolt (kV) bus.

Description:

At 00:33 on August 09, 2024, during a nine -year preventive maintenance calibration of a 'C' 4kV vital bus voltage transducer, Hope Creek experienced an unplanned loss of the bus on a neutral overcurrent and associated bus lockout signal. An inspector responded to this event and observed plant and operator response. During their response, licensed operators entered TS 3.8.3.1, "Onsite Power Distribution Systems," LCO action 3.8.3.1.a to re-energize the channel in eight hours or be in hot shutdown in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

The associated batteries discharged to maintain vital instrument bus power. At 05:17, Operations recovered the bus and exited the LCO.

After the event, inspectors questioned why the station had not entered LCOs for TS 3.8.1.1, "A.C. Sources - Operating," and TS 3.8.2.1, "D.C. Sources - Operating." Regarding TS LCO 3.8.1.1 the 'C' 4kV vital bus lockout signal prevented the 'C' EDG from closing its output breaker to power the 4kV bus. The LCO action 3.8.1.1.b for an inoperable EDG requires completion of Surveillance Requirement 4.8.1.1.1.a within an hour and every eight hours after that. While not entering the action statement, operators had still completed the surveillance requiremen t by direction of the Assistant Operations Manager. Regarding TS LCO 3.8.2.1, the associated TS requires five 'C' channel electrical power sources that includes three full capacity chargers to be operable. In this event, the battery chargers lacked AC power given the upstream 4kV bus loss. Without inclusion of these LCOs, PSEG had not entered the most time-limited LCO action 3.8.2.1.a with two hours to restore the 'C' channel to operable status or be in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after that.

Hope Creek TS 1.28 defines OPERABILITY of a system, subsystem, train, component or device when it is capable of performing its specified function(s) and when all necessary attendant instrumentation, controls, electrical power, cooling and seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s). Given this structure of the OPERABILITY definition, the condition of a support system can impact the OPERABILITY of a supported TS component. This is informally referred to as "cascading" TSs because the result of a support system LCO not being met can "cascade" to result in LCOs for supported systems or components also not being met. Given the requirements in the Hope Creek applicability LCOs 3.0.1 through 3.0.5, PSEG may be required to enter ACTION requirements in multiple TSs because of a single support system being inoperable.

PSEG's response to NRC questioning on applicable TSs during the C 4kV vital bus event was that they did not need to cascade TSs and referenced their TS implementing procedure, OP-HC-108-115 and its Attachment 8, Tech Spec Implementation, that states, for conditions when a support or supported system is declared inoperable in one train, that if the redundant train is not operable to take the required actions in accordance with Technical Specifications for both trains inoperable. Inspectors recognized that not cascading TSs is permitted when a licensee has an LCO similar to LCO 3.0.6 found in NRC standard TSs for a General Electric Boiling Water Reactor. Inspectors reviewed Hope Creek TSs and noted that an LCO equivalent to LCO 3.0.6 does not currently exist in PSEGs license, and therefore, could not be used. Inspectors identified that while the Attachment 8 wording had been incorporated into their procedure since 1998, it was not similar to LCO 3.0.6 but had over time been organizationally interpreted and trained upon as an equivalent to an LCO 3.0.6.

OP-HC-108-115, Step 4.3.1 directs Operations that "any time it is determined that a Tech Spec LCO/Tech Spec Implementation is or will be INOPERABLE either due to a deficiency identified in a notification, a planned activity, or following a plant transient, the appropriate Action Statement is entered. Contrary to this, inspectors determined that PSEG had not entered the appropriate LCOs for the lockout of the C 4kV bus.

Corrective Actions: PSEG entered this issue in their corrective action program as Notifications 20974838, 20975066, and 20975113. In May 2024, PSEG applied for conversion of their current TSs to Improved TSs that includes LCO 3.0.6 (NUREG-1433, Revision 5) via a license amendment (ADAMS ML24142A407).

Corrective Action References: 20974838, 20975066, and 20975113.

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEGs improper implementation of the procedure OP-HC-108-115 requirement to enter the appropriate LCOs was reasonably within PSEGs ability to foresee and correct, should have been prevented, and was therefore a performance deficiency.

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. Further, the deficiency was associated with the Human 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, licensed operators not entering all impacted and appropriate LCOs resulted in less restrictive operating conditions and could result in the station operating in a condition prohibited by the TSs, which is part of the operating license.

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 used Appendix A, Exhibit 2, and determined the finding to be of very low safety significance, Green, because it was not associated with system design or qualification, was not a single train system loss, was not a loss of a multi-train system for a time greater than allowed by TSs, was not the loss of two separate TS systems or a probabilistic risk assessment system/function for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, or the loss of one or more non-TS trains for greater than three days.

Cross-Cutting Aspect: H.1 - Resources: Leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, licensed operators had incorrectly interpreted procedural TS implementation guidance as allowing them to not cascade TSs.

Enforcement:

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

Inadequate Procedure Use Results in Residual Heat Removal (RHR) Pump Start and Low Pressure Coolant Injection (LPCI) Valve Opening Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.14] - 71111.24 Systems NCV 05000354/2024003 - 02 Conservative Open/Closed Bias A self-revealed Green finding and associated non-cited violation (NCV) of TS 6.8.1, "Procedures and Programs," was identified when PSEG technicians improperly implemented an RHR Division 3 injection valve permissive channel calibration procedure.

Description:

On July 10, 2024, instrument and control technicians were performing HC.IC -

CC.BC- 0003, RHR - Division 3 Channel E11-N658C Reactor Pressure - Injection Valve F017C Permissive (LPCI Mode), Revision 13, to test and calibrate the C RHR injection valve pressure permissive channel. The LPCI injection valve has a high pressure/low pressure interlock to prevent pressurization of the low pressure piping upstream of the valve.

This procedure uses an Emergency Core Cooling System (ECCS) Logic Tester that is configured during test setup. A procedural note before Step 4.1.4 states The following steps are performed to prevent the inadvertent opening of injection valve F017C during a high pressure condition. The note continues The A - B and B-C contacts on the ECCS Logic Tester(s) should be verified with a DMM (digital multimeter) to be in the proper position prior to installation. Step 4.1.4 says to VERIFY A - B and B-C switch es/jumpers AND INTERLOCK switch/jumper on an ECCS Logic Tester are in NORM.

While the technicians checked the Logic Tester contacts in all configurations in the shop with a digital multimeter, they altered the configuration in the field and did not verif y the proper position prior to installation as the note intended. The proper Logic Tester configuration for NORM in Step 4.1.4 was to have the jacks removed for switches A -B and B-C and installed for the interlock. In this case, jacks were installed in all three connections.

At 9:02 a.m., when technicians performed Step 4.1.5 to connect the Logic Tester to the test jack, the C RHR pump inadvertently started in minimum flow having received a logic start signal. The instrument and control technicians then stopped the surveillance. At 10:45 a.m.,

while performing Step 4.10.9 to disconnect the ECCS Logic Tester, the RHR LPCI C loop initiated, RHR loop C trouble alarms came in, and the C LPCI injection valve began to open. Operators responded by pressing the auto-open override button and attempted to close the valve at which point the valve's 480V breaker tripped on overcurrent while the valve was in a dual position indication further complicating the human performance event. Operations staff entered TS LCOs 3.5.1.b.1 and 3.6.3 for LPCI injection valve inoperability.

In response to the event, PSEG staff conducted a prompt investigation, a human performance review board, and reported this to the NRC via a telephonic notification for an invalid actuation of a system in accordance with 10 CFR 50.73(a)(2)(iv)(A) (Event Notification#57302). The inspectors reviewed PSEGs prompt investigation and noted this was a first-time Logic Tester evolution for one technician and the first time leading a Logic Tester evolution for the other technician. Further, the instrument and control chief technician who conducted the pre-job brief had never performed this work. Inspectors independently verified the RHR pump and injection valve responses were as expected for the conditions with a focus on PSEG actions between the pump start and the valve opening. The inspectors determined that had the technicians removed the A-B and B-C jacks prior to removal of the Logic Tester, the LPCI valve operation could have been avoided.

Corrective Actions: PSEG used a troubleshooting plan to close the LPCI breaker and valve, turned the RHR pump off, and returned RHR to its normal standby condition. PSEG also conducted remedial training for the responsible staff and completed a stand down with remaining maintenance crews. PSEG subsequently completed the surveillance on August 6, 2024.

Corrective Action References: 20970064 and 20970340.

Performance Assessment:

Performance Deficiency: The inspectors determined that failure to properly implement surveillance procedure HC.IC-CC.BC- 0003 was reasonably within PSEGs ability to foresee and correct, should have been prevented, and was therefore a performance deficiency.

Specifically, instrument and control technicians failed to ensure that the Logic Tester was in the appropriate configuration as required by HC.IC-CC.BC- 0003.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Human 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. The inspectors also reviewed IMC 0612, Appendix E, and noted that this issue was similar to examples 3.c, 3.e, and 4.c, and resulted in an inadvertent start of an RHR pump and LPCI discharge valve inoperability.

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 used Appendix A, Exhibit 2, and determined the finding to be of very low safety significance, Green, because it did not affect RHR design or qualification and was not a loss of one RHR train for greater than its TS allowed outage time or exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Cross-Cutting Aspect: H.14 - Conservative Bias: Individuals use decision making-practices that emphasize prudent choices over those that are simply allowable. A proposed action is determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, PSEG technicians adjusted the Logic Tester configuration in the field thereby altering its condition without confirmatory testing and then removed the Logic Tester without fully understanding potential consequences when the conditions were unusual. Additionally, Operations personnel did not understand the LPCI valve's open signal was a potential undesired test consequence.

Enforcement:

Violation: TS 6.8.1 requires, in part, that written procedures shall be implemented covering the activities in Regulatory Guide 1.33, Revision 2, Appendix A, and surveillance and test activities of safety-related equipment. Regulatory Guide 1.33, Appendix A, 4.h, includes procedures for the operation of ECCSs. Contrary to this, on July 10, 2024, PSEG technicians improperly implemented surveillance procedure HC.IC-CC.BC- 0003 which consequently resulted in the advertent start of an RHR pump and inoperability of a LPCI injection valve.

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

Observation: Equipment Reliability Evaluation (ERE): 'B' EDG Did Not Achieve 71152A 110 Percent Load During TS Surveillance Test The inspectors reviewed PSEGs ERE 70231633 regarding the causes of 'B' EDG not meeting TS loading criteria during the endurance run surveillance test performed on September 14, 2023. PSEGs ERE documented the direct cause resulted from wear material induced binding between tight tolerance metal to metal contact points in the governor actuator. The wear material was generated when a sheared roll pin allowed internal components of the governor actuator to become slightly misaligned, which increased component wear. This conclusion was supported by the results of a failure analysis performed by their vendor in the last quarter of 2023.

PSEG staff determined the roll pin was most likely damaged during a dynamic overspeed test on February 15, 2020, when operators had trouble raising EDG speed to test the overspeed trip mechanism. It appeared to operators that the EDG speed did not respond to turning of the speed control knob and the speed knob was rotated past its stop position which damaged the roll pin. PSEG performed troubleshooting and, in consultation with their vendor, adjusted the speed stops based upon industry operating experience with speed stop adjusting screw looseness that allowed speed stops to move. PSEG operators successfully completed the dynamic overspeed test following the adjustment of the speed stops and PSEG took corrective actions to address this issue.

PSEGs ERE further determined that in January 2021, during the performance of the monthly operability test, operators noted that the speed reference indicator did not perform in a repeatable manner when verifying speed stop values and that the speed control knob was loose. The issue was entered into the corrective action program and PSEG staff consulted with their vendor who indicated that this was likely due to a subcomponent in the governor actuator (this was later found to be a damaged roll pin in 2023). The vendor considered this affected the speed indicator and not the governor performance which was accepted by PSEG staff. PSEGs vendor recommended that the governor actuator be replaced at the next scheduled EDG maintenance window. However, PSEGs ERE found governor actuator replacement was delayed several times until the problem occurred on September 14, 2023.

As a result of their ERE, PSEG staff implemented corrective actions to revise work control procedures to require a risk assessment when corrective action program work is rescheduled, revising work control procedures to retain work deletion requests for trending and periodically reviewing rescheduled activities during the Plant Health Committee meetings.

The inspectors reviewed PSEGs operability and reportability conclusions in corrective action program documents which concluded there was no firm evidence to indicate that the failure occurred prior to the test on September 14, 2023, and therefore, was not reportable. PSEG staff also considered that the 'B' EDG demonstrated capability to carry its design basis loading during all tests since 2020.

The inspectors reviewed the failure analysis and found the conclusion of the wear induced binding was consistent with the evidence but not substantive to constitute firm evidence. The inspectors considered that the 'B' EDG demonstrated capability to carry design loads since the problem was introduced in 2020 and that the scope of corrective actions prioritized and risk-informed governor maintenance decisions. The inspectors did not identify any performance deficiencies of a more than minor significance.

EXIT MEETINGS AND DEBRIEFS

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

• On October 22, 2024, the inspectors presented the integrated inspection results to Robert McLaughlin, Plant Manager, and other members of the licensee staff.

• On July 10, 2024, the inspectors presented the 71124.03 airborne radioactivity control and mitigation and 71124.04 occupational dose assessment inspection results to Robert McLaughlin, Plant Manager, and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.04 Corrective Action 20972465*

Documents 20972941*

Resulting from 20974627*

Inspection 20974626*

20974376*

20974831*

20974832*

20974728*

20976971*

20977401*

20977402*

71111.05 Corrective Action 20973991

Documents 20974460

Corrective Action 20969967*

Documents 20971032*

Resulting from 20973747*

Inspection 20974460*

20974467*

20974468*

20973991*

20974709*

20975094*

71111.13 Corrective Action 20969966*

Documents 20974226*

Resulting from 20973800*

Inspection 20974381*

71111.15 Corrective Action 20971546*

Documents 20972725*

Resulting from 20973450*

Inspection 20973222*

20974557*

20975139*

Inspection Type Designation Description or Title Revision or

Procedure Date

20975201*

71111.18 Corrective Action 20970329*

Documents 20974838*

Resulting from 20975066*

Inspection 20975113*

71111.24 Corrective Action 20968423*

Documents 20971288*

Resulting from 20971289*

Inspection 20972966*

20972695*

20973374*

20973434*

20974023*

20974234*

20971949*

20971948*

20974279*

20974553*

20974569*

20975532*

71114.06 Corrective Action 20973360*

Documents 20973820*

Resulting from

Inspection

71152A Corrective Action 20971163*

Documents 20971195*

Resulting from 20972670*

Inspection 20974928*

20973332*

20973554*

20973571*

20975302*

20973503*

20974525*

Inspection Type Designation Description or Title Revision or

Procedure Date

20974648*

20974727*

20974653*

20975787*

20975178*

20975192*

20975193*

20977332*

Engineering 70221547 Work Group Evaluation: B EDG Failed to Reach Max Load 06/15/2022

Evaluations 70231633 Equipment Reliability Evaluation: B EDG Not Going to 110 06/24/2024

Percent Load

HSE230096 Failure Analysis of Woodward EGB-50P Actuator 12/08/2023

16