IR 05000354/2021004

Integrated Inspection Report 05000354/2021004

ML22038A095
Person / Time
Site:	Hope Creek  (NPF-057)
Issue date:	02/07/2022
From:	Brice Bickett Division of Operating Reactors
To:	Carr E Public Service Enterprise Group
Bickett B
References
IR 2021004
Download: ML22038A095 (22)

Text

February 7, 2022

SUBJECT:

HOPE CREEK GENERATING STATION - INTEGRATED INSPECTION REPORT 05000354/2021004

Dear Mr. Carr:

On December 31, 2021, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station. On February 2, 2022, the NRC inspectors discussed the results of this inspection with Mr. Edward Casulli, Site Vice President and other members of your staff. The results of this inspection are documented in the enclosed report.

One finding of very low safety significance (Green) is documented in this report. This finding did not involve a violation of NRC requirements. Additionally, one Severity Level IV violation without an associated finding is documented in this report. 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:

05000354/2021004

Licensee:

PSEG Nuclear, LLC

Facility:

Hope Creek Generating Station

Location:

Hancock's Bridge, NJ

Inspection Dates:

October 1, 2021 to December 31, 2021

Inspectors:

D. Beacon, Resident Inspector

J. Brand, Reactor Inspector

A. Patel, Senior Reactor Inspector

J. Patel, Senior Resident Inspector

S. Wilson, Senior Health Physicist

Approved By:

Brice A. Bickett, Chief

Projects Branch 3

Division of Operating Reactor Safety

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

Inadequate Assessment and Documentation of Degraded Jacket Water Flange Impact to Emergency Diesel Generator Operability Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green FIN 05000354/2021004-01 Open/Closed

[P.2] -

Evaluation 71111.15 The inspectors identified a Green finding associated with PSEGs implementation of procedure OP-AA-108-115, Operability Determination, Revision 7, regarding the operability of the A emergency diesel generator (EDG). Specifically, on September 28, 2021, PSEG did not adequately implement its operability procedure to assess and document the capability of

'A' EDG to perform its safety function upon discovering jacket water (JW) leakage during a 24-hour surveillance test.

Safety Relief Valves As-Found Setpoint Failures Cornerstone Severity Cross-Cutting Aspect Report Section Not Applicable Severity Level IV NCV 05000354/2021004-02 Open/Closed Not Applicable 71153 A self-revealing Severity Level IV non-cited violation (NCV) of Technical Specification (TS)3.4.2.1 was identified after PSEG was notified that the as-found lift setpoint of two main steam safety relief valve (SRV) pilot stage assemblies had exceeded the lift setting allowable tolerance and one main (mechanical) stage failed to lift when tested. Specifically, A and J SRVs pilot stage assemblies exceeded the lift tolerance of +/-3 percent of the nominal setpoint value in TS 3.4.2.1, and R SRV main stage did not lift.

Additional Tracking Items

Type Issue Number Title Report Section Status LER 05000354/2021-001-00 LER 2021-001-00 for Hope Creek Generating Station,

Safety Relief Valve (SRV)

As-Found Setpoint Failures 71153 Closed

PLANT STATUS

The Hope Creek Generating Station (Hope Creek) began the inspection period at rated thermal power and operated at or near rated thermal power for the entire 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, conducted routine reviews using IP 71152, Problem Identification and Resolution, 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.

71111.01 - Adverse Weather Protection

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

(1) The inspectors evaluated the stations readiness for operating during winter seasonal conditions on December 22.

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) C station service water system with A station service water system out of service for planned maintenance on November 2

(2) Reactor core isolation cooling system on December 5

(3) Standby liquid control system on December 18

Complete Walkdown Sample (IP Section 03.02) (1 Sample)

The inspectors evaluated system configurations during a complete walkdown of the following systems/trains:

(1) High pressure coolant injection system on December 28

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) Torus room in pre-fire plan FP-HC-3415 on October 14

(2) Battery rooms in pre-fire plan FP-HC-3512 on October 18

(3) Service water intake structure in pre-fire plan FP-HC-3713 on November 17

(4) HVAC equipment rooms in pre-fire plan FP-HC-3571 on December 5

(5) Electrical access area in pre-fire plan FP-HC-3533 on December 17

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 on October 27.

71111.06 - Flood Protection Measures

Inspection Activities - Internal Flooding (IP Section 03.01) (2 Samples)

The inspectors evaluated internal flooding mitigation protections in the:

(1) Turbine building lower elevation following a condensate transfer system leak on October 27

(2) High pressure coolant injection system room on December 30

71111.11A - Licensed Operator Requalification Program and Licensed Operator Performance

Requalification Examination Results (IP Section 03.03) (1 Sample)

(1) The inspectors completed the review and evaluation of the licensed operator examination results for the requalification annual operating exam on November 19.

71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance

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

(1) The inspectors observed and evaluated a crew of licensed operators in the plants simulator during a licensed operator requalification examination on October 13.

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (3 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) A and C residual heat removal system jockey pump discharge check valve failed in-service test on October 14

(2) A emergency diesel generator following repetitive jacket water leaks on October 25

(3) Review of PSEGs periodic assessment to ensure the effectiveness of maintenance strategies on December 22

Quality Control (IP Section 03.02) (1 Sample)

The inspectors evaluated the effectiveness of maintenance and quality control activities to ensure the following SSC remains capable of performing its intended function:

(1)3-stage safety relief valves on October 25

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) Emergent work to perform a weld repair on reactor water cleanup system piping on October 13

(2) Planned inoperability of D service water system during maintenance window from November 15 through November 22

(3) Planned unavailability of the Red Lion 5015 offsite power line on December 6

(4) Planned inoperability of high pressure coolant injection system during quarterly in-service test on December 9

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) (4 Samples)

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

(1) A standby liquid control system squib valve loss of continuity on October 28

(2) B control rod drive system with clam shell supplemental coolers installed around piping on November 10

(3) A emergency diesel generator following jacket water leak during surveillance testing on November 23

(4) High pressure coolant injection system following evaluation of steam supply line movement during standby conditions on December 2

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) R safety relief valve acoustic monitor main control room overhead alarm relay bypass on November 8

Severe Accident Management Guidelines (SAMG) Update (IP Section 03.03) (1 Sample)

(1) The inspectors verified the site severe accident management guidelines were updated to incorporate the most recent revisions of the BWR owners group generic severe accident technical guidelines, and validated in accordance with NEI 14-01, Emergency Response Procedures and Guidelines for Beyond Design Basis Events and Severe Accidents, Revision 1, on December 1.

71111.19 - Post-Maintenance Testing

Post-Maintenance Test Sample (IP Section 03.01) (5 Samples)

The inspectors evaluated the following post-maintenance test activities to verify system operability and functionality:

(1) A and C residual heat removal system jockey pump discharge check valve replacement on October 14

(2) Reactor water cleanup following weld repairs of piping leaks on October 18

(3) B station service water system following repair of basket strainer rotating assembly supports on October 19

(4) D service water system following pump replacement on November 23

(5) F filter, recirculation, and ventilation system following instrumentation calibrations and filter check on December 15

71111.22 - Surveillance Testing

The inspectors evaluated the following surveillance tests:

Surveillance Tests (other) (IP Section 03.01)

(1) HC.OP-ST.SV-0006, A and C channel remote shutdown panel control and transfer operability on October 6

(2) HC.OP-ST.KJ-0016, 'C' emergency diesel generator 24-hour operability run and hot restart test on October 13

(3) HC.OP-IS.BD-0001, reactor core isolation cooling pump in-service test on November 22

71114.06 - Drill Evaluation

Drill/Training Evolution Observation (IP Section 03.02) (1 Sample)

The inspectors evaluated:

(1) The inspectors evaluated a simulator training evolution for licensed operators, with associated emergency preparedness drill and exercise performance criteria, on October

71124.02 - Occupational ALARA Planning and Controls

Verification of Dose Estimates and Exposure Tracking Systems (IP Section 03.02) (4 Samples)

The inspectors evaluated dose estimates and exposure tracking:

(1) Radiation work permit number 8; ALARA plan number 24; refuel floor activities during refuel outage number 23

(2) Radiation work permit number 10; ALARA plan number 26; maintenance support activities during refuel outage number 23

(3) Radiation work permit number 19; ALARA work in progress reports for multiple tasks during refuel outage number 23

(4) Radiation work permit number 3; ALARA work in progress reports for multiple tasks involving emergent work activities

71124.03 - In-Plant Airborne Radioactivity Control and Mitigation

Permanent Ventilation Systems (IP Section 03.01) (1 Sample)

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

(1) Control room emergency ventilation

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

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

(1) Refuel floor portable HEPA ventilation units for the equipment pit.

71124.04 - Occupational Dose Assessment

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

The inspectors evaluated the following special dosimetric situations:

(1) Declared pregnant worker dose evaluation - October 2020

(2) Declared pregnant worker dose evaluation - April

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification

The inspectors verified licensee performance indicators submittals listed below:

OR01: Occupational Exposure Control Effectiveness Sample (IP Section 02.15)===

(1) October 1, 2020 through September 30, 2021

PR01: Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences (RETS/ODCM) Radiological Effluent Occurrences Sample (IP Section 02.16) (1 Sample)

(1) October 1, 2020 through September 30, 2021

71152 - Problem Identification and Resolution (PI&R)

Semiannual Trend Review (IP Section 02.02) (1 Sample)

(1) The inspectors reviewed PSEGs corrective action program for potential adverse trends that might be indicative of a more significant safety issue on December 15

Annual Follow-up of Selected Issues (IP Section 02.03) (3 Samples)

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

(1) Corrective actions taken and planned in response to multiple control blade friction abnormalities observed during shutdown for refueling outage RF23 on November 2 (2)3-stage safety relief valve performance issues during Spring 2021

(3) Reactor manual control system transformer failures as documented in notifications

===20867903, 20856295, 20883882, and 20871450

71153 - Follow Up of Events and Notices of Enforcement Discretion

Event Report (IP Section 03.02)===

The inspectors evaluated the following licensee event reports (LERs):

(1) Licensee Event Report (LER) 05000354/2021-001-00, Safety Relief Valve (SRV) As-Found Setpoint Failures on December 22 (ADAMS Accession No.

ML21225A038). The inspection conclusions associated with this LER are documented in this report under Inspection Results.

INSPECTION RESULTS

Inadequate Assessment and Documentation of Degraded Jacket Water Flange Impact to Emergency Diesel Generator Operability Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems

Green FIN 05000354/2021004-01 Open/Closed

[P.2] -

Evaluation 71111.15 The inspectors identified a Green finding associated with PSEGs implementation of procedure OP-AA-108-115, Operability Determination, Revision 7, regarding the operability of the A emergency diesel generator (EDG). Specifically, on September 28, 2021, PSEG did not adequately implement its operability procedure to assess and document the capability of

'A' EDG to perform its safety function upon discovering jacket water (JW) leakage during a 24-hour surveillance test.

Description:

Hope Creek Generating Stations (HCGS) class 1E alternate current (AC) power system consists of four EDGs (A, B, C, and D), which serve as standby power supplies for the four safety-related 4.16 kV buses in the event of loss of both the normal and alternate power sources to the respective buses. The standby power supply for each 4.16 kV bus consists of one EDG complete with its auxiliaries, including the cooling water, starting air, lubrication, intake and exhaust, and fuel oil systems. The EDG cooling water system consists of two separate cooling loops: the jacket water cooling loop and the intercooler cooling loop.

The jacket water cooling loop circulates demineralized water with a corrosion inhibitor to cool the EDG cylinder jackets, turbocharger, and speed governor oil cooler. Water inventory is maintained within the established limits of the system by an expansion tank connected to the pump suction piping. Under normal plant operation, makeup water to the expansion tank is supplied through an auto makeup valve from the non-safety-related (NSR) demineralized water system. The HCGS updated final safety analysis report (UFSAR) states that the EDG cooling water system is designed to seismic category 1 requirements and remains functional during and after a safe shutdown earthquake (SSE). Additionally, it is designed to withstand wind, tornadoes, floods, and missiles and to permit testing and inspection of active system components during plant operation.

On September 28, 2021, approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> into the performance of an A EDG 24-hour endurance surveillance test (ST) in accordance with (IAW) the procedure HC.OP-ST.KJ-0014, EDG 1AG400 - 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Operability Run and Hot Restart Test, Revision 35, an equipment operator identified JW leaking at a rate of approximately 250 mL/min from the A EDG JW supply header flow orifice bolted flange connection near cylinder #12. The leakage reduced to approximately 110 mL/min as the test continued. Subsequently, after completing the 24-hour ST, PSEG declared the ST completed satisfactorily, removed the A EDG from service, and repaired the JW flow orifice flange. The inspectors reviewed this event to assess the operability of the EDG and PSEG's associated response to address the degraded condition.

PSEG performed an operability screening of the 'A' EDG degraded condition on September 28 in NOTF 20882155 and documented that 'A' EDG was operable. The basis for operability was documented in the NOTF and limited to a brief statement regarding the ability to implement a compensatory action to provide makeup water to the JW expansion tank in conditions where a leakage drains significant volume from the tank and challenges EDG to perform its safety function.

The inspectors noted, in 2004, under evaluation 70036674, PSEG established an acceptable JW leak rate criteria at 54 mL/min, at which an EDG would be expected to remain operable and able to fulfill its safety function. Surveillance test procedure HC.OP-ST.KJ-0014, step 3.2.13 described this EDG JW leak rate criteria for operability as less than 54 mL/min total leakage and referenced the 70036674 evaluation. During the 24-hour surveillance on September 28, 2021, PSEG also concurrently performed the A EDG monthly surveillance test procedure, HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test, Revision 82. Step 2.2.11 of this procedure stated, With a sustained EDG JW leak rate greater than 54 mL/min, additional makeup actions may be required, and the shift manager or control room supervisor should evaluate the need for potential compensatory actions to ensure Operability. The verbiage in these two concurrently performed surveillance test procedures conflicted and, PSEG staff informed inspectors that the station intended to apply the guidance in the monthly procedure (HC.OP-ST.KJ-0001) to all relevant procedures.

PSEG indicated the particular step was previously updated in all other EDG surveillance test procedures and HC.OP-ST.KJ-0014 was inadvertently missed during that update process.

The inspectors reviewed PSEG procedures OP-AA-108-115, "Operability Determination,"

Revision 7, and OP-AA-108-115-1002, "Supplemental Considerations for On-Shift Operability Determinations," Revision 2, to determine whether PSEG correctly implemented their operability determination process on September 28, 2021. The inspectors review also considered the leak's location and intensity (i.e., 250 mL/min). The inspectors determined that potentially, given the available information to operators at that time, the degraded condition substantially impacted 'A' EDG to perform its safety function, and a documented operability determination (DOD) would have been required in accordance with the procedure OP-AA-108-115.

The inspectors noted OP-AA-108-115, step 4.3.1 states that the DOD shall be documented in sufficient detail to allow individuals knowledgeable in a technical discipline associated with the condition to understand the basis for the determination. The DOD should consider all available information and may involve data gathering, consideration of plant and SSC conditions, and appropriate use of engineering judgment. The senior reactor operator (SRO)may request assistance from the site organization, as necessary, to provide input to the DOD.

Step 4.3.2.2 states that the SRO documents the basis for operability using the guidance in OP-AA-108-115-1002 and considers items from the procedure to be included in the DOD.

The inspectors determined that PSEGs DOD was not documented in sufficient detail to allow individuals knowledgeable in a technical discipline associated with the condition to understand and support the basis for the determination that the EDG was operable upon identifying the degraded condition. Specifically, the inspectors reviewed the guidance available in procedure OP-AA-108-115-1002, Attachment 1, and determined that the identified degraded condition involved some impact on the following items listed:

• Ability of the SSC to fulfill its safety function,

• Ability of the SSC to complete its function as described in the UFSAR,

• Consequential failure due to any postulated event (step 2.2.2 of OP-AA-108-115), and

• Leakage involving ASME Code component (JW piping and flanges are ASME Class 3)

The inspectors observed that the location and magnitude of the degraded condition introduced the potential for a flow diversion that could reduce cooling flow to the EDG turbocharger because the leak was located on the JW inlet to the EDG turbocharger. The inspectors identified that PSEG did not assess this potential flow diversion and determined that, even with manual makeup of inventory to the JW expansion tank, a flow diversion could have potentially challenged the EDG cooling water systems ability to perform its design function.

The inspectors also determined, as discussed in OP-AA-108-115, step 2.2.2, the operability determination should assess credible consequential failures that may result from any postulated event for which the deficient SSC needs to function. When, due to a deficient SSC condition, a postulated event would cause a consequential failure resulting in the loss of the capability to perform a specified safety function, the affected SSC is to be considered inoperable. The inspectors determined that the DOD should have addressed whether a

postulated seismic event would cause a failure of the flanged connection due to its degraded state and prevent the EDG from performing its specified safety or design functions.

Further, the inspectors found the documentation to be insufficient in detail for evaluating the acceptability and the feasibility of the compensatory action credited. The operability screening credited the availability of a manual compensatory action to provide makeup water to the JW expansion tank from the safety and turbine auxiliary cooling system using a flexible hose connection. However, there was not documented information to indicate operators required verification of the ability to implement the compensatory action given the degraded condition.

The inspectors noted that this manual compensatory action was proceduralized in the standard operating procedure for the EDG.

Based on the above, the inspectors concluded that PSEG did not adequately implement its operability procedure to assess and document the impact of the degraded condition on the 'A' EDG JW cooling system for 'A' EDG operability on September 28, 2021. The inspectors also concluded, in part, there was a reasonable doubt of operability initially when the leakage significantly exceeded PSEGs self-imposed criteria (54 mL/min) established in procedure HC.OP-ST.KJ-0014.

Corrective Actions: PSEGs immediate corrective action was to replace the degraded flange gasket following the completion of the 24-hour EDG surveillance test. On November 24, 2021, PSEG issued a standing order (2021-23, Revision 1) for operators to screen the three required entry criteria as Yes when JW leakage is discovered greater than 54 mL/min, which will require performing a DOD. The standing order also requires verification of the ability to implement the compensatory action (hose availability, connection availability, lube oil cooler safety and turbine auxiliary cooling system drain valve availability, and ensure no more than one diesel with elevated leakage). The surveillance test procedure steps that were conflicting are also being revised for clarity and consistency.

Corrective Action References: 20882155, 20885938

Performance Assessment:

Performance Deficiency: The inspectors determined that inadequate assessment and documentation of the degraded JW flange's impact on the operability of the 'A' EDG IAW OP-AA-108-115 was a performance deficiency that was reasonably within PSEGs 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. The issue was similar to Example 3.k of the IMC 0612, Appendix E, Examples of Minor Issues, because the condition resulted in reasonable doubt of the operability of the 'A' EDG and additional actions were necessary to support operability.

Specifically, the degraded JW flange connection resulted in leakage significantly exceeding PSEGs previously established acceptable leak rate for purposes of initially assessing operability. The degraded condition could have degraded further during a postulated seismic event resulting in a flow diversion and inadequate cooling water flow to the diesel turbocharger.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Exhibit 2, "Mitigating System Screening Questions," the inspectors determined that the degraded condition did not represent a loss of the PRA function for greater than TS allowed outage time. The inspectors reviewed the information provided by PSEG to determine whether the degraded condition challenged the inventory in the JW expansion tank and whether it affected the turbocharger cooling function. Based on the information reviewed, the inspectors determined the A EDG was able to satisfy its surveillance requirement, and therefore it demonstrated capability to perform its safety function. Thus, the finding was screened to Green.

Cross-Cutting Aspect: P.2 - Evaluation: The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Contrary to this, PSEG did not thoroughly evaluate the degraded JW flange and its impact on the A EDG operability.

Enforcement:

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

Observation: Semi-Annual Trend Review of PSEGs CAP 71152 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 list, system health reports, and maintenance or corrective action program backlog. The inspectors review was conducted to assess PSEGs ability to appropriately identify, evaluate, and resolve issues and potential trends. Some trends reviewed by the inspectors and identified by PSEG included:

• Record retention issues and/or gaps (NOTF 20880868)

• Operating experience reporting timeliness (NOTF 20886829)

• Degraded conditions on multiple hydraulic control units (NOTF 20887256)

PSEG evaluated each of these trends (and other lower significance trends not mentioned above) individually and entered the corrective action processes to address each. The inspectors reviewed documented evaluations and corrective actions and/or the plans established to complete evaluations and generate corrective actions (for the more recently identified issues).

The inspectors identified one minor performance deficiency related to this review.

Specifically, a completed record of procedure HC.OP-GP.ZZ-0003, Station preparation for seasonal conditions, Rev. 32, was required to be retained according to step 6.1 of the procedure. When the record was requested to support inspection activities, PSEG personnel indicated that no record could be located. PSEG entered this record retention issue in their corrective action program under NOTF 20888043. The inspectors verified that the actions required by the procedure were implemented, and the inspectors did not identify any significant adverse conditions resulting from the failure to retain the completed record.

Therefore, the inspectors determined this performance deficiency to be minor.

The inspectors did not identify any findings of more than minor significance as part of this semi-annual trend review.

Observation: Control rod blade elevated friction observed during shutdown for refueling outage RF23 71152 Inspectors reviewed corrective actions taken and planned in response to multiple control rod blades experiencing higher than normal friction during the shutdown for refueling outage RF23. Specifically, multiple rods were observed to be slow to insert, slow to settle, or required increased control rod drive pressure to be fully inserted. In response, PSEG evaluated the planned core configuration for fuel cycle 24 and adjusted it, as needed, to reduce the potential for further control blade friction issues in the subsequent fuel cycle. Additionally, the potentially affected components were quarantined and replaced prior to restarting.

Subsequently, PSEG initiated an apparent cause evaluation (70217682) to evaluate the potential cause(s) of the control blade friction issues. As part of this evaluation, the quarantined components are undergoing post-irradiation inspections. The inspectors reviewed both PSEG's immediate corrective actions as well as the long-term actions that were in progress. The inspectors did not identify any findings of more than minor significance associated with PSEG's actions taken in response to the observed control blade issues.

Observation: Annual Follow-up: Reactor Manual Control System Transformer Failures 71152 The inspectors evaluated PSEGs initial, interim, and long-term corrective actions and past operability related to the reactor manual control system transformer failures that occurred in the last three years. The issues were documented in PSEGs corrective action program as NOTFs 20867903, 20856295, 20883882, and 20871450. The inspectors reviewed the corrective actions taken, cause analysis, and the past operability evaluations. The inspectors assessed PSEGs problem identification threshold, prioritization of the issues, apparent cause analyses, use of operating experience, and timeliness of corrective actions. The sample was selected due to the potential impact of the reactor manual control system on an anticipated transient without scram event.

The inspectors assessed PSEGs evaluation of the issue, review of applicable operating experience, and corrective actions for adequacy and timeliness. The inspectors noted that long term corrective actions are still in progress and PSEG plans to take voltage and current readings on the transformers and determine any modifications that are required. PSEG has also implemented plans to replace capacitors periodically as part of the interim corrective actions.

The inspectors did not identify any findings of more than minor significance as part of this review.

Observation: Annual Follow-up: 3-stage SRV Performance issues during Spring 2021 71152 The inspectors reviewed PSEG's identification, evaluation, and resolution of problems that occurred in Spring 2021 involving leakage past three recently replaced SRVs. The inspectors considered whether PSEG evaluated these problems in accordance with their corrective action procedures with appropriate technical rigor to identify the likely causes and provide for effective corrective actions. The inspectors reviewed documents and interviewed engineering personnel to discuss the SRV performance problems that involved the following:

• On May 15, 2021, the 3-stage 'R' SRV showed indications of second stage leakage during plant startup (10 days) after its initial installation. PSEG replaced the entire

valve on May 26, 2021, during a non-SRV related plant shutdown (NOTF 20876854 and Apparent Cause Evaluation (ACE) 70218022).

• On June 26, 2021, the 3-stage 'A' SRV showed indications of a pilot stage leak, after about one month in service. PSEG staff shutdown the plant and replaced the valve pilot on June 27, 2021 (NOTF 20880274 and Root Cause Evaluation (RCE)70218550).

• On June 11, 2021, the 3-stage 'H' SRV showed indications of a pilot stage leak, less than a month after initial installation. PSEG shutdown the plant and replaced the pilot stage on July 22, 2021 (RCE 70218550).

As background, PSEG replaced all fourteen 2-stage SRVs with 3-stage design SRVs over refueling outages from 2018 to 2021 to address a setpoint drift problem with the previous 2-stage design. The 3-stage design has a main stage assembly, second stage assembly, and pilot stage assembly. The pilot stage is bolted to the second stage which is bolted to the main stage to provide a unitized, automatic, and manually controlled SRV. Indication of leakage is usually identified by changes in 2nd stage temperature or tail pipe temperature. The inspectors noted PSEG used two vendors to provide for the parts, assembly, and testing of the 3-stage SRVs. Assembly involved converting the existing 2-stage bodies to 3-stage bodies using the Top Works assembly consisting of the pilot and the second stage to the main valve body.

The inspectors determined that PSEG staff identified and evaluated the 'R' SRV second stage leakage problem by having it disassembled and examined at a vendor facility where PSEG determined that the disc seating surface was out of specification for total indicated runout (TIR) and observed uneven seat contact bandwidth. Testing data showed the valve was leaking each time when pressurized. PSEG staff concluded that the apparent cause of

'R' SRV second stage leakage was less than adequate manufacturing practices and processes resulting in this condition. Specifically, documentation that PSEG staff accepted did not include critical dimension measurements for second stage disc TIR and surface finish. PSEG staff identified contributing causes including not incorporating operating experience and industry best practices not being reflected in testing, acceptance criteria, and also less than adequate quality assurance oversight.

The inspectors determined that PSEG staff completed a RCE 70218550 for the 'A' and 'H' SRV pilot leakage problems. PSEG staff concluded these problems resulted from inadequate quality control during manufacturing that resulted in pilot disc contact seating widths being outside specified critical dimension criteria. Additionally, the 'A' SRV seat surface finish was more course than the specified surface finish requirement. PSEG staff identified contributing causes involving their overreliance on vendor quality assurance and control programs and not establishing sufficient barriers to verify all critical measurements were satisfied upon acceptance. PSEG staff completed corrective actions that involved replacement of 'A' and 'H' SRV pilot stages. They developed further corrective actions that included plans to review documentation of supplied components for adequacy including critical dimension control in addition to valve trueness and surface finish, adding PSEG witness hold points for key process steps, providing for PSEG quality assurance audit type activities with their vendors, and revising PSEG purchase requirements and records in this regard.

The inspectors concluded that PSEG identified SRV leak conditions, entered the problems into their corrective action process, and evaluated these problems to identify likely causes, and planned and implemented actions to address the likely causes. Regarding corrective action timing, the inspectors noted that 13 of the 14 currently installed SRVs were subject to

processes that did not consistently ensure pilot or second stage seat finish and trueness.

However, the inspectors noted PSEG plans to replace pilot and 2nd stage sections of these valves during the next refueling outage (RF24). Additionally, the inspectors noted that PSEG staff were monitoring SRV performance in accordance with their procedures. Furthermore, the inspectors considered PSEGs conclusions that the most likely impact of second stage leakage would be nuisance leakage or possibly valve opening issues. In regard to valve opening performance, PSEG determined that the as-left steam certification testing performed prior to shipment and installation of all of these valves did not show any valve opening issues. Specifically, each SRV was demonstrated acceptable by lifting a minimum of five times based on a single solenoid configuration, or six times with a dual solenoid configuration. The inspectors noted that PSEG determined that the operational risk associated with these SRVs, if dimensions are outside of tolerance, was considered low. The inspectors considered whether these test results in conjunction with online monitoring provided for planned corrective actions by PSEG were commensurate with the safety significance of potential seat trueness and finish problems in installed SRVs.

The inspectors did not identify any findings of more than minor significance.

Safety Relief Valves As-Found Setpoint Failures Cornerstone Severity Cross-Cutting Aspect Report Section Not Applicable Severity Level IV NCV 05000354/2021004-02 Open/Closed

Not Applicable 71153 A self-revealing Severity Level IV Non-Cited Violation (NCV) of Technical Specification (TS)3.4.2.1 was identified after PSEG was notified that the as-found lift setpoint of two main steam safety relief valve (SRV) pilot stage assemblies had exceeded the lift setting allowable tolerance and one main (mechanical) stage failed to lift when tested. Specifically, A and J SRVs pilot stage assemblies exceeded the lift tolerance of +/-3 percent of the nominal setpoint value in TS 3.4.2.1, and R SRV main stage did not lift.

Description:

During the H1R23 refueling outage at Hope Creek Generating Station (HCGS),seven 2-stage main steam SRV assemblies were removed and tested at NWS Technologies (NWS). On June 14, 2021, HCGS received results that the "as-found" setpoint tests of A and J SRVs pilot stage assemblies had exceeded the lift setting tolerance prescribed in TS 3.4.2.1, and R SRV main stage failed to lift. PSEG wrote NOTFs 20879139, 20879140, and 20879141 to document the as-found failures of those three SRVs. The TS requires the operability of at least 13 (of 14) SRVs at their specified code safety valve function lift settings of 1108 psig (4), 1120 psig (5), and 1130 psig

(5) with an allowable tolerance of +/-3 percent.

'A' SRV (F013A) and 'J' SRV (F013J) pilot stage assemblies set pressure tests were outside their required setpoint tolerances. The 'A' SRV with a nominal setpoint of 1130 psig was tested to lift at 1167 psig (3.27 percent higher), and the 'J' SRV has a nominal setpoint of 1120 psig was tested to lift at 1161 psig (3.66 percent higher). 'R' SRV (F013R) main stage assembly (serial number 357) did not lift, though the pilot stage tested satisfactorily within the allowable tolerance. PSEG determined that these three SRVs were inoperable during cycle 23. As a result, PSEG reported this condition as this is a condition prohibited by plant TS under 10 CFR 50.73(a)(2)(i)(B) to the NRC as Licensee Event Report 05000354/2021-001-00 on August 13, 2021.

PSEG concluded that the cause of the A and J SRVs setpoint drift was attributed to corrosion bonding between the pilot disc and seating surfaces. The SRV corrosion bonding

issue was previously reported to the NRC by PSEG (LER 2019-002-00, LER 2018-002-01, LER 2016-003-01) and several other licensees. As reviewed and documented in NRC Integrated Inspection Report 05000354/2020001, PSEG has worked with the Boiling Water Reactor Owners Group (BWROG) in evaluating 2-stage SRV setpoint drift issues (ADAMS Accession No. ML18267A016, ML19239A280, ML19323E051). As a result, PSEG has taken several actions, including changing the platinum coating application process for the pilot valve disc for the 2-stage SRVs. In addition, during the Spring 2018 refueling outage, PSEG started a phased implementation plan to replace 2-stage SRVs with a modified 3-stage SRV design.

In May 2021, during the H1R23 refueling outage, PSEG completed this phase implementation plan by replacing the remaining seven 2-stage SRVs with a modified 3-stage design.

PSEG concluded that the cause of the R SRV main stage failing to lift was the main disc and piston thread wear, resulting in side-loading of the main piston within the guide. It allowed slight grooves to form in the guide where the piston and rings could bind. The inspectors reviewed maintenance history associated with the R SRV main stage assembly to determine if PSEG was performing required testing and maintenance prior to its failure. In April 2011, NWS refurbished SRV main stage serial number 357 and tested it satisfactorily. Following refurbishment, pilot stage serial number 343 was mounted on main stage 357, and the valve assembly was certified in May 2011. The valve assembly was shipped to PSEG and was installed in the R SRV location during the H1R17 refueling outage in April 2012. Main stage 357 was installed for three cycles from April 2012 to October 2016. The pilot stage associated with main stage 357 was removed each refueling outage in situ, and a new pilot was installed on main stage 357. During H1R20 in October 2016, the main stage assembly from the R location was removed for testing at NWS and was recertified and reinstalled in the same location during that refueling outage. There was no refurbishment performed during this interval. The main stage 357 remained installed in the plant from October 2016 through May 2021, when removed for testing and was discovered to be failed.

SRV main stage assembly testing is governed by TS Surveillance Requirement 4.4.2.3. The surveillance requires that the SRV main stage assemblies shall be pressure tested, reinstalled, or replaced as per frequency established by the surveillance frequency control program (SFCP) LS-HC-1000-1001, Hope Creek Generating Station Surveillance Frequency Control Program List of Surveillance Frequencies. The SFCP refers to the American Society of Mechanical Engineers (ASME) Operational and Maintenance of Nuclear Power Plant (OM)code for the SRV main stage. The SRV main stage assembly testing frequency is either every five years per ASME OM Code, Appendix 1, Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants, or six years per ASME OM Code Case OMN-17, Alternative Rules for Testing ASME Class 1 Pressure Relief/Safety Valves.

The difference is that Appendix 1 requires just testing, whereas OMN-17 requires disassembly due to additional time allowed in service. On September 6, 2019, the NRC approved PSEG's request to use the ASME OM Code Case OMN-17, which allowed an alternate maintenance strategy for the SRVs. The frequency extended from five years to six years, provided valves were disassembled and inspected each time. The inspectors determined that the OMN-17 requirements would not have been applied for the 'R' SRV until it had been disassembled and tested, which would have occurred in May 2021. Prior to 2021, PSEG met the ASME OM Code Appendix 1 requirement to test every five years.

In LER 2021-001-00, PSEG concluded the safety significance was very low because the safety function of the SRVs was not compromised. TS 3.4.2.1 requires the safety function of only 13 of 14 SRVs to be operable. There were no instances during operating cycle 23 that

resulted in any of the 14 SRVs being declared inoperable. There were no events during that cycle that required the operation of the SRVs. For the A and J SRV pilot stage setpoint drifts due to corrosion bonding, it was demonstrated during the test that once the SRVs lifted, the corrosion bond broke, and subsequent opening occurred near the setpoint within the allowable tolerance. Technical evaluation (70218327-0010 and 70218327-0015) performed by PSEG determined the as-found condition of the SRVs would have satisfactorily performed the intended safety function under postulated accident conditions, including dynamic loading to connected piping. Concerning the R SRV failure to lift, PSEG considered R SRV inoperable since installed during H1R20 in October 2016. PSEG reviewed the additional SRVs that were inoperable in cycles 21 and 22 due to setpoint drift from corrosion bonding and determined that ASME overpressure protection and core thermal limits would not have been exceeded. The inspectors reviewed this and determined that it supported PSEGs conclusion. The inspectors did not identify any performance deficiencies during the conduct of this review.

Corrective Actions: During the H1R23 refueling outage, PSEG completed the SRV phased replacement plan for installing modified 3-stage SRVs, bringing all of 14 SRVs installed in the plant to a modified 3-stage design. Additionally, PSEG has adopted the ASME Code Case OMN-17, requiring PSEG to disassemble, inspect, and test each SRVs every six years.

Corrective Action References: 20879139, 20829140, 20879141, 20882865

Performance Assessment:

The NRC determined this violation was not reasonably foreseeable and preventable by the licensee and therefore is not a performance deficiency.

Enforcement:

The ROPs significance determination process does not specifically consider a violation without a finding in its assessment of licensee performance. Therefore, it is necessary to address this violation using traditional enforcement to adequately deter non-compliance.

Severity: This issue is assigned a Severity Level IV violation based on its similarity to example 6.1.d.1 in the Enforcement Policy. The inspectors also reviewed the NRC Enforcement Policy, Section 2.2.1, Factors Affecting Assessment of Violations, which states, in part, that in determining the appropriate enforcement response to a violation, the NRC considers, whenever possible, risk information in assessing the safety or security significance of violations and assigning severity levels. The inspectors determined the issue to be of very low safety significance because the safety function of the SRVs was not compromised. As a result, the inspectors determined that the violation is appropriately characterized at Severity Level IV.

Violation: TS 3.4.2.1 requires the safety valve function of at least 13 of the 14 SRVs to be operable with specified lift setting tolerance of +/-3 percent. Contrary to this requirement, on June 14, 2021, SRV lift setpoint testing revealed that two SRVs had as-found setpoints in excess of the TS allowable tolerance and one SRV failed to lift; and those SRVs were assumed to have been inoperable at some point during the respective operating cycles.

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 October 8, 2021, the inspectors presented the 3-stage safety relief valve performance issues inspection results to Mr. Gary Stith, Component Engineering Manager and other members of the licensee staff.

• On November 18, 2021, the inspectors presented the RP Rad Hazard; ALARA; In-Plant Airborne; Dose Assessment, and Performance Indicator Inspection results to Mr. Edward Casulli, Site Vice President and other members of the licensee staff.

• On February 2, 2022, the inspectors presented the integrated inspection results to Mr. Edward Casulli, Site Vice President and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71152

Corrective Action

Documents

20856295

20867903

20871450

20873169

20876854

20880274

20881213

20881346

20881347

20883882

Corrective Action

Documents

Resulting from

Inspection

20886027

Miscellaneous

20880599/70218550 RCE, 'A' and 'H' SRV Pilot Valve Leakage

218534

Failure Analysis Report-Hope Creek Target Rock 3-Stage

SRV, Model 0867F Pilot 311 (NWS Traveler 21-267),

7/15/2021

ACE 70218022

'R' SRV 2nd Stage Leakage Upon Start from 1R23

Work Orders

214168