IR 05000272/2023001

Integrated Inspection Report 05000272/2023001 and 05000311/2023001

ML23122A217
Person / Time
Site:	Salem
Issue date:	05/03/2023
From:	Brice Bickett NRC/RGN-I/DORS
To:	Carr E Public Service Enterprise Group
References
IR 2023001
Download: ML23122A217 (1)

Text

May 3, 2023

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2 - INTEGRATED INSPECTION REPORT 05000272/2023001 AND 05000311/2023001

Dear Eric Carr:

On March 31, 2023, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Salem Nuclear Generating Station, Units 1 and 2. On April 20, 2023, the NRC inspectors discussed the results of this inspection with Dave Sharbaugh, Site Vice President, 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. 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, D.C. 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Resident Inspector at Salem Nuclear Generating Station, Units 1 and 2.

If you disagree with a cross-cutting aspect assignment 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, D.C. 20555-0001; with copies to the Regional Administrator, Region I; and the NRC Resident Inspector at Salem Nuclear Generating Station, Units 1 and 2. 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 (CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, Digitally signed by Brice Brice A. A. Bickett Date: 2023.05.03 Bickett 08:34:49 -04'00'

Brice A. Bickett, Chief Projects Branch 3 Division of Operating Reactor Safety Docket Nos. 05000272 and 05000311 License Nos. DPR-70 and DPR-75

Enclosure:

As stated

Inspection Report

Docket Numbers: 05000272 and 05000311 License Numbers: DPR-70 and DPR-75 Report Numbers: 05000272/2023001 and 05000311/2023001 Enterprise Identifier: I-2023-001-0039 Licensee: PSEG Nuclear, LLC Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: Hancocks Bridge, NJ Inspection Dates: January 1, 2023 to March 31, 2023 Inspectors: J. Dolecki, Senior Resident Inspector P. Cataldo, Senior Reactor Inspector N. Floyd, Senior Reactor Inspector E. Garcia, Resident Inspector N. Mentzer, 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 Salem Nuclear Generating Station, Units and 2, 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 Establish Measures to Prevent Freezing of Steam Generator Pressure Sensing Lines Results in Safety Injection Actuation and Reactor Trip Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.11] - 71152A NCV 05000311/2023001-01 Challenge the Open/Closed Unknown A self-revealing, very low safety significance (Green) finding and associated non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified when PSEG staff failed to correct a condition adverse to quality (CAQ). Inspectors determined PSEG did not establish measures to ensure failures of the 22 and 24 steam generator (SG)pressure sensing lines in cold weather conditions was corrected. As a result, Unit 2 tripped on December 24, 2022, because of a safety injection (SI) actuation due to inaccurate SG pressure indications.

Structural Monitoring Procedures Not Enhanced in Accordance with License Renewal Commitment Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.1] - 71152A Systems NCV 05000272,05000311/2023001-02 Resources Open/Closed The inspectors identified a Green finding and associated NCV of Salem Unit 1 License Condition 2.C.19, and Salem Unit 2 License Condition 2.C.35. These license conditions state, in part, that the license renewal safety evaluation report and updated final safety analysis report (UFSAR) supplement, describe certain future programs and activities to be completed before the period of extended operation, and that PSEG Nuclear LLC shall complete these activities no later than August 13, 2016, for Salem Unit 1, and April 18, 2020, for Salem Unit 2.

The inspectors determined the Salem UFSAR, Appendix B, Section A.2.1.33, describes enhancements to be made to the Salem structures monitoring program (SMP) under Commitment No. 33, which states that the existing program and associated implementing procedures are to be enhanced to include additional acceptance criteria details specified in American Concrete Institute (ACI) 349.3R-96. In review of monitoring reports completed in 2020 related to the Salem Unit 1 Auxiliary Building, 64-foot elevation walls, the inspectors found that Salem SMP inspection procedure and associated checklist, ER-AA-310-101 and Form F.1, which is used for monitoring safety-related structures, had not been enhanced to include additional acceptance criteria details specified in ACI 349.3R-96.

Additional Tracking Items

Type Issue Number Title Report Section Status LER 05000311/22-001-00 LER 22-001-00 for Salem 71153 Closed Generating Station, Unit 2,

Invalid Safety Injection and Valid Reactor Trip Due to Inaccurate Steam Generator Pressure Indications

PLANT STATUS

Unit 1 began the inspection period at rated thermal power and remained at or near rated thermal power for the remainder of the inspection period.

Unit 2 began the inspection period at rated thermal power. On February 28, 2023, Unit 2 commenced coastdown in preparation for the planned refueling outage 26 (S2R26) to start on April 1, 2023. Unit 2 was at approximately 17 percent rated thermal power at the end 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.

71111.01 - Adverse Weather Protection

Impending Severe Weather (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated readiness for impending adverse weather for cold weather alert and high wind conditions February 3 through 4, 2023

71111.04 - Equipment Alignment

Partial Walkdown (IP Section 03.01) (2 Samples)

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

(1) Unit 2, 22 auxiliary feedwater during 21 auxiliary feedwater work window, on January 4, 2023

(2) Unit 1, 11 component cooling following returning system to service, on January 5, 2023

71111.05 - Fire Protection

Fire Area Walkdown and Inspection (IP Section 03.01) (3 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) Unit 1, auxiliary building ventilation elevation 122, FP-SA-1562, on January 18, 2023

(2) Unit 1, auxiliary building volume control and boric acid tank elevation 122, FP-SA-1563, on January 18, 2023

(3) Unit 1 auxiliary building elevation 45 and 55', 11 residual heat removal pump room, 1FA-AB-45A, on March 7, 2023

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 Unit 1 and 2 operations personnel during surveillance activities on March 7, 2023, and during the pre-refueling outage downpower on March 31, 2023.

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

(1) The inspectors observed a Unit 2 simulator evaluation that included a fire near the 23 charging pump, reactor coolant pump vibrations, and a SG tube leak, on January 31, 2023.

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management (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) Unit 2, elevated risk during scheduled activity on component cooling valve 2CC16, on January 12, 2023 (work order (WO) 30315266)

(2) Units 1 and 2, risk assessment and management action for the interim abandonment of Unit 3 gas turbine, on February 23, 2023

(3) Unit 1, elevated risk during scheduled activity on 12 residual heat removal pump suction valve, on March 7, 2023

(4) Unit 1, emergent work on 'B' train of solid-state protection system due to multiple alarms in channel III input bay, during week of March 29, 2023 (notification (NOTF)

===20930916 / WO 60156300)

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) ===

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

(1) Unit 2, 21 SG due to suspected degraded upper lateral support seismic strut, on January 4, 2023 corrective action program (NOTF 20925195 / operable with engineering justification (OEJ) 70227453-0020)

(2) Unit 2, containment spray valve CS14 due to failure to stroke closed during post-maintenance test, on January 10, 2023 (NOTF 20925571)

(3) Unit 1, radiation monitoring instrumentation due to noble gas effluent monitor, 1R41D, erratic performance and rework, on January 13, 2023 (NOTF 20925607)

(4) Units 1 and 2, review of functional assessment and associated corrective actions resulting from interim abandonment of Unit 3 gas turbine, on February 1, 2023

(5) Unit 2, 25 containment fan coil unit due to fail to start in low speed, on February 15, 2023 (NOTF 20927637)

(6) Unit 2, 22 SI pump due to 'C' phase time overcurrent relay not functioning as expected, on February 22, 2023 (OEJ 70227841-0010)

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 permanent modifications:

(1) Engineering Change Package 80124612, replacement of 12 kVA analog inverter to 15 kVA digital inverter for '2C' 115 VAC vital instrument bus power supply

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)

(1) Unit 2, 22 residual heat removal system following pre-outage inspection to air-operator valves 2RH20 and 22RH18, on March 8, 2023 (WOs 30361641 and

===30360678)

(2) Unit 1, 12 chiller following repair to address system tripping on low superheat, on March 20, 2023 (NOTF 20930454)

Surveillance Testing (IP Section 03.01) ===

(1) Unit 2, S2.OP-ST.AF-0004 Inservice Testing - Auxiliary Feedwater Valves, on January 25, 2023 (WO 50239380)

(2) Unit 2, S2.OP-ST.CBV-0003, Containment Systems - Cooling Systems, on February 17, 2023 (WO 50241086)

(3) Unit 2, S2.OP-ST.DG-0012 2A Diesel Generator Endurance Run, on

February 28, 2023 (WO 50230466) Inservice Testing (IST) (IP Section 03.01) (1 Sample)

(1) Unit 2, S2.OP-ST.DG-0005, 22 Fuel Oil Transfer System Operability Test, on January 25 through 26, 2023 (WOs 50239263 and 60155939)

71114.06 - Drill Evaluation

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

The inspectors evaluated:

(1) The inspectors evaluated the conduct of a routine drill involving a simulated fire in the auxiliary building, loss of coolant accident inside containment, and failure of containment vent to close, resulting in a general emergency declaration, on March 8,

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification The inspectors verified licensee performance indicators submittals listed below:

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

(1) Unit 1, January 1, 2022 through December 31, 2022

(2) Unit 2, January 1, 2022 through December 31, 2022

BI01: Reactor Coolant System (RCS) Specific Activity (IP Section 02.10) (2 Samples)

(1) Unit 1, January 1, 2022 through December 31, 2022

(2) Unit 2, January 1, 2022 through December 31, 2022

BI02: RCS Leak Rate (IP Section 02.11) (2 Samples)

(1) Unit 1, January 1, 2022 through December 31, 2022

(2) Unit 2, January 1, 2022 through December 31, 2022

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

(1) Review of work group evaluation 70227453-0010 and associated licensee activities for suspected missing collar and shim pack on 21 SG upper lateral support compression strut

(2) Review of aging management for below grade wall degradation due to groundwater intrusion

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) LER 05000311/2022-001-00, Invalid Safety Injection and Valid Reactor Trip Due to Inaccurate Steam Generator Pressure Indications (Agencywide Documents Access and Management System (ADAMS) Accession No. ML23052A211). The inspection conclusions associated with this LER are documented in this report under the Inspection Results Section. This LER is Closed.

INSPECTION RESULTS

Failure to Establish Measures to Prevent Freezing of Steam Generator Pressure Sensing Lines Results in Safety Injection Actuation and Reactor Trip Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.11] - 71152A NCV 05000311/2023001-01 Challenge the Open/Closed Unknown A self-revealing, very low safety significance (Green) finding and associated non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified when PSEG staff failed to correct a condition adverse to quality (CAQ). Inspectors determined PSEG did not establish measures to ensure failures of the 22 and 24 steam generator (SG) pressure sensing lines in cold weather conditions was corrected. As a result, Unit 2 tripped on December 24, 2022, because of a safety injection (SI) actuation due to inaccurate SG pressure indications.

Description:

The engineered safety feature (ESF) systems are provided in nuclear power plants to mitigate the consequences of reactor plant accidents. ESF systems are actuated when the logic of the SI signals are met, such as when pressure instrumentation senses a main steam line break. Multiple pressure sensing lines per SG are located on the main steam lines to input to the SI logic and when that logic is met, an SI signal will actuate ESF systems.

Specifically, when a particular SG (i.e., 24 SG) pressure measures at least 100 psi lower than at least two of the other three SGs (i.e., 21, 22, and 23) then SI actuates to start ESF systems and mitigate the consequence of a steam line break.

PSEG entered SC.OP-AB.ZZ-0001, Adverse Environmental Conditions, on December 23, 2022, at 7:00 a.m., due to the local area being under a cold weather advisory and the associated entry condition of air temperatures below 32 degF. On December 23, 2022, at 11:35 p.m., the 22 SG pressure indication (2PT525) failed high and alarmed in the control room. Operators responded in accordance with the alarm response procedure, determined it to be a suspected instrument failure of an unknown cause, and concurrently pursued technical specification actions to trip the associated bistable. On December 24, 2022, at 1:44 a.m., the 24 SG pressure indication (2PT546) failed high and alarmed in the control room. At this time, there were two separate 1-out-of-3 SI coincidence logic schemes met, which does not result in an SI signal. Following receipt of the second alarm, field operators identified ventilation dampers had failed open in the area that housed the 22 and 24 SG pressure sensing lines. Operators closed these dampers and started room heaters to address the suspected SG pressure sensing line failures. On December 24, 2022, at 2:22 a.m., the 24 SG pressure indication (2PT546) thawed and indicated an inaccurate low pressure. With 2PT525 reading high and 2PT546 reading low, differential pressures across two steam line loops gave inaccurate readings of a steam line break, resulting in an SI actuation, starting ESF systems, and an associated reactor trip. The inaccurate SG steam pressure indications were caused by both the localized freezing and the subsequent thawing of the SG pressure sensing lines because the dampers failed open and permitted cold air to blow directly onto the uninsulated and unheated safety-related SG pressure sensing lines.

PSEG postulated the cause of the dampers failing open was due to a combination of higher sustained winds with drastic wind changes leading up to the time of the event causing the damper to open and the relatively weak spring-return on the dampers being unable to pull the associated dampers closed. Following the event, PSEG notified the NRC with 4 and 8-hour reports in accordance with 10 CFR 50.72 (event report 56286) and submitted a LER on February 21, 2023, in accordance with 10 CFR 50.73 (LER 2022-001-00).

The inspectors reviewed the event and associated PSEG staff actions surrounding the event.

The 22 and 24 SG pressure sensing lines are installed in the outer penetration area which is vulnerable to adverse weather conditions because of adjacent ventilation dampers which, when open, direct air flow at the sensing lines. PSEG identified this vulnerability in a previous root cause evaluation (RCE) 70029296 and within their winter readiness procedures.

Inspectors reviewed SC.OP-AB.ZZ-0001, which provides directions, in part, to ensure the safety-related procedure SC.OP-PT.ZZ-0002, Station Preparations for Seasonal Conditions, had been completed for the current season. Inspectors noted that PSEG performed SC.OP-PT.ZZ-0002 in accordance with WO 30363195 and declared winter readiness complete on November 1, 2022. In WO 30363195, PSEG staff documented satisfactory manipulation of the spring-loaded dampers. The inspectors identified the procedure includes a note and a required sign-off to acknowledge that proper spring-loaded damper operation is needed to prevent freezing of the sensing lines. However, the inspectors noted that the procedure does not provide details on what the satisfactory operation of the dampers entails. Also, in the same area as the dampers, inspectors identified that three of the four room space heaters are directed at the SG pressure sensing lines and PSEG staff had documented them all as unsatisfactory because they had been disabled with their breakers opened and tagged out.

The inspectors noted WO 30363195 listed the four corrective action program NOTFs that previously identified this condition. Inspectors determined these NOTFs had no actions to address these deficiencies at the time of the event.

The inspectors reviewed PSEG staffs previous RCE 70029296 where it was determined inadequate winter readiness preparations had resulted, in part, in SG pressure sensing lines freezing. PSEG categorized that inadequate winter readiness as a significant CAQ and the freezing SG pressure sensing lines as a CAQ. One of the corrective actions was to implement a design change to prevent freezing of the SG pressure sensing lines and inaccurate SG pressure indications. Inspectors identified that the initial RCE corrective action was to install heat tracing to provide backup to the installed area heaters, but the corrective action was later changed to insulate the SG pressure sensing lines. Within the RCE, PSEG noted that the Unit 1 area had installed insulation for the SG pressure sensing lines since 1979 but, Unit 2 did not have installed insulation. PSEG staff determined the corrective action to insulate the Unit 2 SG pressure sensing lines was closed on December 15, 2005 (WO 60049281) but was not implemented or maintained prior to the reactor trip on December 24, 2022.

In summary, the inspectors determined that from January 2003 until December 24, 2022 PSEG staff had not established measures to ensure a CAQ, failure of the SG pressure sensing lines in cold weather conditions, was corrected. Inspectors determined that it was the combination of uninsulated sensing lines and disabled room heaters nearby that led to the invalid SG pressure indications after the dampers failed open, which resulted in the SI actuation and reactor trip. Inspectors determined PSEG staff failed to identify and correct the deficient equipment design of the safety-related SG pressure sensing lines located in an area previously identified to be vulnerable to temperature changes.

Corrective Actions: Immediately following the SI actuation and reactor trip, operators placed Unit 2 in a safe shutdown condition. PSEG staff thawed the remaining SG pressure sensing lines. Prior to starting up Unit 2, the dampers were secured closed, additional monitoring of the area was implemented, and functional testing of the SG pressure sensing lines was performed satisfactorily. PSEG staff entered the issue into the corrective action program and completed an RCE (70227130). Also, since the event, PSEG staff has insulated the SG pressure sensing lines.

Corrective Action References: 20925047 and 70227130

Performance Assessment:

Performance Deficiency: Inspectors determined PSEGs failure to correct a CAQ as required by 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, as implemented by LS-AA-125, Corrective Action Program, Sections 4.5 and 4.6, was a performance deficiency because it was within their ability to foresee and correct and should have been prevented.

Specifically, after an event in 2003 that demonstrated the pressure sensing lines in the outer penetration area were susceptible to cold weather, inspectors determined PSEG did not establish measures to ensure failures of the 22 and 24 SG pressure sensing lines in cold weather conditions was corrected.

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, PSEG staff's failure to implement corrective actions to maintain and provide reliable SG pressure indications resulted in an SI actuation and automatic Unit 2 trip. This more than minor performance deficiency is similar to IMC 0612, Appendix E example 5.b because the failure to implement corrective actions resulted in an SI signal and reactor trip.

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 and determined the finding caused a reactor trip but did not result in the loss of mitigation equipment relied upon to transition the plant form the onset of the trip to a stable shutdown condition. Therefore, the inspectors determined the finding to be of very low safety significance (Green).

Cross-Cutting Aspect: H.11 - Challenge the Unknown: Individuals stop when faced with uncertain conditions. Risks are evaluated and managed before proceeding. The inspectors determined PSEG staff did not maintain a questioning attitude and communicate unexpected conditions during job-site reviews to identify and resolve unexpected conditions. Inspectors also determined that although the performance deficiency occurred more than three years ago the performance characteristics have not been corrected or eliminated. PSEG staff performs winter readiness each year and an abnormal operating procedure is entered when specific cold weather conditions are met, such as during the event on December 24, 2022, to review for and address vulnerabilities to adverse weather conditions. Inspectors identified WO 30363195 included notes highlighting the vulnerability of the SG pressure sensing lines to freezing and had identified the outer penetration heaters to be unsatisfactory and disabled but PSEG staff did not take actions to resolve the condition. Inspectors had also challenged the stations conclusion that winter readiness was complete in early December 2022 based, in part, that these heaters were marked as unsatisfactory.

Enforcement:

Violation: 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected.

Contrary to the above, from January 23, 2003 to December 24, 2022, PSEG staff failed to identify and correct a CAQ. Specifically, PSEG staff did not ensure the increased likelihood of failure/malfunction of the 22 and 24 SG pressure sensing lines in cold weather conditions was corrected. As a result, Unit 2 tripped on December 24, 2022, because of a SI actuation due to inaccurate SG pressure indication.

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

Structural Monitoring Procedures Not Enhanced in Accordance with License Renewal Commitment Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.1] - 71152A Systems NCV 05000272,05000311/2023001-02 Resources Open/Closed The inspectors identified a Green finding and associated NCV of Salem Unit 1 License Condition 2.C.19, and Salem Unit 2 License Condition 2.C.35. These license conditions state, in part, that the license renewal safety evaluation report and updated final safety analysis report (UFSAR) supplement, describe certain future programs and activities to be completed before the period of extended operation, and that PSEG Nuclear LLC shall complete these activities no later than August 13, 2016, for Salem Unit 1, and April 18, 2020, for Salem Unit

2. The inspectors determined the Salem UFSAR, Appendix B, Section A.2.1.33, describes

enhancements to be made to the Salem structures monitoring program (SMP) under Commitment No. 33, which states that the existing program and associated implementing procedures are to be enhanced to include additional acceptance criteria details specified in American Concrete Institute (ACI) 349.3R-96. In review of monitoring reports completed in 2020 related to the Salem Unit 1 Auxiliary Building, 64-foot elevation walls, the inspectors found that Salem SMP inspection procedure and associated checklist, ER-AA-310-101 and Form F.1, which is used for monitoring safety-related structures, had not been enhanced to include additional acceptance criteria details specified in ACI 349.3R-96.

Description:

The inspectors completed a problem identification and resolution annual sample inspection related to the licensees performance to address indications of potential degradation mechanisms active in the Salem Units 1 and 2 auxiliary building below grade walls. The inspector observed cracks, efflorescence, staining, and other conditions associated with groundwater in-leakage regarding exterior walls. The groundwater in-leakage was more prominent at Salem Unit 1, as evidenced by observed collections of water/wetness at some locations on the floor.

The inspectors reviewed SMP reports completed in 2020, with a focus on the 64-foot elevation of the auxiliary buildings. On a sampling basis, the inspectors found that monitoring was completed per the implementing procedure and checklists and at the required periodicity. The inspectors observed that SMP implementing procedure ER-AA-310-101 used a framework involving the responsible engineer assigning concrete surface condition assessments of increasing significance from Category A through D, with Level D directing that an evaluation be completed for assessment of significance. The inspectors noted this procedure had not been enhanced with the ACI 349.3R-96 qualitative and quantitative Tier I and II evaluation criteria as described in license renewal Commitment No. 33, Enhancement No. 14, which states, in part, that the existing program and associated implementing procedures are to be enhanced to include additional acceptance criteria details specified in ACI 349.3R-96.

In particular, the inspectors reviewed a checklist completed on February 18, 2020, and determined an area of degradation was assigned a Level B condition in Concrete Examination Checklist, AUX-64-1, Sheet 15 of 20, EL64 / Rooms 15301, 15302, and 15303.

The inspectors noted that if this procedure had been enhanced with the ACI 349.3R-96 criteria, a recorded crack width size (0.040 inches) would have exceeded Tier II criteria and the wall would have been subject to more detailed, documented evaluation. As a result, this detailed evaluation consistent with the enhanced criteria in ACI 349.3R was not performed, as the procedure was not enhanced as committed to by PSEG. The inspectors noted the SMP procedure addressed other safety-related structures, as well as additional elevations of the Units 1 and 2 auxiliary buildings, and that monitoring activities did not include implementation of the enhanced acceptance criteria and associated evaluations for these other structures, since the Salem units entered their periods of extended operation.

Corrective Actions: Salem staff entered the issues into their corrective action program for assessment and resolution.

Corrective Action References: NOTFs 20920419, 20929697, 20929897, and 20930059

Performance Assessment:

Performance Deficiency: The performance deficiency associated with this finding was the failure to implement the use of the Tier I and Tier II acceptance criteria from ACI 349.3R-96, in structural monitoring activities associated with the Salem Units 1 and 2 auxiliary building below grade walls.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Procedure Quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the reliability of safety-related concrete structures is intended to be assured through incorporation of an enhancement to the structures monitoring inspection procedures and implemented during the periodic inspections, as committed to during the license renewal process. The inspectors determined that indications of degradation in the Units 1 and 2 auxiliary buildings, 64-foot elevation, were accepted without further evaluation, which would have been required had the enhanced criteria had been implemented.

Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that because there is no indication the performance deficiencies resulted in the actual loss of function of a seismic concrete structure for greater than 14 days, the issue was determined to be Green.

Cross-Cutting Aspect: H.1 - Resources: Leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. The inspectors identified the licensee did not ensure the SMP implementing procedures were revised to contain appropriate, qualitative acceptance criteria consistent with ACI 349.3R-96, as required by the license renewal commitments. This is representative of current licensee performance because the SMP procedures were utilized during the most recent, periodic SMP inspections conducted in 2020.

Enforcement:

Violation: Unit 1 License Condition 2.C.19, and Unit 2 License Condition 2.C.35, both state, in part, that the license renewal safety evaluation report and UFSAR supplement, describe certain future programs and activities to be completed before the period of extended operation, and that PSEG Nuclear LLC shall complete these activities no later than August 13, 2016, for Salem Unit 1, and April 18, 2020, for Salem Unit 2. UFSAR Supplement contains Commitment No. 33, Structures Monitoring Program, as detailed in LRA Section A.21.1.33(14), which required, in part, that the existing program and associated implementing procedures will be enhanced to include additional acceptance criteria details specified in ACI 349.3R-96, prior to period of extended operation.

Contrary to the above, in March 2023, the NRC identified that these activities have not been completed. Specifically, that baseline structures monitoring inspections conducted in 2015, as well as the first, periodic structures monitoring inspections conducted during the period of extended operation, were performed with structures monitoring implementing procedures and associated concrete inspection checklists that did not include the required Tier I and Tier II quantitative inspection criteria, as well as the associated follow-up qualitative evaluation criteria consistent with Sections 5.1, 5.2, and 5.3 of ACI 349.3R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures.

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

Observation: Licensee Did Not Enter Risk-Informed Decision-Making Process for 71152A Suspected Degraded Condition Affecting Seismic Qualification Inspectors reviewed PSEGs identification, evaluation, and initiated corrective actions associated with a suspected degraded upper lateral support (ULS) compression strut on the Unit 2, 21 SG. Inspectors reviewed PSEGs actions and evaluations to ensure they were commensurate with the safety significance, with a focus on their operability determination and risk-informed decision-making.

On January 4, 2023, PSEG identified a suspected missing collar and shim pack on one of the two ULS struts that support seismic qualification for the 21 SG. PSEG declared the supported system, structure, or components operable using an initial operability determination but engaged engineering staff for additional technical input via their OEJ process. The OEJ (70227453-0020) was approved on February 9, 2023. Inspectors challenged the reasonable assurance of operability because, in part, PSEG had documented an assumption that the other ULS strut was installed; that the expected faulted loading from a design basis earthquake would exceed the load rating; and that PSEG had qualitatively concluded that refined, future evaluations could likely show faulted loading would not exceed the load rating (i.e., conservatism would be removed with a revised evaluation). Based on the inspectors questions, PSEG revised the OEJ and included a more quantitative basis that concluded the faulted load rating would not be exceeded. Inspectors determined this revised OEJ on February 22, 2023, demonstrated the 21 steam generator had reasonable assurance of operability.

Inspectors also reviewed Salem procedure OP-AA-106-101-1006, Operational and Technical Decision Making (OTDM) Process, for application to the identified suspected degraded ULS strut and associated OEJ. This OTDM procedure provides a method for evaluating operational and technical decisions that affect plant operations, safety, reliability, and material condition. Inspectors noted that PSEG did not enter the OTDM process following the identification of the suspected degraded ULS strut or throughout their decision-making process.

The inspectors determined this issue was of minor significance because a revision to 70227453-0020 demonstrated the design margin was restored and when the ULSs were inspected during the scheduled refueling outage, it was identified that all compression struts were intact. PSEG generated NOTF 20929878. This inspection did not result in the identification of a performance deficiency or violation of more than minor significance.

Observation: Review of Licensee Event Report 2022-001-00, Salem Generating 71153 Station, Unit 2, Invalid Safety Injection and Valid Reactor Trip Due to Inaccurate Steam Generator Pressure Indications While the inspectors had full availability of inspection and event information throughout our review, inspectors determined the LER lacked details consistent with guidance in NUREG-1022. The summary section of NUREG-1022, Event Report Guidelines 10 CFR 50.72 and 50.73, Revision 3, describes the importance of providing operating experience within LERs and other reports. NRC staff uses the information reported under 10 CFR 50.72 and 10 CFR 50.73 in responding to emergencies, monitoring ongoing events, confirming licensing bases, studying potentially generic safety problems, assessing trends and patterns of operational experience, monitoring performance, identifying precursors of more significant events, and providing operational experience to the industry. Section 5.2.2, states, in part, to explain exactly what happened during the entire event or condition, including how systems, components, and operating personnel performed and to describe the event from the perspective of the operator (i.e., what the operator saw, did, perceived, understood, or misunderstood). Based on a review of the event, inspectors determined the LER lacked detail regarding plant response and operator actions. Specifically, the LER did not include the operators actions in the field in response to the freezing SG pressure sensing lines and how the actions of thawing the lines resulted in the SI actuation and reactor trip. Without inclusion of the details regarding sensing line thawing, an independent reader cannot conclude how the SI occurred.

This observation did not result in the identification of a performance deficiency or violation of more than minor significance. The circumstances surrounding this LER, including an NCV, are documented in the Inspection Results Section 71152A of this inspection report. This disposition closed LER 05000331/2022-001-00.

Observation: Review of Aging Management for Below Grade Wall Degradation 71152A Due to Groundwater Intrusion The inspectors reviewed PSEG identification, evaluation and corrective actions related to indications of problems resulting from below grade wall groundwater intrusion in the Salem Units 1 and 2, 64-foot elevation auxiliary building exterior walls. These walls showed efflorescence and stained leachate typical to concrete structures exposed to a groundwater environment. Specifically, the inspectors reviewed Notification 20925794, generated in October 2022 regarding the presence of groundwater in-leakage through auxiliary building walls at the 64-foot elevation. The inspectors also reviewed associated SMP documents for these walls covering the most recent five year periodicity examinations completed in 2020 (S-IR-6S1-0027 and S-IR-6S2-0027).

The inspectors determined PSEG committed to enhance their SMP to perform chemical analysis of ground or surface water in-leakage where there is significant in-leakage or there may be reason to believe that the in-leakage may be damaging concrete elements or reinforcing steel (LR commitment, UFSAR Commitment No. 33, Item 13). Inspectors had previously questioned whether PSEG staff had tested groundwater at the 64-foot elevation walls considering the local staining and efflorescence. PSEG staff initiated Notification 20920419, sampled efflorescence, and determined in March 2023 the chemistry results did not indicate a significant breakdown of concrete element or reinforcing bar corrosion. The inspectors sampling review of records did not indicate groundwater samples had been taken for areas of groundwater intrusion such as the 64-foot elevation and that the basis was not clear as to how PSEG staff ruled out the potential for damage to concrete elements or reinforcement steel.

The inspectors also observed groundwater related corrosion on an electrical conduit to breaker panel S1460-1EX1AX17X-1, associated with the 12 control rod drive mechanism fan.

In review of records this condition had existed likely since 2011 as documented in several Notifications including 20536888, and recently re-assessed following NRC questions in Notification 20561198. The inspectors noted per PSEG procedure LS-AA-120, the issue should have been more appropriately categorized as a Severity Level 2 or 3, or as a CAQ or CARC, based on examples in Attachment 2, as the increased potential for fan tripping could affect reactor pressure head cooling during several operational modes.

This observation did not result in the identification of a performance deficiency or violation of more than minor significance.

EXIT MEETINGS AND DEBRIEFS

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

• On April 20, 2023, the inspectors presented the integrated inspection results to Dave Sharbaugh, Site Vice President, and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.01 Procedures SC.OP-AB.ZZ- Adverse environmental conditions 32

0001(Q)

71111.04 Corrective Action 20925483 Drain clogged on 21 CC pump room cooler 01/04/2023

Documents

Resulting from

Inspection

Drawings 205231 Sheet 1 No. 1 Unit Component Cooling 66

205231 Sheet 2 No. 1 Unit Component Cooling 44

205231 Sheet 3 No. 1 Unit Component Cooling 46

205336 Sheet 1 No. 2 Unit Auxiliary Feedwater 64

71111.05 Corrective Action 20925708 Fire extinguisher dates not accurate 01/29/2023

Documents

Resulting from

Inspection

Procedures FP-SA-1511 Salem Pre-Fire Plan 0

SC.ER-PS.FP- Salem Fire Protection Report - FHA 1

0001-A2

71111.13 Corrective Action 20925700 NRC challenge on protected equipment 01/19/2023

Documents

Procedures OP-AA-108-116 Protected Equipment Program 13

Work Orders 30315266 PM - Online test I-2109 Thermal O.L 01/12/2023

71111.15 Corrective Action 20893224 Flow erratic on 1R41 plant vent stack radiation monitor 01/01/2023

Documents system 1FA8603

20925195 21 steam generator missing piston seal and shim pack collar 01/04/2023

on 1 of 2 seismic struts

20925197 Flow erratic on 1R41 plant vent stack radiation monitor 01/04/2023

system 1FA8603 similar to previous issue

20925481 Pre- and post-MSIP cold measurements taken in 2009 did 01/04/2023

not properly account for different temperatures

20924615 25 CFCU failed to start in low speed 12/18/2022

20927637 25 CFCU failed to start in low speed 02/15/2023

Corrective Action 20931054 25 CFCU lessons learned 03/21/2023

Inspection Type Designation Description or Title Revision or

Procedure Date

Documents

Resulting from

Inspection

Engineering OEJ 70227453- Missing collar and shim pack on 21SGSWC 02/09/2023

Evaluations 0020

Miscellaneous 20925571 2CS14 failed PMT 01/10/2023

ML100920052 Agencywide Documents Access and Management system 12/15/2010

(ADAMS) accession no. ML100920052, unit 2 technical

specification amendment 281, delete the reactor coolant

system structural integrity requirement

Procedures OP-AA-102-103 Operator Workaround Program 3

Work Orders 60156235 Corrective maintenance rework for 1R41 flow elevated and 01/13/2023

erratic

30315266 PM - Online Test I-2109 Thermal O.L 01/10/2023

60156074 2CS14 failed PMT 01/12/2023

60156239 Corrective maintenance to 1R41 in accordance with S1.IC- 01/03/2023

CC.RM-0088

71111.18 Corrective Action 20883736 New Salem 21 and 22 essential controls inverter machine 09/05/2021

Documents had incorrect alarm setpoint

20920615 Vendor received unfavorable reading during 2C vital 11/14/2022

instrument bus testing prior to shipping

Engineering S-C-115-KQA- Qualitative Assessment for Quality, Reliability, and Common 12/18/2019

Evaluations 0003 Cause Failure Susceptibility for Installation of Ametek NDPP

Inverters

Procedures SC.MD-CM.115- Ametek Inverter Troubleshooting 0

0009

SC.MD-PM.115- 15 kVA Ametek Inverter Fan Checks 0

0010

SC.MD-PM.115- Ametek Inverter Parts Replacement 0

0011

71111.24 Corrective Action 20877260 22RH18 not responding as expected 10/28/2021

Documents 20919563 Degrading pump flow trend of 22 diesel fuel oil transfer pump 10/14/2022

20926210 22 diesel fuel oil transfer pump did not start following pump 01/26/2023

replacement

Inspection Type Designation Description or Title Revision or

Procedure Date

20926304 [NRC] Pipe wrench found on angle iron 01/26/2023

20930454 12 chiller tripped on compressor low discharge superheat 03/14/2023

temperature (refrigerant side)

Drawings 205216, Sheet 9 No. 1 Unit Chiller Refrigerant Loop 2

Engineering 70105525 13 chiller found out of service 12/02/2009

Evaluations 70220457 22RH18 not responding as expected 10/28/2021

Procedures MA-AA-716-1004 Conduct of Troubleshooting 17

S2.OP-ST.AF- Inservice Testing - Auxiliary Feedwater Valves 23

0004

S2.OP-ST.AF- Inservice Testing - Auxiliary Feedwater Valves 23

0004

Work Orders 50230466 S2.OP-ST.DG-0012 "2A Diesel Generator Endurance Run" 02/28/2023

239380 "S2.OP-ST.AF-0004 Inservice Testing - Auxiliary Feedwater 1/26/2023

Valves"

241086 "S2.OP-ST.CBV-0003, Containment Systems - Cooling 02/17/23

Systems"

60154603 Post-maintenance test using S1.OP-ST.CH-0004 following 10/25/2022

repairs

60155939 Corrective maintenance for IST - adverse trend in 22 DFOTP 01/25/2023

flow rate

71151 Engineering 70223712-0020 MRule Functional failure cause determination for failure of 04/23/2022

Evaluations unit 1 auxiliary building vent letdown heat exchanger switch

227130-0140 MRule Functional failure cause determination for Unit 2 03/06/2023

reactor trip SI

71152A Corrective Action 20881323 24 space heater running continuously 07/11/2021

Documents 20881905 21 space heater running continuously 07/30/2021

20881906 22 space heater running continuously 07/30/2021

20906830 23 space heater running continuously 05/21/2022

Engineering 80080098 Unit 2 steam generator seismic support conversion from 03/06/2006

Evaluations snubbers to compression struts

Procedures HU-AA-1212 Technical Task Risk / Rigor Assessment, Pre-Job Brief, 10

Independent Third Party Review, and Post-Job Brief

OP-AA-106-101- Operational and Technical Decision Making Process 11

1006

Inspection Type Designation Description or Title Revision or

Procedure Date

71153 Corrective Action 20929701 control room narrative did not accurately reflect unit 2 SI and 03/11/2023

Documents reactor trip on 12/24/2022

Resulting from

Inspection

19