IR 05000272/2021001

Integrated Inspection Report 05000272/2021001 and 05000311/2021001

ML21125A086
Person / Time
Site:	Salem
Issue date:	05/05/2021
From:	Brice Bickett Division of Operating Reactors
To:	Carr E Public Service Enterprise Group
References
IR 2021001
Download: ML21125A086 (23)

Text

May 5, 2021

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT 1 AND 2 - INTEGRATED INSPECTION REPORT 05000272/2021001 AND 05000311/2021001

Dear Mr. Carr:

On March 31, 2021, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Salem Nuclear Generating Station, Unit 1 and 2. On April 8, 2021, the NRC inspectors discussed the results of this inspection with Mr. Dave Sharbaugh, Site Vice President and other members of your staff. The results of this inspection are documented in the enclosed report.

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

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

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Resident Inspector at Salem Nuclear Generating Station, Unit 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, DC 20555-0001; with copies to the Regional Administrator, Region I; and the NRC Resident Inspector at Salem Nuclear Generating Station, Unit 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 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, X /RA/

Signed by: Brice A. Bickett

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

Docket Nos. 05000272 and 05000311 License Nos. DPR-70 and DPR-75

Enclosure:

Integrated Inspection Report 05000272/2021001 and 05000311/2021001

Inspection Report

Docket Numbers:

05000272 and 05000311

License Numbers:

DPR-70 and DPR-75

Report Numbers:

05000272/2021001 and 05000311/2021001

Licensee:

PSEG Nuclear, LLC

Facility:

Salem Nuclear Generating Station, Unit 1 and 2

Location:

Hancocks Bridge, NJ

Inspection Dates:

January 01, 2021 to March 31, 2021

Inspectors:

J. Hawkins, Senior Resident Inspector

M. Hardgrove, Resident Inspector

D. Kern, Senior Reactor Inspector

Approved By:

Brice A. Bickett, Chief

Reactor 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 Salem Nuclear Generating Station,

Unit 1 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

Inadequate Post Maintenance Procedures Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000272,05000311/2021001-01 Open/Closed

[H.5] - Work Management 71111.12 A Green, very low safety significance, self-revealing non-cited violation (NCV) of Salem Nuclear Generating Station Unit 2 Technical Specification (TS) 6.8.1.a was identified when PSEG did not establish appropriate post maintenance test procedures in accordance with the requirements of Regulatory Guide (RG) 1.33, Appendix A, Section 9, for the 22 component cooling heat exchanger service water inlet valve (22SW122) on August 7, 2020. Specifically, the procedures and work order instructions for the 22SW122 repair did not include an adequate post maintenance test which would have found the improper positioning of the needle valve that led to insufficient air flow to the valve actuator. This resulted in the valve failing in its ability to close within the required TS time of 30 seconds during quarterly surveillance testing, 39 days later, on September 15, 2020. As a result, the 22SW122 valve was determined to be inoperable.

Inadequate Maintenance Procedures for Bearing Lubrication of 21 CFCU Outboard Fan Bearing Cornerstone Significance Cross-Cutting Aspect Report Section Barrier Integrity Green NCV 05000272,05000311/2021001-02 Open/Closed

[H.7] -

Documentation 71111.19 A Green, very low safety significance, self-revealing non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, was identified because PSEG did not establish appropriate maintenance procedures for the Unit 2, 21 containment fan coil unit (CFCU) outboard fan bearing repacking on January 31, 2020. Specifically, the procedures did not have adequate instructions for greasing level inside the pillow housing for the outboard fan bearing. As a result, the 21 CFCU outboard fan bearing failed on December 13, 2020.

Inadequate Design Change Preventive Maintenance and Monitoring Actions Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000272,05000311/2021001-03 Open/Closed

[P.3] -

Resolution 71111.19 A Green, very low safety significance, self-revealing non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, was identified because PSEG did not establish adequate measures to ensure that safety-related components associated with the Unit 1, 13 chiller design change remained capable of performing their functions. Specifically, PSEG did not have adequate preventive maintenance, monitoring or testing established as part of the new chiller design change to provide reasonable assurance that the 13 chiller service water control valve (13SW857) would not fail due to the buildup of silt and impact the ability of the chiller to perform its safety function. As a result, the 13SW857 valve failed to properly isolate flow to the 13 chiller causing the chiller to trip on three separate occasions between December 2019 and January 2021, rendering the chiller inoperable.

Additional Tracking Items

None.

PLANT STATUS

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

Unit 2 began the inspection period at rated thermal power. The Unit remained at or near rated thermal power for the remainder of the inspection period.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors performed plant status activities described in IMC 2515, Appendix D, Plant Status, and conducted routine reviews using IP 71152, Problem Identification and Resolution. 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.

Starting on March 20, 2020, in response to the National Emergency declared by the President of the United States on the public health risks of the coronavirus (COVID-19), resident and regional inspectors were directed to begin telework and to remotely access licensee information using available technology. During this time the resident inspectors performed periodic site visits each week, increasing the amount of time on site as local COVID-19 conditions permitted. As part of their onsite activities, resident inspectors conducted plant status activities as described in IMC 2515, Appendix D; observed risk significant activities; and completed on site portions of IPs. In addition, resident and regional baseline inspections were evaluated to determine if all or portion of the objectives and requirements stated in the IP could be performed remotely. If the inspections could be performed remotely, they were conducted per the applicable IP. In some cases, portions of an IP were completed remotely and on site. The inspections documented below met the objectives and requirements for completion of the IP.

71111.01 - Adverse Weather Protection

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

(1) The inspectors evaluated the adequacy of the overall preparations to protect risk-significant systems from impending severe weather from winter storm warning on January 29

71111.04 - Equipment Alignment

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

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

(1) Unit 2, auxiliary feedwater discharge check valves during 22 auxiliary feedwater pump quarterly surveillance testing during the week of January 11

(2) Unit 2, chemical and volume control system during 21 charging pump maintenance window on January 12

(3) Unit 1, chillers following identification of through-wall leak during the week of January 18

(4) Unit 2, service water intake structure ventilation during the week of March 8

71111.05 - Fire Protection

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

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

(1) Unit 1, 'A' emergency diesel generator fire area FP-SA-1555 on January 4

(2) Unit 2, 'B' emergency diesel generator fire area FP-SA-2555 with CO2 shunt trip fault during the week of January 25

(3) Unit 1, relay and battery rooms fire area FP-SA-1551 on January 26

(4) Unit 2, relay and battery rooms fire area FP-SA-2551 on January 26

(5) Units 1 and 2, electrical penetration seal inspection on fire areas FP-SA-1531, FP-SA-1541, FP-SA-1551, FP-SA-2531, FP-SA-2541, and FP-SA-2551 on February 23

(6) Unit 1, service water intake structure and pump rooms fire area FP-SA-1651 during the week of March 8

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

(1) The inspectors evaluated the onsite fire brigade training and performance during a Unit 1 table top scenario for 13 reactor coolant pump motor on February 18

71111.06 - Flood Protection Measures

Inspection Activities - Internal Flooding (IP Section 03.01) (1 Sample)

The inspectors evaluated internal flooding mitigation protections in the:

(1) Unit 2, Residual heat removal (RHR) pump rooms on January 15

71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance

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

(1) The inspectors observed and evaluated licensed operator performance in the Control Room during 11 residual heat removal (RHR) pump in-service testing on March 3

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

(1) The inspectors observed and evaluated licensed operator requalification training on March 4, 2021

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (2 Samples)

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

(1) Unit 1, review of the RHR Discharge valve (12SJ49) to cold legs failure to stroke during the Unit 1 refueling outage during the weeks of January 4 and 11

(2) Unit 2, feed water regulating valve (21BF19) junction box and air line contact causing rubbing during the week of January 18

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management Sample (IP Section 03.01) (6 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 1 elevated risk due to 13 chiller trip on low differential pressure on January 20

(2) Unit 2 elevated risk due to 21 chiller maintenance window with 22 chiller operable but degraded on February 1

(3) Unit 1 elevated risk due to 'A' emergency diesel generator permissive light not lighting during in-service testing followed by relay replacement on February 2

(4) Unit 1 elevated risk due to 12 steam generator steam flow channel 2 isolation and inadvertent loss of automatic feed regulating valve control during the week of March 15

(5) Unit 1 elevated risk due to single source of offsite power for a planned 500Kv bus section 1 maintenance outage to perform relay work during the week of March 29

(6) Unit 2 elevated risk due to single source of offsite power for a planned 500Kv bus section 1 maintenance outage to perform relay work during the week of March 29

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) (6 Samples)

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

(1) Unit 2, 'B' emergency diesel generator service water supply valve (22SW39) failed stroke time on January 4

(2) Unit 2, 22 chiller condenser recirculation pump discharge check valve (22SW99)failed reverse seat test on January 8

(3) Unit 2, fuel handling building watertight door (2DOOR-FH103-2) failed chalk test during the week of January 25

(4) Unit 1, flow rate mismatch between calculations resulting in non-conforming condition for auxiliary feedwater flow rates when pumps are running on degraded pump curves on February 16

(5) Unit 1 and Unit 2, degraded electrical penetration seals discovered during fire protection walkdowns of auxiliary building on March 1

(6) Unit 2, degraded main control ventilation damper (S1CAV-1CAV3) during the week of March 8

71111.19 - Post-Maintenance Testing

Post-Maintenance Test Sample (IP Section 03.01) (9 Samples)

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

(1) Unit 2, 'B' emergency diesel generator service water supply valve (22SW39)replacement following slow stroke time during in-service testing on January 5

(2) Unit 1, 12 chilled water pump following through-wall leaks on January 11

(3) Unit 2, 21 containment fan coil unit (CFCU) outboard fan bearing failure on January 20

(4) Unit 1, 13 chiller troubleshooting following service water overcooling on January 20

(5) Unit 2, 23 CFCU outlet flow control valve (23SW233) replacement on January 28

(6) Unit 2, 'C' emergency diesel generator 18 month preventive maintenance window on February 18

(7) Unit 2, repair and testing of a service water pump ventilation damper (S2SWV-2SWV9)during the week of March 8

(8) Unit 1, 12 steam generator steam flow channel 2 restoration following transmitter leak and channel isolation during the week of March 15

(9) Unit 2, 23 chiller air regulator supply valve (23SW92) leak repair during the week of March 22

71111.22 - Surveillance Testing

The inspectors evaluated the following surveillance tests:

Surveillance Tests (other) (IP Section 03.01)

(1) Unit 1, review of containment spray full flow testing which included stroking of the RHR discharge valve to the cold leg (12SJ49) during the week of January 4

(2) Unit 1, 13 auxiliary feedwater pump surveillance test during the week of March 29

Inservice Testing (IP Section 03.01) (2 Samples)

(1) Unit 1, auxiliary feedwater valves on January 19

(2) Unit 1, 12 component cooling water pump during the week of March 22

71114.06 - Drill Evaluation

Select Emergency Preparedness Drills and/or Training for Observation (IP Section 03.01) (1 Sample)

(1) The emergency planning aspects of a licensed-operator simulator evaluation was conducted in the plant-reference simulator on January 19. This evaluation included the initiating conditions that resulted in associated emergency classification and notifications in accordance with PSEG's emergency plan.

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification

The inspectors verified licensee performance indicators submittals listed below:

MS05: Safety System Functional Failures (SSFFs) Sample (IP Section 03.04)===

(1) Unit 1, January 1, 2020 - December 31, 2020

(2) Unit 2, January 1, 2020 - December 31, 2020

BI01: Reactor Coolant System (RCS) Specific Activity Sample (IP Section 03.10) (2 Samples)

(1) Unit 1, January 1, 2020 - December 31, 2020

(2) Unit 2, January 1, 2020 - December 31, 2020

BI02: RCS Leak Rate Sample (IP Section 03.11) (2 Samples)

(1) Unit 1, January 1, 2020 - December 31, 2020

(2) Unit 2, January 1, 2020 - December 31, 2020

71152 - Problem Identification and Resolution

Annual Follow-up of Selected Issues (IP Section 02.03) (2 Samples)

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

(1) Unit 1 and 2, review of corrective actions associated with the auxiliary feedwater pump discharge check valves (AF23s) due to reverse flow surveillance test failures during the weeks of January 4 and 11

(2) Elevated Unit 1 outer penetration area temperatures and the associated impact on main steam isolation valve limit wwitch environmental qualified life

INSPECTION RESULTS

Inadequate Post Maintenance Procedures Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems

Green NCV 05000272,05000311/2021001-01 Open/Closed

[H.5] - Work Management 71111.12 A Green, self-revealing non-cited violation (NCV) of Salem Nuclear Generating Station Unit 2 Technical Specification (TS) 6.8.1.a was identified when PSEG did not establish appropriate post maintenance test procedures in accordance with the requirements of Regulatory Guide (RG) 1.33, Appendix A, Section 9, for the 22 component cooling heat exchanger service water inlet valve (22SW122) on August 7, 2020. Specifically, the procedures and work order instructions for the 22SW122 repair did not include an adequate post maintenance test which would have found the improper positioning of the needle valve that led to insufficient air flow to the valve actuator. This resulted in the valve failing in its ability to close within the required TS time of 30 seconds during quarterly surveillance testing, 39 days later, on September 15, 2020. Consequently, the 22SW122 valve was determined to be inoperable.

Description:

The Salem Unit 2, 22SW122 valve is stroke time tested quarterly to ensure that the valve will stroke closed in less than the TS required 30 seconds in accordance with the IST program. The 30 second stroke time mitigates potential water hammer effect during a loss of coolant accident and station blackout, in addition to minimizing the potential loss of cooling flow to other safety-related components during these accident conditions. The actuator on the 22SW122 is a Masoneilan Domotor which is direct acting actuator that utilizes air to open and close and will fail open. Air is supplied to the 22SW122 at a constant pressure through a filter regulator to the positioner. The positioner maintains valve position by porting into the top and bottom of the actuator piston through two volume boosters; one for each side of the piston, that assist in the closing speed of the valve. The volume boosters greatly increase the volume of air provided and the exhaust capability from each side of the piston.

Upstream of the air supply of each volume boosters are 1/2-inch needle valves which allow for adjustment to the volume boosters.

On September 15, 2020, during the performance of S2.OP-ST.SW-0008, Quarterly In-service Testing of Service Water Valves, the 22SW122 valve failed to stroke closed within the TS required 30 seconds, instead stroking closed in 37.81 seconds. PSEG declared the valve inoperable and entered a 72-hour TSAS while troubleshooting and repairing the valve.

PSEGs equipment reliability evaluation (ERE 70214617) determined that the cause of the slow closed stroked time was insufficient air flow to the 22SW122 due to improper position of the needle valve. PSEGs troubleshooting found the position of the needle valve was 1/4 turn open which results in the valve not passing a sufficient volume of air in order to close the valve in the required TS time. Per vendor documentation, the 1/4 turn open position is the starting valve position prior to proper tuning of the valve actuator and positioner. Prior to the stroke time test failure on September 15, 2020, the 22SW122 was last stroke time tested on June 16, 2020, (work order 50219710; 20.9 seconds) with acceptable results and no degrading trend. Between June and September, the 22SW122 valve feedback air hose from the positioner to the upper volume booster was replaced due to failure on August 7, 2020 (work order 60147339). PSEGs evaluation determined that the 22SW122 valve was not stroke time tested following the hose replacement and that PSEG procedure MA-AA-716-012, Post maintenance Testing, Attachment 5 for Air-Operated Valves, did not provide adequate instruction to ensure that AOVs, like the 22SW122, are stroke time tested as part of the required post-maintenance testing.

The inspectors reviewed PSEGs causal evaluation, work orders and maintenance procedures on December 2, 2020. The inspectors found that PSEG procedure MA-AA-716-012, Att. 5 for AOV PMT Guidelines, provides guidance on maintenance activities performed on AOVs that would require a stroke time test as part of the AOV PMT.

PSEGs repair (60147339) on August 7, 2020, addressed a small air line leak on the 22SW122. As part of this maintenance, the air supply to the valve was disconnected and the air line flexible hose was replaced. Per the table in MA-AA-716-012, Att. 5, the inspectors noted any actuator repair, refurbishment, or replacement of accessories would require a stroke time test as part of the PMT. PSEGs causal evaluation determined that this table was not specific enough to ensure stroke time testing was performed for the air line repair. As a corrective action, PSEG created an action to revise MA-AA-716-012, Att. 5, to clarify that stroke time testing is required whenever an air supply is disconnected from its actuator.

Because of this, the inspectors determined that PSEG did not establish appropriate post maintenance test procedures for the 22SW122 valve repair on August 7, 2020, which would have found the improper positioning of the needle valve that led to insufficient air flow to the valve actuator.

Corrective Actions: PSEGs corrective actions included documenting this issue in the Corrective Action program (CAP), performing a causal evaluation, placing the needle valves in the correct position and reperforming the stroke time testing for the 22SW122 valve.

PSEG also created actions to revise MA-AA-716-012, Att. 5, and perform applicable extent-of-condition reviews.

Corrective Action References: Work Order 70214198, 70214617, 70214841 and 70215923

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEG not establishing appropriate post maintenance test procedures for the 22SW122 valve repair was a performance deficiency that was within PSEGs ability to foresee and correct and should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the 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. The inspectors determined the performance deficiency was more than minor because it adversely affected the procedure quality attribute, specifically the maintenance and testing procedures, of the Mitigating Systems Cornerstone to the availability, reliability, and capability of systems that respond to initiating events. The 22 CCHX was potentially inoperable and unreliable from August 7 to September 15, 2020, because PSEGs PMT did not include stroke time testing of the 22SW122 valve.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that this finding was of very low safety significance (Green) using NRC IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power,

Exhibit 2 - Mitigating Systems Screening Questions, dated November 30, 2020, because all of the questions are answered NO.

Cross-Cutting Aspect: H.5 - Work Management: The organization implements a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process includes the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. The finding had a cross-cutting aspect of Human Performance, Work Management, because PSEG did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority, including the identification and management of risk commensurate to the work. (H.5)

Enforcement:

Violation: Salem Unit 2, TS 6.8.1.a requires, in part, that written procedures shall be established, implemented, and maintained covering the activities referenced in Appendix A of RG 1.33, Revision 2, February 1978. Appendix A, Section 5 of RG 1.33 requires procedures for properly preplanning and performing maintenance on safety-related equipment in accordance with written procedures and appropriate to the circumstances. PSEG procedure MA-AA-716-012, Post maintenance Testing, Attachment 5 for Air-Operated Valves provides station guidance on when PMT testing for AOVs is required.

Contrary to the above, on August 7, 2020, the procedure and work order instructions for the 22SW122 valve repair were not properly preplanned and performed with procedures appropriate to the circumstance. Specifically, PSEG did not include an adequate post maintenance test required by MA-AA-716-012 which would have identified the improper positioning of the needle valve that led to insufficient air flow to the valve actuator. This resulted in the valve failing in its ability to close within the required Technical Specification (TS) time of 30 seconds during quarterly surveillance testing on September 15, 2020.

Consequently, the 22SW122 valve was determined to be inoperable.

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

Inadequate Maintenance Procedures for Bearing Lubrication of 21 CFCU Outboard Fan Bearing Cornerstone Significance Cross-Cutting Aspect Report Section Barrier Integrity

Green NCV 05000272,05000311/2021001-02 Open/Closed

[H.7] -

Documentation 71111.19 A Green, very low safety significance, self-revealing non-cited violation (NCV) of Title 10 of Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified because PSEG did not establish appropriate maintenance procedures for the Salem Unit 2, 21 containment fan coil unit (CFCU) outboard fan bearing repacking on January 31, 2020. Specifically, the procedures did not have adequate instructions for greasing level inside the pillow housing for the outboard fan bearing. As a result, the 21 CFCU outboard fan bearing failed on December 13, 2020 and the 21 CFCU was declared to be inoperable.

Description:

The Unit 2 containment fan cooling system is an engineered safeguard that is designed to operate during normal power generation, and during the design basis loss of coolant accident (LOCA). The system reduces containment stress via removing heat from the containment atmosphere to limit the average temperature to 120 degrees Fahrenheit (F)during normal power operation and shutdown conditions. The containment fan cooling system consists of five CFCUs, each consisting of a motor, fan, motor heat exchangers, cooling coils, roughing filters, dampers, duct distribution system, instrumentation, and controls. The fan cooling system is actuated, in the post-accident mode, by a safety injection signal. Either all five CFCUs or a minimum of three CFCUs are started by the safeguards equipment controller, depending on the availability of emergency power.

The 21 CFCU outboard fan bearing was last rebuilt on January 31, 2020 under maintenance procedure SC.MD-PM.CBV-0001(Q), Revision 13, Containment Fan Coil Unit Shaft, Pillow Block Bearing and Labyrinth Seal Repack and/or Replacement. Under Work Order (WO) 60144009, the outboard bearing and inboard and outboard pillow block bearings were replaced, the old-style bearing housing was reused, and the bearing was repacked with 4 lbs. of Krytox grease. The packing break-in run of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of operation and swapping between high-speed and low-speed CFCU functions was completed satisfactorily.

However, the inspectors noted that PSEG did not have available a completed WO 60144009 copy for review that recorded the actual grease amounts used.

Following the rebuild on the 21 CFCU, a Common Cause Evaluation (CCE) 70204764-0100 was created to address lubrication issues surrounding application of Krytox 283AC Grade 2 grease during CFCU bearing assembly and packing. CCE 70204764-0100 identified issues that could lead to bearing failures such as over or under packing and oil separation while in storage, which were not addressed in the prior 21 CFCU bearing rebuild on January 31, 2020. SC.MD-PM.CBV-0001(Q) Revision 13 had inadequate steps for bearing grease compared to the maintenance practices being implemented. Maintenance practices determined that 6 lbs. of Krytox grease were required per bearing, which is more than the 4 lbs. required by SC.MD-PM.CBV-0001(Q) Revision 13. Maintenance procedure SC.MD-PM.CBV-0001(Q) was subsequently revised to Revision 14 to include attachments defining levels of grease in the bearing housing.

On October 27, 2020, temperatures on the outboard bearing of the 21 CFCU started to oscillate between 0- and 136-degrees F. The control room temperature alarm for the 21 CFCU outboard fan bearing temperature was subsequently blocked by operators in the main control room on October 29, 2020 (NOTF 20863452). This is permitted by SC.OP-DL.ZZ-0010, Revision 11, Control Room Instrumentation and Alarms, provided a method to track instrumentation, that is either inoperable or not a reliable source of information, is utilized by control room operators. The inboard and outboard fan bearing temperatures are monitored via the plant computer, and will alarm when temperatures reach 185 degrees F. The operations limit in accordance with Salem operating procedure S1.OP-SO.CBV-0001, Revision 27, Containment Ventilation Operations, is 195 degrees F. The bearing temperature oscillations continued to rise, peaking at 244 degrees F on December 7, 2020.

During the time period of December 7 through December 13, 2020, temperature increased continuously above the alarm temperature of 195 degrees F. On December 13, 2020, the 21 CFCU was identified with an elevated outboard fan bearing temperature, with a maximum recorded temperature of 440 degrees F. Operators secured the 21 CFCU and dispatched field operators to investigate. The field operators reported a local temperature of 290 degrees F and outboard fan bearing degradation. The 21 CFCU was declared inoperable and troubleshooting and corrective maintenance followed until the 21 CFCU was restored on December 22, 2020. Following the 21 CFCU being declared inoperable for the outboard fan bearing failure, PSEG evaluated operator actions (70215971-0010) prior to and during the 21 CFCU outboard fan bearing failure. Specifically, PSEG determined the 21 CFCU outboard bearing temperature was not monitored appropriately and operators did not put sufficient monitoring plans in place following the blocking of the alarm in accordance with procedure SC.OP-DL.ZZ-0010, Revision 11.

PSEG Equipment Reliability Evaluation (ERE) 70215971-0020 following the 21 CFCU outboard fan bearing failure determined that the bearing failed because of lubrication deficiencies as a result of installation on January 31, 2020 and condition monitoring.

Based on the information above, the inspectors determined that PSEG did not establish adequate maintenance procedures for the 21 CFCU outboard fan bearing during the bearing repacking on January 31, 2020. Specifically, PSEG procedure SC.MD-PM.CBV-0001, Revision 13, did not have adequate instruction for greasing the pillow housing that resulted in the 21 CFCU outboard fan bearing failure.

Corrective Actions: PSEGs corrective actions involved a procedure revision for procedural enhancements to SC.MD-PM.CBV-0001 to Revision 14 for lubrication reliability issues and to ensure Krytox grease is mixed thoroughly prior to installation following Common Cause Evaluation 70204764-0100. PSEG also performed a ERE following the 21 CFCU outboard fan bearing failure to determine the direct cause.

Corrective Action References: Notification 20863452, 20867330, 20867400

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEG did not have adequate maintenance procedures for the 21 CFCU outboard fan bearing which was a performance deficiency that was within their ability to foresee and correct, and which should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the SSC and Barrier Performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The performance deficiency is more than minor because it was associated with the procedure quality attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, PSEGs maintenance procedure SC.MD-PM.CBV-0001, Revision 13, did not have adequate instructions for greasing level inside the pillow housing for the 21 CFCU outboard fan bearing during bearing replacement on January 31, 2020. Thus, on December 13, 2020 the 21 CFCU outboard fan bearing failed and the 21 CFCU was inoperable and unavailable from December 13 through December 22, 2020.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors assessed the significance of the finding using Appendix A, Significance Determination of Reactor Inspection Findings for at Power, Exhibit 3 - Barrier Integrity Screening Questions, Section C for Reactor Containment. The finding screened to Green, very low safety significance, because there was no actual open pathway in the physical integrity of the reactor containment, no failure of the containment isolation system, no failure of containment heat removal components, or no failure of the plants severe accident mitigation features. Additionally, there was no actual reduction in function of the hydrogen igniters in the reactor containment.

Cross-Cutting Aspect: H.7 - Documentation: The organization creates and maintains complete, accurate and up-to-date documentation. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Documentation, because PSEG did not maintain complete, accurate, and up-to-date documentation. Specifically, PSEG did not have available a completed WO 60144009 copy for review and verification of the 21 CFCU bearing repacking, thus no record of grease amounts was available for review. [H.7]

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions or procedures of a type appropriate to the circumstances and shall include qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

Contrary to the above, on January 31, 2020, PSEGs maintenance procedure SC.MD-PM.CBV-0001, Revision 13, the procedure for lubricating the outboard fan bearing of the 21 CFCU did not include adequate instructions for greasing level inside the pillow housing that led to elevated bearing temperatures. This resulted in the 21 CFCU outboard fan bearing failing and the 21 CFCU being declared inoperable due to high temperature from inadequate bearing lubrication on December 13, 2020.

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

Inadequate Design Change Preventive Maintenance and Monitoring Actions Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems

Green NCV 05000272,05000311/2021001-03 Open/Closed

[P.3] -

Resolution 71111.19 A Green, very low safety significance, self-revealing non-cited violation (NCV) of Title 10 of the Code of Federal Regulation (CFR) Part 50, Appendix B, Criterion III, Design Control, was identified because PSEG did not establish adequate measures to ensure that safety-related components remained capable of performing their functions associated with the 13 chiller design change. Specifically, PSEG did not have adequate preventive maintenance, monitoring or testing established as part of the new chiller design change to provide reasonable assurance that the Salem Unit 1, 13 chiller service water control valve (13SW857)would not fail due to the buildup of silt and impact the ability of the chiller to perform its safety function. As a result, the 13SW857 valve failed to properly isolate flow to the 13-chiller

causing the chiller to trip on three separate occasions between December 2019 and January 2021, rendering the chiller inoperable.

Description:

The Salem Unit 1 chilled water system consists of three 50 percent capacity safety-related chillers. The safety functions of the chilled water system are to remove heat loading from the emergency control air compressors under accident conditions, and from the main control room air conditioning units under normal and accident conditions. On December 18, 2019, the 13 chiller tripped on low suction pressure. This impacted 13 chillers ability to provide heat removal for safety-related equipment. As a result, the 13 chiller was declared inoperable and Unit 1 entered a 14-day unplanned Limiting Condition of Operation (LCO) per Technical Specification Action Statement 3.7.10.a. PSEG performed troubleshooting which determined that the chiller tripped due to sediment (silt) buildup on the 13SW857 seating surface allowing service water through the valve, overcooling the refrigerant stored in the condenser. PSEG took immediate corrective action (CA) to manually jack open the 13SW857 valve and flush the valve internals to remove the buildup of silt. This eliminated the excessive cooling of the condenser refrigerant and allowed the chiller to be restored to an operable status. PSEG took additional CAs to create a maintenance plan to perform quarterly flushing of the SW857 valves.

On December 15, 2020, the 13 chiller tripped on low suction pressure across the compressor. PSEGs troubleshooting determined that the chiller tripped due to silt buildup on the 13SW857 seating surface allowing service water through the valve, overcooling the refrigerant stored in the condenser. After flushing the valve, returning the chiller to service, and while performing a causal evaluation for the trip, the 13 chiller tripped again due to service water overcooling the refrigerant caused by silt buildup on the 13SW857 valve on January 19, 2021. PSEGs causal evaluation (70215962) included both the December 15, 2020, and January 19, 2021, trips as part of their review for CAs. PSEG determined that inadequate design and preventive maintenance contributed to the 13SW857 valve failing to operate correctly causing the chiller to trip. PSEGs corrective actions included flushing the 13SW857 valve, increasing the frequency of the scheduled flushes of the 13SW857 valve from quarterly (every 3 months) to bi-weekly (every 2 weeks), and reviewing the chiller trip setpoints for additional operating margin.

The inspectors noted that the three Salem Unit 1 chillers (11, 12, and 13) are in the process of being upgraded under PSEGs Design Change Package (DCP) 80111049. The 11 and 13 chillers have been upgraded to the new chiller design which directly uses refrigerant pressure to control service water flow through its condenser. During the review of PSEGs evaluations and the DCP, the inspectors noted DCP Section 4.1.7, which discusses that the new chiller design removed the benefit of preventing biofouling, and states that increased biofouling monitoring and high flow flushes will be required to compensate for the elimination of this [benefit] (pg. 31). The DCP goes on to say that regular, high flow condenser flushing will be performed to prevent silt buildup and biofouling. This new maintenance activity is needed due to the removal of SW recirculation piping around the existing condensers. The flushing will be supported with monitoring of condenser parameters to determine when flushing is required and to confirm that flushing is effective in removing silt buildup and biofouling (pg. 47).

Based on this, the inspectors determined that PSEGs conclusion of inadequate design and preventive maintenance contributed to the initial 13 chiller trip in December 2019, and that inadequate corrective actions led to the repeated 13 chiller trips in December 2020, and January 2021.

Corrective Actions: PSEGs corrective actions included documenting this issue in CAP, performing a causal evaluation, flushing the 13SW857 valve, increasing the frequency of the scheduled flushes of the 13SW857 valve from quarterly to bi-weekly, and reviewing the chiller trip setpoints for additional operating margin.

Corrective Action References: 70210322 and 70215962.

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEG not having adequate preventive maintenance, monitoring or testing established as part of the chiller design change, specifically for the 13SW857 valve, was a performance deficiency that was within PSEGs ability to foresee and correct, and should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the 13 chiller was inoperable and unavailable on three separate occasions due to the performance issue.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors assessed the significance of the finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that this finding was of very low safety significance (Green), because NO was answered to all the screening questions.

Cross-Cutting Aspect: P.3 - Resolution: The organization takes effective corrective actions to address issues in a timely manner commensurate with their safety significance. This finding had a cross-cutting aspect of Problem Identification and Resolution, Resolution, because PSEG did not take effective corrective actions to address the frequent buildup of silt on the 13SW857 valve which led to multiple chiller trips and chiller inoperability. (P.3)

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, that for those SSCs to which this appendix applies, measures shall be established to assure the regulatory requirements and design basis of SSCs are correctly translated into procedures and instructions. These measures shall include provisions to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. Measures shall also be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems and components. The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews or by the performance of a suitable testing program.

Contrary to the above, between December 2019 and January 2021, PSEG did not establish adequate measures resulting from the design change of the Unit 1 chiller system to ensure that safety-related components remained capable of performing their functions. Specifically, PSEG did not have adequate preventive maintenance, monitoring or testing established to provide reasonable assurance that the SW857 valves would not fail and impact the ability of the 13 chiller to perform its expected function. As a result, the 13SW857 valve failed to isolate flow to the 13 chiller causing the chiller to trip and be inoperable on three occasions.

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

Observation: Delay in Collecting and Evaluating MSIV Limit Switch Temperature Data 71152 In August 2019, inspectors identified elevated temperatures in the vicinity of main steam isolation valve (MSIV) limit switches 14MS167LS4 (178F) and 12MS167LS3 (163F) within the Unit 1 Outer Penetration Area (OPA). These temperatures exceeded the normal service temperature (160F) which engineers had analyzed to determine the environmental qualification (EQ) life of these components. Engineers placed the issue in the corrective action program (notifications 20832547, 20834827, and 70209183), performed follow-up evaluations of EQ life, and initiated actions to replace the 14MS167 limit switches and install temperature monitoring devices to obtain reliable temperature measurements to support verification of EQ life. The inspectors selected this issue as an annual sample for focused problem identification and resolution review, because the issue could adversely impact the MSIV limit switch safety-related function to provide input to the reactor control solid state protective system. Inspection scope included review of issue documentation and prioritization, causal evaluation, corrective actions, and assessment of the extent-of-condition.

The inspectors concluded PSEG staff appropriately documented the issue in the corrective action program and evaluated the immediate potential safety consequence and extent-of-condition in a manner commensurate with its safety significance. Engineers determined all U1 and U2 MSIV limit switches remained qualified. Corrective actions, including replacement of the 14MS167 limit switches during a March 2020 forced outage and advancing the scheduled replacement of 12MS167 limit switches to the Spring 2023 refueling outage were appropriate. Temperature monitoring equipment for Unit 1 MSIV (12MS167 and 14MS167)limit switches to verify the normal service temperatures were installed in December 2020. The inspectors noted this was much later than originally recommended by engineers, but still provided time for data collection and EQ life analysis prior to exceeding current MSIV limit switch qualified life.

The inspectors performed plant walkdowns and determined the temperature monitoring equipment was not properly installed on the U1 MSIV limit switches and the licensee had no reliable data for the first month since installation. Review of initial MSIV limit switch temperature data during the inspection, revealed that some MSIV limit switches may exceed the 178F temperature previously measured and evaluated. The inspectors discussed the importance of verifying equipment was properly installed to support timely collection of MSIV limit switch temperature data and analysis with engineers. PSEG staff-initiated notification 20868904 to correct the equipment installation and data collection. The inspectors concluded the significance of the delay in collecting and evaluating MSIV limit switch temperature data was minor, because based on analysis of current temperature data, the oldest installed MSIV limit switches remained qualified until September 2023.

Observation: Unit 1 and 2, review of the Auxiliary Feedwater Pump Discharge Header Stop Check Valves (AF23s)71152 The inspectors reviewed PSEGs equipment performance issues with the Auxiliary Feedwater (AFW) Pump Discharge Header Stop Check Valves (AF23s). Additionally, due to recent operating experience from Surry Station (OE 486762; NRC 95001 Supplemental Inspection Report 05000281/2020040) which involved inadequate preventive maintenance and inspection of their turbine-driven auxiliary feedwater (TDAFW) pump discharge check valves, the inspectors utilized this OE to inform their inspection of the Salem Unit 1 and 2 AFW discharge stop check valves.

Each Salem Unit AFW system consists of two motor-driven pumps and one turbine-driven pump. The AFW system serves as a backup system for supplying feedwater to the secondary side of the steam generators when the main feedwater system is not available and can be relied upon for extended periods to prevent core damage and system over pressurization in the event of accidents such as a loss of normal feedwater or a secondary system pipe rupture, and to provide a means for plant cooldown. Prior to the flow being discharged from the AFW pumps and entering the steam generators (through the main feedwater lines), the AFW flow must travel through the AF23 stop check valves. These valves have a closed safety function to prevent reverse flow through the system and preclude steam binding of the AFW pumps which could result in the inability of the pumps to start on demand.

The inspectors reviewed PSEGs license commitments, testing and maintenance records, and corrective action program (CAP) documents for the AF23 valves as part of this inspection. The inspectors verified that PSEG compliance with the ASME code of record for testing and preventive maintenance for these valves per ASME OM Code-2012 Edition, Operation and Maintenance of Nuclear Power Plants. The inspectors also reviewed PSEGs cold shutdown testing justification, CS-03, documented in IST-SC-PROG-CS JUSTIF, Salem Generating Station Units 1 and 2 Fifth Interval In-service Testing Plan for Pumps and Valves 2, for not including the AF23 valves in the in-service testing (IST) Check Valve Monitoring Program. This review also included verifying that the valves are routinely tested using PSEG procedure S1(S2).OP-ST.AF-0005. No major deficiencies were noted during this review.

However, the inspectors did note that corrective actions (CAs) associated with a 2016 common cause evaluation (CCE 70188576) were not timely. Specifically, PSEGs evaluation was conducted in response to the risk of repeated issues with the AF23 valves [seven in-service testing (IST) reverse flow failures and five separate leak-by events during normal operations], and documented inadequate procedural guidance for IST testing and inadequate preventive maintenance in that it was not in accordance with industry guidance. PSEG created action 70188576-0160 on October 26, 2016, to revise the AF23 valve maintenance strategy from a 6-year open and inspect to a 9-year full valve replacement (NOTF 20842018). The review and generation of the NOTF took over 3.5 years (March 3, 2020),and the associated Order 70211792 to change the maintenance strategy is now due on April 4, 2021.

In discussions with PSEG engineering and reviews of the AF23 valve replacement history, the inspectors found that: 1. All four of the Unit 1 AF23 valves were replaced in 1996 (WO# 930203123); 2. All four of the Unit 2 AF23 valves were replaced in 1995 (WO# 930802086) and that the 23AF23 was replaced again in 2017 (WO# 60129392). Based on this, the inspectors determined that seven of the eight AF23 valves across both Salem Units 1 and 2 were potentially 25 years old exceeding PSEGs justification for a 9-year full valve replacement. The inspectors noted that PSEG has active operability evaluations for the AF23 valve performance under 70213081, and that PSEG has entered this into their CAP under 70213151. The observation above concerning the untimely CAP actions were evaluated to be minor violations in accordance with IMC 0612, Appendix B and Appendix E. Consequently, these issues were not subject to enforcement action in accordance with the NRCs enforcement policy.

EXIT MEETINGS AND DEBRIEFS

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

• On April 8, 2021, the inspectors presented the integrated inspection results to Mr. Dave Sharbaugh, Site Vice President and other members of the licensee staff.

THIRD PARTY REVIEWS

Inspectors reviewed Institute on Nuclear Power Operations reports that were issued during the inspection period on March 8.

DOCUMENTS REVIEWED

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71152

Calculations

S-C-ZZ-SDC-

1419

Salem Generating Station Environmental Design Criteria

Revision 0

Corrective Action

Documents

notification

20832547

notification

20834827

notification

20846398

notification

20859775

notification

20868254

notification

40041483

notification

209183

Corrective Action

Documents

Resulting from

Inspection

notification

20868815

notification

20868904

Engineering

Evaluations

EQ-SA-008B

Environmental Qualification Binder for Namco Controls, Limit

Switch Model(s) EA180-xx302 and EA180-xx602

Revision 1

Work Orders

40041483

60147891