IR 05000272/2018003

Integrated Inspection Report 05000272/2018003 and 05000311/2018003

ML18318A010
Person / Time
Site:	Salem
Issue date:	11/13/2018
From:	Fred Bower Reactor Projects Branch 3
To:	Sena P Public Service Enterprise Group
References
IR 2018003
Download: ML18318A010 (28)

Text

November 13, 2018

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -

INTEGRATED INSPECTION REPORT 05000272/2018003 AND 05000311/2018003

Dear Mr. Sena:

On September 30, 2018, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Salem Nuclear Generating Stations (Salem) Units 1 and 2. On October 10, 2018, the NRC inspectors discussed the results of this inspection with Mr. Charles McFeaters, Salem Vice President, and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented two findings of very low safety significance (Green) in this report.

Both of these findings involved violations of NRC requirements. Further, inspectors documented a PSEG-identified violation which was determined to be of very low safety significance in this report. The NRC is treating these violations as non-cited violations (NCVs)

consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or significance of these NCVs, 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. In addition, if you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC, 20555-0001; with copies to the Regional Administrator, Region I, and the NRC Resident Inspector at Salem.

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 the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations (10 CFR), Part 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Fred L. Bower, III, Chief Reactor Projects Branch 3 Division of Reactor Projects

Docket Nos:

50-272 and 50-311 License Nos. DPR-70 and DPR-75

Enclosure:

Inspection Report 05000272/2018003 and 05000311/2018003

Inspection Report

Docket Nos.

50-272 and 50-311

License Nos.

DPR-70 and DPR-75

Report Nos.

05000272/2018003 and 05000311/2018003

PSEG:

PSEG Nuclear LLC PSEG

Facility:

Salem Nuclear Generating Station (Salem) Units 1 and 2

Location:

Hancocks Bridge, NJ 08038

Dates:

July 1, 2018, through September 30, 2018

Inspectors:

P. Finney, Senior Resident Inspector

A. Ziedonis, Resident Inspector

J. Furia, Senior Health Physicist

Approved By:

Fred L. Bower, III, Chief

Reactor Projects Branch 3

Division of Reactor Projects

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring PSEGs performance at

Salem Units 1 and 2 by conducting the baseline inspections described in this report 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. NRC identified and self-revealing findings, violations, and additional items are summarized in the table below.

Licensee-identified non-cited violations are documented in the following Inspection Results sections of the report: 7115

List of Findings and Violations

Inadequate Chiller Maintenance Procedures Cornerstone Significance Cross-Cutting Aspect Inspection Results Section Mitigating Systems

Green NCV 311/2018-003-01 Closed H.7 - Human Performance -

Documentation 71152 (1)

The inspectors identified a Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, when PSEG did not properly preplan maintenance activities in accordance with written instructions appropriate to the circumstances of safety-related chiller compressor tubing repairs and installation. Specifically, PSEG installed compressor oil tubing lines without appropriate work instructions, which led to insufficient separation, and use of a nylon tie or strap to support and route two adjacent lines of tubing, causing the tubing lines to rub and fret during normal compressor operation. Consequently, on March 5, 2018, the 22 chiller compressor tripped on low oil pressure as a result of oil leakage from tube fretting.

Failure to Follow Generic Letter 89-13 Program Procedure Cornerstone Significance Cross-Cutting Aspect Inspection Results Section Mitigating Systems

Green NCV 311/2018-003-02 Closed P.3 - Problem Identification and Resolution-Resolution 71152 (3)

The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not adequately follow Generic Letter (GL) 89-13 program procedure steps for performing inspections of the safety-related service water (SW) piping and components. Specifically, certain American Society of Mechanical Engineers (ASME) Nuclear Class III pressure retaining components were not inspected, as required by ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 8, during SW system internal pipe inspections.

Consequently, protective internal coating degradation on the 21 SW supply header two-inch branch connection was not identified and corrected, which resulted in through-wall leakage and significant weld material loss due to corrosion.

Additional Tracking Items

Type Issue number Title Inspection Results Section Status LER 05000311/2018-001-00 Manual reactor trip due to elevated 21 Reactor Coolant Pump motor winding temperature 71153 Closed

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. On September 14, the unit automatically tripped from approximately 90 percent of rated thermal power on steam generator high water level. A startup was commenced on September 16 and the unit ascended to 67 percent power on September 20. The unit remained at or near 67 percent of 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 PSEGs performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

71111.01 - Adverse Weather Protection

Impending Severe Weather (1 Sample)

The inspectors evaluated readiness for impending adverse weather conditions for a hot weather alert on August 27, 2018.

External Flooding (1 Sample)

The inspectors evaluated readiness to cope with external flooding associated with the service water intake structure and auxiliary building on July 2, 2018.

71111.04 - Equipment Alignment

Partial Walkdown (3 Samples)

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

(1) Unit 1, Control room emergency air conditioning system (CREACS) and auxiliary feedwater (AFW) with 11 AFW pump and Unit 2 CREACS out of service (OOS) on July 24, 2018

(2) Unit 1, charging system (high head safety injection) with 11 component cooling water pump OOS on September 5, 2018

(3) Common, 4KV with 11 and 22 station power transformers OOS on July 9, 2018

Complete Walkdown (1 Sample)

The inspectors evaluated system configurations during a complete walkdown of the Switchgear and Penetration Area Ventilation system, on September 20, 2018.

71111.05A/Q - Fire Protection Annual/Quarterly

Quarterly Inspection (5 Samples)

The inspectors evaluated fire protection program implementation in the following selected areas:

(1) Unit 1, Auxiliary feedwater pump area on September 5, 2018

(2) Unit 2, Mechanical penetration area on July 20, 2018

(3) Common, 460V/230V switchgear on July 5, 2018

(4) Common, 1 and 4 SW bays on August 2, 2018

(5) Common, 4KV switchgear on August 23, 2018

Annual Inspection (1 Sample)

The inspectors evaluated fire brigade performance during a drill in the SW intake structure control room #3 on September 5, 2018.

71111.11 - Licensed Operator Requalification Program and Licensed Operator Performance

Operator Performance (1 Sample)

The inspectors observed power coastdown and axial flux difference control on September 5, 2018.

Operator Requalification (1 Sample)

The inspectors reviewed and evaluated licensed operator requalification training that involved steam generator tube ruptures, a service water leak, a small break loss of coolant accident, and a load reduction on July 30, 2018.

71111.12 - Maintenance Effectiveness

Routine Maintenance Effectiveness (2 Samples)

The inspectors evaluated the effectiveness of routine maintenance activities associated with the following equipment and/or safety significant functions:

(1) Common, Control room ventilation radiation monitor (R1B) failures on July 2, 2018

(2) Common, Feedwater regulating valves (FRVs) on September, 24, 2018

71111.13 - Maintenance Risk Assessments and Emergent Work Control

The inspectors evaluated the risk assessments for the following planned and emergent work activities:

(1) Unit 1, Main generator stator winding elevated vibration and emergent troubleshooting on September 5, 2018

(2) Unit 2, 2G1 460V motor control center bus outage with temporary power to FLEX and service water accumulator heating ventilation and cooling on July 23, 2018

(3) Unit 2, FRV 23BF19 emergent work on September 17, 2018

(4) Unit 2, FRV emergent instrumentation and monitoring during startup following reactor trip on September 18, 2018

(5) Common, 11 SW strainer rework and 25 SW strainer troubleshooting on July 31, 2018

(6) Common, Emergent work in response to mitigating strategies diesel fuel transfer system on August 15, 2018

71111.15 - Operability Determinations and Functionality Assessments

The inspectors evaluated the following operability determinations and functionality assessments:

(1) Unit 1, Spent fuel pool water seepage into auxiliary building on July 9, 2018

(2) Unit 2, 25 SW strainer continuous blowdown and subsequent trip on August 1, 2018

(3) Unit 2, Containment sump level recorder issues on August 7, 2018

(4) Common, River temperature exceeds 82 degrees on July 26, 2018

71111.18 - Plant Modifications

The inspectors evaluated the following temporary or permanent modifications:

(1) Unit 2, 23 Heater drain pump steam leak temporary repair on August 20, 2018

71111.19 - Post Maintenance Testing

The inspectors evaluated post maintenance testing for the following maintenance/repair activities:

(1) Unit 1, 11 component cooling water pump lube and breaker switch calibration on July 3, 2018

(2) Unit 1, Auxiliary building ventilation (ABV) damper ABV7 failure to open, and associated solenoid valve repair, on July 12, 2018

(3) Unit 1, Emergency control air compressor following lubrication classification error on July 18, 2018

(4) Unit 1, 16 SW pump replacement on September 7, 2018

(5) Unit 1, 11 ABV supply fan lube, alignment, expansion joint repair, and internal inspection on September 12, 2018

(6) Unit 2, 22 SW strainer as-found degraded body and anode on September 13, 2018

71111.22 - Surveillance Testing

Inservice (1 Sample)

(1) Unit 2, 22 AFW (IST) on July 11, 2018

71114.06 - Drill Evaluation

Drill/Training Evolution (1 Samples)

The inspectors observed and evaluated a simulator-based licensed operator requalification exam scenarios that involved a service water leak, a control rod eject, a failure of the reactor to manually trip, a pressurizer power-operator relief valve failing open, and a total loss of residual heat removal flow, on August 13,

71124.06 - Radioactive Gaseous and Liquid Effluent Treatment

Walkdowns and Observations (1 Sample)

The inspectors walked down the gaseous and liquid radioactive effluent monitoring and filtered ventilation systems to assess the material condition and verify proper alignment according to plant design.

Calibration and Testing Program (Process and Effluent Monitors) (1 Sample)

The inspectors reviewed gaseous and liquid effluent monitor instrument calibration, functional test results, and alarm set-points based on National Institute of Standards and Technology calibration traceability and the offsite dose calculation manual (ODCM)specifications.

Sampling and Analyses (1 Sample)

The inspectors reviewed radioactive effluent sampling activities, representative sampling requirements, compensatory measures taken during effluent discharges with inoperable effluent radiation monitoring instrumentation, the use of compensatory radioactive effluent sampling, and the results of the inter-laboratory and intra-laboratory comparison program including scaling of hard-to-detect isotopes.

Instrumentation and Equipment (1 Sample)

The inspectors reviewed the methodology used to determine the radioactive effluent stack and vent flow rates to verify that the flow rates were consistent with TS/ODCM and the Updated Final Safety Analysis Report (UFSAR) values. The inspectors reviewed radioactive effluent discharge system surveillance test results based on TS acceptance criteria.

Dose Calculations (1 Sample)

The inspectors reviewed changes in reported dose values from the previous annual radioactive effluent release reports, several liquid and gaseous radioactive waste discharge permits, the scaling method for hard-to-detect radionuclides, ODCM changes, land use census changes, public dose calculations (monthly, quarterly, annual), and records of abnormal gaseous or liquid radioactive releases.

71124.07 - Radiological Environmental Monitoring Program

Site Inspection (1 Sample)

The inspectors walked down various thermoluminescent dosimeter and air and water sampling locations and reviewed associated calibration and maintenance records. The inspectors observed the sampling of various environmental media as specified in the ODCM. The inspectors reviewed the groundwater monitoring program as it applies to selected potential leaking structures, systems, and components, and 10 CFR 50.75(g)records of leaks, spills, and remediation since the previous inspection.

Groundwater Protection Initiative (GPI) Implementation (1 Sample)

The inspectors reviewed: groundwater monitoring results; changes to the GPI program since the last inspection; anomalous results or missed groundwater samples; leakage or spill events including entries made into the decommissioning files (10 CFR 50.75(g)); evaluations of surface water discharges; and PSEGs evaluation of any positive groundwater sample results including appropriate stakeholder notifications and effluent reporting requirements.

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification

The inspectors verified PSEGs performance indicator submittals listed below for the period from July 1, 2017, through June 30, 2018.===

(1) Unit 1 Heat Removal Systems (MS08)

(2) Unit 2 Heat Removal Systems (MS08)

(3) Unit 1 Residual Heat Removal Systems (MS09)

(4) Unit 2 Residual Heat Removal Systems (MS09)

Based on a review of Notifications (NOTFs) for the period from January 1, 2018, through September 13, 2018, the inspectors verified that PSEG had identified all occurrences that met the reporting thresholds for the below listed performance indicators. (2 samples)

(5) Common, Occupational Exposure Control Effectiveness (OR01)

(6) Common, Radiological Effluent TS/ODCM Radiological Effluent Occurrences (PR01)

71152 - Problem Identification and Resolution

Annual Follow-up of Selected Issues (3 Samples)

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

(1) Unit 2, Multiple chilled water system deficiencies on July 30, 2018

(2) Unit 2, Root cause evaluation performed in response to May 7, 2018, Unit 2 reactor trip on August 8, 2018

(3) Unit 2, 21 SW supply header American Society of Mechanical Engineers (ASME)

Class III through-wall leakage on September 6, 2018

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

The inspectors evaluated response to the following events:

(1) Common, Security Incident Response on July 27, 2018

(2) Unit 2, Turbine trip with reactor trip on 23 steam generator high level due to a FRV failure on September 14, 2018

Licensee Event Reports (1 Sample)

The inspectors evaluated the following licensee event reports which can be accessed at https://lersearch.inl.gov/LERSearchCriteria.aspx:

(1) Licensee Event Report 05000311/2018-000-00, Manual Reactor Trip due to Elevated 21 Reactor Coolant Pump Motor Winding Temperature on August 8, 2018

The inspectors determined that it was not reasonable to forsee or correct the cause discussed in the Licensee Event Report (LER), therefore no performance deficiency was identified. The inspectors also concluded that no violation of NRC requirements occurred.

INSPECTION RESULTS

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

Green NCV 311/2018-003-01 Closed H.7 - Human Performance - Documentation 71152

(1) The inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG did not properly preplan maintenance activities in accordance with written instructions appropriate to the circumstances of safety-related chiller compressor tubing repairs and installation. Specifically, PSEG installed compressor oil tubing lines without appropriate work instructions, which led to insufficient separation, and use of a nylon strap/tie to support and route two adjacent lines of tubing, causing the tubing lines to rub and fret during normal compressor operation. Consequently, on March 5, 2018, the 22 chiller compressor tripped on low oil pressure as a result of oil leakage from tube fretting.

Description:

On March 5, 2018, the 22 chiller tripped on low oil pressure. Equipment operators responded locally to the chiller, and discovered a large pool of refrigerant oil on the floor surrounding the compressor, and evidence of spray onto various chiller skid-mounted components such as the compressor and the evaporator. PSEGs subsequent inspection determined that three adjacent copper tubing refrigerant oil lines, supported together by a nylon strap/tie in the tube routing between the compressor and the local gauge panel, had rubbed together during normal compressor operation, causing tube fretting damage and subsequent refrigerant oil leakage. The Salem chilled water system consists of three 50 percent capacity safety-related chillers per unit. The safety functions of the chilled water system are to remove sufficient heat loading from emergency control air compressors under accident conditions, and from the main control room air conditioning units under normal and accident conditions. Each chiller unit consists of a six-cylinder compressor that assists in mixing the lubricating oil with the refrigerant as part of the standard refrigeration cycle.

Upon discovery of the 22 chiller trip, PSEG operators declared the 22 chiller inoperable, and entered TS 3.7.10, which required restoration of 22 chiller to OPERABLE within 14 days, or shutdown to Mode 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. PSEG entered the tubing leak into the Corrective Action Program (CAP) under NOTF 20796701, performed corrective maintenance to replace the damaged tubing, and restored the 22 chiller to OPERABLE on March 7, 2018. PSEG performed CAP Work Group Evaluation (WGE)70199153 to evaluate the causal aspects of the 22 chiller tubing failure. The WGE determined the direct cause of the tubing failure was technicians did not install the proper supports on tubing running between the gauge panel and system components. In addition to the corrective maintenance already performed to repair the failed tubing, PSEG assigned one other corrective action to perform extent of condition (EOC) inspections on the other safety-related chillers, and directed action to document any identified discrepancies with a NOTF.

PSEG completed the EOC inspections on April 13, 2018, with no discrepancies noted.

The inspectors performed an independent EOC inspection, and identified a nylon strap/tie supporting the routing of a single tube line on 22 chiller, and identified two tube lines in contact with each other on 13 chiller. PSEG captured these observations in NOTFs 20803273, 20803418 and 20803414, took prompt action to separate the two tubing lines on 13 chiller so that they were no longer rubbing together, and performed WGE 70202710 to further evaluate the apparent inadequacies in the EOC walkdowns performed by PSEG under WGE 70199153.

The inspectors reviewed WGE 70199153, and reviewed the WGE instructional template, as described in PIA-004, Work Group Evaluation, Revision 4, which is required to be used for performance of a WGE under LS-AA-125, Corrective Action Program, Revision 25, step 4.3.2. The inspectors noted PIA-004 contained a bullet under Corrective Actions and Other Actions, which stated The actions ensure the problem / condition is corrected and aligned with cause. In response to questions from the inspectors regarding application of this standard to WGE 70199153, PSEG revised the WGE as follows:

• PSEG clarified when the tubing may have been installed under work order (WO)60073595, performed in 2009 to replace a refrigerant oil gauge on the chiller unit local gauge panel. PSEG had difficulty determining the exact time of installation due to inconsistencies in populating the tubing material in the WO parts list.

• PSEG identified a potential cause, in addition to the direct cause as stated above, that maintenance technicians used an unapproved material for the work activity when a nylon strap/tie was applied.

The inspectors reviewed WO 60073595, and identified the instructions for gauge installation referred to PSEG Technical Standard ND.DE-TS.ZZ-1014, Instrument Piping and Tubing Design Requirements, Revision 4, although no listing of copper tubing in the work order parts list. The inspectors reviewed Technical Standard ND.DE-TS.ZZ-1014, and noted it contained instructions for the routing and installation of tubing. The inspectors then reviewed two corrective maintenance work orders from chiller compressor tubing repairs in 2018, and noted inconsistencies with respect to listing tubing in the parts list, as well as references to the Technical Standard for tubing installation. Specifically, WO 60138051 for the March 2018 tubing leak on 22 chiller did not specify a tubing standard, and did not list the tubing in the WO parts list. In addition, WO 60138959 for the May of 2018 compressor replacement and tubing repairs on 21 chiller did list the compressor tubing in the parts list, but did not specify a tubing standard in the WO. The inspectors also reviewed maintenance procedures SC.MD-PM.CH-0001, ACME Chiller Compressor Inspection and Repair, Revision 25, and SC.MD-CM.CH-0001, ACME Chiller Compressor Maintenance, Revision 3, and noted general steps for tubing installation such as install all remaining tubing lines, with no further instructions on routing or supporting the tubing, nor any references to the Technical Standard.

The inspectors questioned PSEG as to whether Technical Standard ND.DE-TS.ZZ-1014 applied to the chiller compressor tubing, and if it should be incorporated into the chiller maintenance procedures. PSEG captured these questions in NOTF 20804078 for further evaluation.

The inspectors determined that PSEGs maintenance procedures and work order instructions did not contain adequate guidance for compressor tubing repairs and installation to support safety-related chiller operation. The inspectors initially considered the oil leak and trip on the 22 chiller to be a self-revealing issue. However, the inspectors reviewed the definition of NRC-identified in IMC 0612, and determined this issue was NRC-identified, because after PSEGs EOC walkdowns, the inspectors identified inadequacies (13 and 22 chillers) that PSEG was not previously aware of and were not previously captured in CAP, and because the inspectors identified inadequacies in PSEGs evaluation and EOC under WGE 70199153.

Corrective Actions: PSEG entered the tubing leak into the CAP under NOTF 20796701, performed corrective maintenance to replace the damaged tubing, and restored the 22 chiller on March 7, 2018. Additionally, PSEG performed WGE 70199153, performed EOC inspections of the tubing associated with the Unit 1 and 2 chiller compressors, performed additional EOC walkdowns and WGE 70202710 after the inspectors independently identified additional tubing deficiencies, and wrote NOTF 20804078 to address maintenance procedures SC.MD-PM.CH-0001 and SC.MD-CM.CH-0001 after the inspectors identified gaps in the written instructions regarding tubing installation.

Corrective Action References: NOTFs 20788249, 20787293, 20804078, 20801600, 20803273, 20803414, 20803418, and WGEs 70199153 and 70202710

Performance Assessment:

Performance Deficiency: The inspectors determined that not properly preplanning written instructions appropriate to the circumstances for safety-related chiller compressor tubing repairs and installation, as required under TS 6.8.1 and Appendix A of Regulatory Guide (RG) 1.33, Revision 2, was a performance deficiency that was within PSEGs ability to foresee and correct, and should have been prevented.

Screening: This finding is more than minor because it was associated with the equipment performance 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 22 chiller was inoperable and unavailable from March 5 to 7, 2018, while PSEG performed emergent repairs to repair tubing leakage that resulted in a low oil pressure trip of the compressor.

Significance: 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 the finding did not represent a loss of the chilled water system safety function, did not result in any loss of function beyond the Technical Specification allowed outage time, and did not result in the loss of any non-Technical Specification trains that were designated as high safety-significance in accordance with PSEGs maintenance rule program.

Cross-Cutting Aspect: This finding had a cross-cutting aspect of Human Performance, Documentation, because PSEG did not consistently create and maintain complete, accurate and up-to-date work order instructions for the installation of chiller compressor tubing.

Specifically, the inspectors reviewed chiller compressor tubing repair work orders from 2018, as well as chiller maintenance procedures, and identified a lack of written instructions covering how to properly route or support the tubing. (H.7)

Enforcement:

Violation: TS 6.8.1, Procedures and Programs, requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of RG 1.33, Revision 2. RG 1.33, Section 9.a, Procedures for Performing Maintenance, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, or documented instructions, appropriate to the circumstances.

Contrary to the above, PSEG procedures SC.MD-PM.CH-0001 and SC.MD-CM.CH-0001, as well as work order instructions, did not properly preplan documented instructions appropriate to the circumstances of compressor tubing installation, from the establishment of the procedures until present. Specifically, PSEG installed 22 chiller compressor refrigerant oil tubing lines without sufficient separation, and used a nylon strap/tie as an apparent method to support and route two adjacent lines of tubing, such that the lines rubbed together and fretted during normal compressor operation. Consequently, on March 5, 2018, the 22 chiller compressor tripped on low oil pressure as a result of oil leakage from tube fretting.

Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy.

Failure to Follow Generic Letter 89-13 Program Procedure Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems

Green NCV 311/2018-003-02 Closed P.3 - Problem Identification and Resolution

- Resolution 71152

(3) The inspectors identified a Green NCV of 10 CFR Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not adequately follow Generic Letter (GL) 89-13 program procedure steps for performing inspections of the safety-related SW piping and components. Specifically, certain American Society of Mechanical Engineers (ASME) Nuclear Class III pressure retaining components were not inspected during SW system internal pipe inspections, as required by ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 8, during SW system internal pipe inspections.

Consequently, protective internal coating degradation on the 21 SW supply header two-inch branch connection was not identified and corrected, which resulted in through-wall leakage and significant weld material loss due to corrosion.

Description:

On June 4, 2018, inspectors identified corrosion and apparent pinhole leakage from a two-inch butt-welded branch connection on the 21 SW supply header, and immediately informed Operations. The 21 SW header is one of two safety-related 26-inch SW headers on Salem Unit 2, both of which are classified as moderate energy, ASME Nuclear Class III pressure boundaries. Operations immediately responded to inspect the condition, and confirmed there was through-wall leakage in an ASME Class III pressure boundary.

Operations documented the issue under NOTF 20796701, and screened the condition as Operable but Degraded, based on reasonable assurance of structural integrity due to apparent microbiological (MIC)-induced pinhole leakage, and pertinent operating experience of MIC-induced service water leakage at Salem. Additionally, Operations requested a Prompt Determination of Operability from Engineering to evaluate and characterize the flaw to ensure adequate structural integrity. PSEG immediately began to plan non-destructive examination (NDE) as part of the effort to evaluate and characterize the flaw. The inspectors reviewed IMC 0326, Appendix C, Sections C.12 (Flaw Evaluation) and C.13 (Operational Leakage from ASME Code Class 1, 2, and 3 Components), and determined PSEGs immediate determination of operability was reasonable, with the appropriate prioritization given to the performance of NDE to support the Prompt Determination of Operability.

On June 5, 2018, PSEG performed a radiography examination in an effort to characterize the weld flaw in support of the structural integrity evaluation. The radiography results revealed significant wall thinning and volumetric loss around the entire circumference of the weld, such that margin above the minimum required wall thickness could not be demonstrated to support weld structural integrity. Operations subsequently declared the 21 SW header inoperable on June 5, 2018, and entered the action statement for TS 3.7.4, which required restoration of 21 SW header to OPERABLE within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or shutdown to Mode 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

PSEGs current ASME In-service Inspection interval requires conformance with the ASME Boiler and Pressure Vessel (BPV) Code, 2004 Edition. ASME BPV Code,Section XI, Division 1, Subsection IWC 3122, requires repair, replacement, or analytical evaluation of the flaw. Given the very limited remaining wall thickness on the weld, and the potential to incur elevated operational leakage on the safety-related 21 SW header PSEG, determined that immediate replacement of the branch connection was the preferred option to comply with the ASME code. When performing a replacement,Section XI requires conformance to the original construction code, or American Nuclear Standards Institute (ANSI) Nuclear Power Piping Standard B31.7, as specified in UFSAR Sections 3.2.2.2 and 9.2.1. After declaring the 21 SW header inoperable, PSEG subsequently isolated the 21 SW header, successfully replaced the two-inch welded connection to restore conformance with the code requirements, performed as-left NDE measurements to verify weld integrity, and declared the 21 SW header OPERABLE on June 7, 2018. In addition, PSEG performed NDE of the pipe header area surrounding the branch connection, and verified all measurements were greater than the minimum-required wall thickness. PSEG engineering estimated the worst-case leakage would not cause a loss of safety function of the 21 SW header, assuming a complete failure of the welded connection, because the leakage was bounded by the system design margin demonstrated in existing station calculations. PSEG did not initially document this determination, but after subsequent questions from the inspectors, PSEG documented a qualitative summary of the determination under order 70202757-0010, and assigned an action to document the full Technical Evaluation under 70202757-0030. The inspectors performed an independent review of the header NDE results, PSEGs worst-case leak estimation, and PSEGs qualitative determination, and the inspectors determined that there was not a past operability concern associated with the SW header leak that was identified on June 4, 2018.

PSEG performed a CAP evaluation under Engineering Reliability Evaluation (ERE)70200947, and determined the cause of the equipment failure was most likely attributed to inner-diameter-initiated galvanic corrosion due to the presence of brackish service water on a dissimilar metal weld. Specifically, there was a stainless steel two-inch branch connection with a carbon steel pipe header and weld-o-let. In addition, PSEG Laboratory and Testing Service (LTS) performed a failure analysis of the two-inch weld-o-let, and determined that the weld failed due mainly to the delamination of the protective internal coating. Contributing factors included crevice corrosion behind an incomplete original construction weld that used a 316 stainless steel (SS) backing ring and galvanic corrosion caused by contact between dissimilar welded alloys. Additionally, PSEGs ERE determined that SW supply and return header inspection activities that were implemented under recurring work order instructions performed every three years in response to GL 89-13, Service Water System Problems Affecting Safety-Related Equipment, did not include specific guidance to inspect and correct deficiencies associated with internal protective coating on the vent and drain branch connections. In response, PSEG performed EOC visual inspections of the seven additional two-inch branch connections (two connections per each supply and return header in 21 and 22 trains, respectively) on the exposed portions of the safety-related 21 and 22 SW headers, and determined there was no observable leakage. PSEG assigned additional internal and NDE inspections of the two-inch vent branch connections as a follow-up action from ERE 70200947.

The inspectors reviewed PSEG procedure ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 8, and noted: step 4.3.7 required inspection of piping and components for protective coating degradation; step 4.3.8 required documenting and trending all inspections and monitoring of corrosion and protective coating failures; and, step 4.3.9 required determination of the appropriate corrective actions based upon the inspection results. The inspectors reviewed PSEG design specification S-C-MPOO-MGS-0001, Service, Fresh and Salt Water, Revision 13, and noted that coal tar enamel internal lining was required for the moderate energy, Class III, SW system, including the two-inch test and drain connections as specified in station drawing 219593. The inspectors reviewed previous GL 89-13 SW inspection work orders and internal piping inspection videos, and noted the two-inch test and drain connections were not inspected during the internal piping inspections.

PSEGs ERE stated that NOTF 20765041 (dated May 2017) had previously identified 21 SW supply header piping corrosion and external coating degradation in the vicinity of the two-inch branch connection. PSEG stated that the NOTF did not adequately address the condition, because no actions were taken in response to NOTF 20765041. The NOTF characterized the observed conditions to be a result of historical leakage from the threaded vent cap, and did not describe active leakage. The inspectors agreed with PSEGs ERE determination that the NOTF was addressed inadequately, but the inspectors concluded that without the presence of any active leakage corrective actions would not be required. Therefore, the inspectors determined that ER-AA-430, steps 4.3.7 through 4.3.9, was the appropriate requirement for PSEG to identify and correct the two-inch branch connection internal coating degradation.

Corrective Actions: PSEG entered the ASME leak into the CAP under NOTF 20796701; performed corrective maintenance to replace the two-inch welded branch connection on June 7, 2018; performed UT examination of areas surrounding the branch connection weld on the SW header to verify greater than code-allowable wall thickness; performed EOC visual inspections of the other accessible branch connections; and, assigned EOC NDE and internal inspections of the other accessible branch connections. Additionally, PSEG performed ERE 70200947, conducted a failure analysis to evaluate the cause of the weld failure, and wrote NOTF 20799781 to change to the recurring work order instruction template that implements the GL 89-13 inspections required under ER-AA-430.

Corrective Action References: NOTFs 20796701, 20799781, 20804817, 20804843, 20804846, and ERE 70200947

Performance Assessment:

Performance Deficiency: The inspectors determined that not adequately performing SW system inspections in accordance with ER-AA-340, steps 4.3.7 through 4.3.9, was a performance deficiency that was within PSEGs ability to foresee and correct, and should have been prevented.

Screening: This finding is more than minor because it was associated with the equipment performance 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 21 SW header was inoperable and unavailable from June 5 to June 7, 2018, while PSEG performed emergent repairs to replace a through-wall leak and significantly degraded weld in an ASME Class III pressure boundary.

Significance: The inspectors assessed the significance of the finding using IMC 0609.04, and IMC 0609, Appendix A, Exhibit 2. The inspectors determined that this finding was of very low safety significance (Green), because the finding did not represent a loss of the SW system safety function, did not result in any loss of function beyond the TS-allowed outage time, and did not result in the loss of any non-TS trains that were designated as high safety-significance in accordance with PSEGs maintenance rule program.

Cross-Cutting Aspect: This finding had a cross-cutting aspect of Problem Identification and Resolution, Resolution, because PSEG did not take effective corrective actions to address 21 SW supply header piping corrosion and external coating degradation at the two-inch vent branch connection after it was identified in May 2017 under NOTF 20765041, over one year prior to identification of the through-wall leak. Specifically, the NOTF identified degraded conditions that were characterized as the result of historical leakage from the threaded vent cap (no active leakage was described), but no actions were assigned to further evaluate or correct the condition. (P.3)

Enforcement:

Violation: 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires activities affecting quality shall be prescribed by procedures, and shall be accomplished in accordance with these procedures. PSEG procedure ER-AA-340, Generic Letter 89-13 Program Implementing Procedure, Revision 8, steps 4.3.7 through 4.3.9, required inspection of piping for protective coating degradation, documenting and trending corrosion and protective coating failures, and determination of appropriate corrective actions based on the inspection results.

Contrary to this, from the establishment of GL 89-13 program inspections until present, PSEG did not accomplish GL 89-13 program inspections in accordance with procedure ER-AA-340.

Specifically, PSEG performed 89-13 inspections of the 21 SW header on a three-year periodicity, but did not inspect the two-inch branch connections for internal protective coating degradation, did not document and trend corrosion and internal protective coating failures in the two-inch branch connections, and therefore did not determine the appropriate corrective actions based on the inspection results. Consequently, on June 4, 2018, a through-wall leak was identified by the inspectors at the two-inch vent connection for the 21 SW supply header, which resulted in prompt NDE and identification of significant weld degradation by PSEG, and subsequent isolation of the 21 SW supply header to replace the welded branch connection.

Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy.

Failure to Follow Maintenance Procedure 71152

(1) This violation of very low safety significant was identified by PSEG, has been entered into PSEGs CAP, and is being treated as a Green NCV, consistent with Section 2.3.2 of the Enforcement Policy.

Violation: 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires activities affecting quality shall be prescribed by procedures, and shall be accomplished in accordance with these procedures. PSEG procedure MA-AA-716-011, Work Execution and Closeout, Revision 17, step 4.13.5, required order operations to be completed after the preventive maintenance WO was taken Technically Complete, or TECOd.

Contrary to the above, preventive maintenance WOs 30319825 and 30320738 were TECOd by mechanical maintenance, on March 2 and April 9, 2018, respectively, without completing all of the WO operations. Specifically, maintenance technicians performed the monthly thermography on the 22 chiller evaporator divider plate gasket and took the preventive maintenance work order TECO and did not perform MA-AA-716-011, step 4.13.5 to complete operation 0020 by notifying engineering that the thermography results were available for review. Consequently, leakage past the divider plate gasket went undetected from March 2 to April 30, 2018, until quarterly compressor thermography detected crankcase temperature above the action level on April 30, 2018. Maintenance immediately notified Operations of the elevated compressor temperature, and the 22 chiller was declared inoperable and removed from service emergently on April 30, 2018. Subsequent disassembly and inspection revealed internal compressor damage and pieces of the evaporator divider plate gasket in the compressor filter housing. PSEG replaced the compressor and restored the 22 chiller to OPERABLE on May 4, 2018. The inspectors documented an observation, related to this PSEG-identified violation, in the observation box below.

Significance/Severity Level: The inspectors evaluated this finding using IMC 0609.04, and IMC 0609, Appendix A, Exhibit 2. The inspectors determined that the finding was of very low safety significance (Green).

Corrective Action References: NOTFs 20793065, 20793429, 20793476, and ERE 70200400

Observation (71152 Annual Sample: Multiple chilled water system deficiencies)71152

(3) Performance Monitoring of the Safety-Related Chillers

The inspectors reviewed NCV 05000272; 311/2015002-06, Inadequate Chiller Maintenance Procedures, and noted historical challenges with chiller evaporator divider plate gasket leakage. Additionally, the inspectors reviewed Apparent Cause Evaluation (ACE) 70181604, and noted that PSEG created corrective action #1 (operation 0030) to install a new evaporator divider plate gasket design in all six of the chillers across both units. PSEG ERE 70200400, performed in response to the 22 chiller emergent inoperability described in the PSEG-identified violation above, identified that the new gasket design was scheduled to be installed in 22 chiller in December of 2017, but was subsequently cancelled through the use of the scope deletion request process. The basis for cancellation was two-fold: 1) an elimination strategy was scheduled to install new chiller units on both units under design change packages 80111049 and 80112165, respectively; and 2) continued verification that the gaskets were properly seated was being performed through existing chiller performance monitoring.

The inspectors concluded that PSEG followed the process for scope deletion to cancel installation of the new gasket design on 22 chiller. The inspectors also noted a turnover of the chiller system engineer occurred in early 2018, just prior to missed monthly thermography data reviews for March and April. Therefore, the inspectors observed that effective chiller performance monitoring and completion of all work order operations will remain very important to ensure reliable chiller operation, until installation of the new chiller units. With the exception of the above-described PSEG-identified violation, the inspectors did not identify additional performance deficiencies.

Observation (71152 Annual Sample: 21 SW supply header through-wall leakage)71152

(3) ASME Class III Flaw Evaluations to Support the Operability Determination Process

The inspectors reviewed PSEGs immediate operability determination associated with the ASME Class III leak on the 21 SW header, conducted on June 4, 2018, under NOTF 20796701. The inspectors noted that Operations screened the condition as Operable but Degraded, based on reasonable assurance of structural integrity due to apparent MIC-induced pinhole leakage, and pertinent operating experience of MIC-induced service water leakage at Salem. The inspectors conducted a historical review of Operability Evaluations focusing specifically on evaluations performed to address through-wall leakage in Class III sections of the SW system at Salem Units 1 and 2. While the inspectors noted several recent examples of through-wall leakage caused by MIC in 2016 and 2014, the inspectors noted these examples mostly involved welds in isolable, small diameter tubing that did not require flaw evaluations to support the operability determination process. The inspectors then requested, from PSEG engineering, examples of Operability Evaluations involving flaw evaluations performed in response to Class III Service Water leakage. PSEG provided one example dating back to 2005 (OD 05-12), performed under 70048937. The inspectors noted that the analytical flaw evaluation was performed by a third party to support PSEGs Operability Determination.

The inspectors concluded that PSEG did not have pertinent experience performing flaw evaluations in response to SW leaks to support the Operability Determination process. As a result, PSEG did not formerly pursue evaluation of SW pipe header structural integrity during the Operability Determination process in response to the through-wall leak identified on June 4, 2018, and instead focused on structural integrity of the welded branch connection that was localized to leak location. PSEG captured this observation under NOTF 20807062. The inspectors determined this observation was not a performance deficiency, because pertinent operating experience of the apparent degradation mechanism (in this case, MIC), as originally identified on June 4, 2018, did exist to support reasonable assurance in the immediate Operability Determination, as discussed in IMC 0326, Appendix C, Sections C.12 and C.13.

Additionally, the inspectors determined that PSEG exhibited appropriate conservative decision making that supported nuclear safety in the decision to perform prompt repairs versus prolonged operation with a degraded condition.

EXIT MEETINGS AND DEBRIEFS

The inspectors confirmed that proprietary information was controlled to protect from public disclosure.

• On September 14, 2018, the inspector presented the radiation safety inspection results to Mr. D. Mannai, Sr. Director Regulatory Operations, and other members of the licensee staff.

• On October 10, 2018, the inspectors presented the quarterly resident inspector inspection results to Mr. Charles McFeaters, Salem Vice President, and other members of the PSEG staff.

DOCUMENTS REVIEWED

71111.01 - Adverse Weather Protection

Notifications (*initiated in response to inspection)

20799478*

20804067*

Procedures

SC.OP-AM.FLX-0050, Predicted Hurricane Storm Surge, Revision 2

OP-AA-108-111-10001, Severe Weather and Natural Disaster Guidelines, Revision 15

71111.04 Equipment Alignment

Drawings

205248, Salem Unit 1 Auxiliary Building Control Area Air Conditioning and Ventilation, Sheet 1,

Revision 37

205248, Salem Unit 1 Auxiliary Building Control Area Air Conditioning and Ventilation, Sheet 2,

Revision 51

Notifications (*initiated in response to inspection)

20799420

Procedures

S1.OP-SO.PC-0001, Switchgear and Penetration Areas Ventilation Operation, Revision 19

Work Orders

285580

30307813

30307542

50190494

71111.05 - Fire Protection

Notifications (*initiated in response to inspection)

20799936*

20800816*

20803887*

Procedures

FP-SA-2547, Salem Pre-Fire Plan: Unit 2 Mechanical Penetration Area, Revision 0

FP-SA-2527-F1, Salem Pre-Fire Plan: Unit 2 Mechanical Penetration Area Map 1, Revision 0

FP-SA-2527-F2, Salem Pre-Fire Plan: Unit 2 Mechanical Penetration Area Map 2, Revision 0

71111.06 - Flood Protection Measures

Notifications (*initiated in response to inspection)

20800390*

71111.11 - Licensed Operator Requalification Program and Licensed Operator

Performance

Notifications (*initiated in response to inspection)

20801208

20801016*

20801071*

20801349

20801348

Procedures

S2.OP-IO.ZZ-0004, Power Operation, Revision.80

Other

Examine Scenario Guides, ESG 1804 and ESG-1805

71111.12 - Maintenance Effectiveness

Notifications (*initiated in response to inspection)

20775715

20775877

20778080

20778109

20778575

20782781

20783332

20789687

20793442

20793751

20794424

20795393

20795743

20796667

20797427

20799672

20799639

20795500

20803834

20804820*

20806021*

Work Orders

70179610

70195913

70196422

200479

Other

(A)(1) Evaluation Eval-S-RM-00101, 1R1B Channel 1 Radiation Monitor (U1) 1R1B Channel 2

Radiation Monitor (U2)

(A)(1) Evaluation Eval-S-RM-00102, 1R1B Channel 1

ERE 70196422, 1R1B Channel 2 Failing High During Daytime

MRC Trend - Radiation Monitors, dated July 9, 2018

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Notifications (*initiated in response to inspection)

20794767

20798067

20788604

20799942*

20800731*

20801166*

20801439*

20801579

20801852

20801858

20802261

20803701

20803842

20803845

20803856

20803950

20803951

20804105

20804112

20804113

20804117

20804118

20804128

20804133

20804141

20804142

20804144

20804717

20804802*

20804894

20806210

20806223

20806476

Procedures

S1.OP-AB.GEN-0001, Main Generator Abnormal Stator Conditions, Revisions 10 and 11

SC.OP-AM.TSC-0009, Flooding Containment Utilizing Portable Diesel Driven Pump, Revision 2

SC.OP-PM.FLX-0001, FLEX Standby Equipment Status Checks, Revision 3

WC-AA-105, Work Activity Risk Management, Revision 7

Work Orders

30139022

30145467

60139405

60139574

60139885

70182594

202202

Other

ACM 18-010, 21-24BF19 Elevated Vibrations, Revisions 0, 1, 2 and 3

Licensed Operator Training Lesson Plan NOS05ODFWCS-02, Ovation Advanced Digital

Feedwater Control System

OTDM 18-005, Unit 2 Feedwater and Condensate / 23BF19, Revision 1

VTD 119162, BF19 AOV Digital Positioner Vendor Manual

71111.15 - Operability Determinations and Functionality Assessments

Notifications (*initiated in response to inspection)

20799821*

20800086

20801434

20802013*

20801260

20801255

20801259

20801365

20801362

20804448*

Work Orders

201360

60139371

Other

S-C-SW-MDC-1350, Service Water System Mode Ops Analysis, Revision 8

RG 1.97, Criteria for Accident Monitoring Instrumentation for Nuclear Power Plants, Revision 4

NUREG-0737, Clarification of TMI Action Plan Requirements

71111.18 Plant Modifications

Notifications (*initiated in response to inspection)

20802380*

20801692

20802023

Procedures

VSH.MD-GP.ZZ-0199, Inservice Temporary Leak Repair, Revision 7

Work Orders

60139656

Other

TEAM Inc., Design Package 1401-000005-37, Job 4107493

71111.19 Post Maintenance Testing

Notifications (*initiated in response to inspection)

20800463

20803661

20803600

Work Orders

259200

203034

60139504

30314032

288265

30321309

60138966

205482

71111.22 Surveillance Testing

Notifications (*initiated in response to inspection)

20654970

Work Orders

203542

71114.06 - Drill Evaluation

Other

Examine Scenario Guides, ESG 1807 and ESG-1808

71151 - Performance Indicator Verification

Notifications (*initiated in response to inspection)

20791642

Other

Unit 1 and Unit 2 Unavailability and Unreliability Indices for June 2017 and June 2018 for

Residual Heat Removal and Heat Removal Systems

71152 - Problem Identification and Resolution

CAP Evaluations

ACE 70051392, 11 Chiller Tripped on Freeze Protection

ACE 70156720, 21 Chiller Tripped on Low Oil Pressure

ACE 70181604, Chiller Divider Plate Gasket Leakby

ERE 70196614, 22 Chiller Running Hot

ERE 70200400, 22 Chiller Parameters Degrading

ERE 70200903, Autopsy for 21 Chiller Compressor

ERE 70200947, 21 SW Nuke Header Supply Header Vent Leak

EQACE 70179986, 22 Chiller High Suction Pressure

RCE 70200390, Manual Reactor Trip due to Elevated 21 RCP Motor Winding Temperature

WGE 70199153, 22 Chiller Tripped due to Oil Leak, Revisions 0 and 1

WGE 70202710, 22 Chiller Tie Wraps Holding Tubing

Drawings

203525, Units 1 and 2 Control Rooms Recorder Panels 1RP4 and 2RP4, Revision 41

219563, Service Water Piping to Auxiliary Building, Sheet 1, Revision 23

S2-ISI-342, Salem Unit 2 Service Water Nuclear Area, Sheet 1, Revision 83

Notifications (*initiated in response to inspection)

20765041

20776461

20777171

20788294

20791672

20792574

20793065

20793116

20793429

20793465*

20793476

20793813

20793944

20793974

20793987

20793988

20793989

20794630

20795251

20795497

20795909

20796274

20796452

20796523

20796561

20796701*

20798100*

20798968

20799715*

20799780

20799781

20799918*

20800091*

20800144*

20800280*

20801600*

20801957*

20803273*

20803414*

20803418*

20803584*

20804078*

20804422*

20804817*

20804843

20804846

Procedures

ER-AA-210-1005, Corporate Engineering, Revision 0

ER-AA-2001-1003, Equipment Reliability Risk Management Process, Revision 0

ER-AA-2003, System Performance Monitoring and Analysis, Revision 11

ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 8

ER-AA-340-1001, GL 89-13 Program Implementation Instructional Guide, Revision 9

ER-AA-340-1002, Service Water Heat Exchanger and Component Inspection Guide, Revision 9

MA-AA-716-003, Tool Pouch / Minor Maintenance, Revision 12

MA-AA-716-010-1000, Maintenance Planning, Revision 11

MA-AA-716-011, Work Execution and Closeout, Revisions 17 and 18

OP-AA-108-115, Operability Determinations and Functionality Assessments, Revision 4

S2.OP-ST.CH-0004, Chilled Water System - Chillers, Revision 23

SC.IC-GP.RC-0006, Reactor Coolant Pumps Instrument Removal, Revision 9

SC.MD-CM.CH-0001, ACME Chiller Compressor Maintenance, Revision 3

SC.MD-PM.CH-0001, ACME Chiller Compressor Inspection and Repair, Revision 25

Work Orders

60073595

60138051

60138585

60138959

60139163

Other

ASME Code Case N-513-3, Approved January 26, 2009

ASME Section XI, 2004 edition

Crane Technical Paper 410, Flow of Fluids through Valves, Fittings and Pipe, 25th printing - 1991

ISI Program Plan, Salem Generating Station, Unit 2, Fourth Interval, Revision 3

LTS Service Report, Failure Analysis of the SW Nuclear Header Nipple Weld-o-let, Salem

Generating Station, dated July 25, 2018

LTA Issue S-15-0075, Unit 1 and 2 Chiller Evaporators Divider Plate Gaskets

Operability Evaluation 16-023, 70190257, Evidence of Through Wall Leak in Service Water

Operability Evaluation 16-022, 70189048, Through Wall Leak in Stainless Tubing

Operability Evaluation 16-004, 70183883, Leak in Service Water Weld

Operability Evaluation 14-001, 70163033, ASME Weld Leak

Operability Determination 05-012, 70048937, ASME Leak

PIA-004, Work Group Evaluation (Template), Revision 4

PORC Meeting S2018-004 Package, Dated May 7, 2018

PSEG Nuclear Repair Program Manual, Revision 23

PSEG Response to Generic Letter 89-13, Service Water Problems Affecting Safety Related

Equipment, Dated January 26, 1990

NCV 005000272; 311/2015002-06, Inadequate Chiller Maintenance Procedure

ND.DE-TS.ZZ-1014, Instrument Piping and Tubing Design Requirements - Salem Generating

Station, Revision 4

SC.DE-TS.ZZ-2039, SPEG Nuclear L.

L.C. Technical Standard - Cable Termination Methods,

Revision 7

Temporary Standing Order 2018-015: Units 1 and 2 RCP Stator Winding Alternate Indications

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

Procedures

HLA/IPA Brief Checklist, S2C23 End of Cycle Startup and Power Ascension

OP-AA-108-108, Unit Restart Review, Revision 13

OP-AA-108-114, Post Transient Review, Revision 5

OP-SA-108-114-1001, Post-Trip Data Collection Guidelines, Revision 4

REMA Form, U2C23 Startup Following Feedwater Trip

SC.RE-RA.ZZ-0002, Inverse Count Rate Ration during Reactor Startup, Revision 12

S2.OP-IO.ZZ-0003, Hot Standby to Minimum Load, Revision 45

S2.OP-IO.ZZ-0103, Hot Standby to Minimum Load Administrative Requirements, Revision 13

Notifications (*initiated in response to inspection)

20736472

20803839

20803844

20803846

20803841

20803842

20803946

20803947

20804109

20804120

20804132

20804135

20804140

20804223

Other

EN 53606, Dated September 14, 2018

Sequence of Events Report, Dated September 14, 2018