IR 05000354/2017003

Integrated Inspection Report 05000354/2017003

ML17319A218
Person / Time
Site:	Hope Creek
Issue date:	11/14/2017
From:	Fred Bower Reactor Projects Branch 3
To:	Sena P Public Service Enterprise Group
References
IR 2017003
Download: ML17319A218 (42)

Text

T. Joyce UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713 November 14, 2017 Mr. Peter P. Sena, III President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 - INTEGRATED INSPECTION REPORT 05000354/2017003

Dear Mr. Sena:

On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station (HCGS). On October 11, 2017, the NRC inspectors discussed the results of this inspection with Mr. Edward Casulli, HCGS Plant Manager, and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented one NRC-identified and one self-revealing finding of very low safety significance (Green) in this report. Both of these findings involved violations of NRC requirements. 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 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 HCGS. 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 HCGS.

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 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Fred Bower, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket No. 50-354 License No. NPF-57

Enclosure:

Inspection Report 05000354/2017003 w/Attachment: Supplementary Information

REGION I==

Docket No. 50-354 License No. NPF-57 Report No. 05000354/2017003 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Hope Creek Generating Station (HCGS)

Location: Hancocks Bridge, NJ 08038 Dates: July 1, 2017 through September 30, 2017 Inspectors: J. Hawkins, Senior Resident Inspector S. Haney, Resident Inspector J. Furia, Senior Health Physicist Approved By: Fred Bower, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report (IR) 05000354/2017003; 07/01/2017 - 09/30/2017; Hope Creek Generating

Station; Operability Determinations and Functionality Assessments, Problem Identification and Resolution.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. The inspectors identified one NRC-identified finding and one self-revealing finding of very low safety significance (Green), both of which were non-cited violations (NCVs). The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated April 29, 2015.

Cross-cutting aspects are determined using IMC 0310, Aspects Within Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated November 1, 2016. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 6.

Cornerstone: Mitigating Systems

Green.

A self-revealing finding of very low safety significance (Green) 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 when PSEG did not perform an adequate operability determination in accordance with procedure OP-AA-108-115, Operability Determinations & Functionality Assessments,

Revision 4. Specifically, an operability determination evaluating a ground fault alarm received following D emergency diesel generator (EDG) post-maintenance testing on June 23, 2017 was narrowly focused, and resulted in operators inappropriately declaring the D EDG operable. Subsequently, the EDG failed to start for a surveillance test on June 25, 2017. PSEGs immediate corrective action (CA) was to replace the failed D EDG speed switch. PSEGs CAs also included revision to the applicable attachments in the alarm response procedure guidance such that operators are directed to verify and assess operability, and document technical specification compliance, for any supported equipment that was placed into service or removed from service when the ground indications occurred.

The issue was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). For a 26-hour period between 10:00 p.m. on June 23 through 12:02 a.m. on June 25, PSEG incorrectly considered the D EDG to be available and capable to perform its safety function in an emergency, when in fact, the D EDG was inoperable. In accordance with IMC 0609.04,

Initial Characterization of Findings, dated October 7, 2016, and Exhibit 2 of IMC 0609,

Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its technical specifications (TS) allowed outage time, did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors determined this finding had a cross-cutting aspect in the area of Human Performance, Resources, in that PSEG did not ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, PSEGs inadequate alarm procedure guidance resulted in the focus of the operability determination concentrating on the direct current (DC) distribution system.

[H.1] (Section 1R15)

Green.

The inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(1), Requirements for monitoring the effectiveness of maintenance at nuclear power plants (maintenance rule). Specifically,

PSEG did not demonstrate that the performance of the reactor protection system (RPS)was effectively controlled through the performance of appropriate preventive maintenance, did not establish adequate goals and monitoring, and did not take adequate corrective actions when the system experienced repetitive failures due to mechanical binding of the

1. 4 main turbine stop valve (MSV) limit switch arm causing unexpected delays in the RPS trip actuation times in excess of surveillance test criteria. PSEGs immediate corrective action was to initiate notification (NOTF) 20742337 and new operations to order 70192748 to revise the RPS maintenance rule (a)(1) action plan and plan the replacement of the limit switch during the next scheduled or forced outage.

The issue was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG not establishing new goals and monitoring, as well as not performing adequate corrective actions for the mechanical binding of the #4 MSV limit switch arm that was causing unexpected delays in the RPS trip actuation times that adversely impacted the reliability of those systems. The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, dated June 19, 2012, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its TS-allowed outage time; or represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Therefore, the inspectors determined the finding was

Green.

The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that PSEG did not thoroughly evaluate the repetitive issues with the #4 MSV limit switch to ensure that resolutions address the causes and extent of conditions commensurate with their safety significance. More specifically, PSEG did not properly classify, prioritize, and evaluate the issue according to its safety significance allowing the cause to be undetermined and the monitoring of the RPS to be ineffective. [P.2] (Section 4OA2.3)

REPORT DETAILS

Summary of Plant Status

Hope Creek Generating Station began the inspection period at full rated thermal power (RTP).

On September 23, 2017, operators reduced power to approximately 76 percent RTP to support planned main turbine valve testing, control rod scram time and settle testing, control rod sequence exchange, and plant repairs. The unit was returned to 100 percent RTP on September 25, 2017. The unit remained at or near full 100 percent RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

External Flooding

a. Inspection Scope

During the week of September 18, the inspectors performed an inspection of the external flood protection measures for HCGS. The inspectors reviewed TSs, procedures, design documents, and Updated Final Safety Analysis Report (UFSAR),which depicted the design flood levels and protection areas containing safety-related equipment to identify areas that may be affected by external flooding. The inspectors conducted a general site walkdown of all external areas of the plant, including the auxiliary building, EDGs, and service water intake structure to ensure that PSEG erected flood protection measures in accordance with design specifications. Where applicable the inspectors determined installed flood seal service life and verified that adequate procedures existed for inspecting the installed seals. The inspectors also reviewed operating procedures for mitigating external flooding in advance of severe weather on September 9, to confirm that, overall, PSEG had established adequate measures to protect against external flooding events and, more specifically, that credited operator actions were adequate. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial System Walkdown (71111.04Q - 4 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

• A reactor feedwater pump (RFP) following high vibrations during the week of July 17

• A and C core spray (CS) system during planned maintenance on the B and D CS system during the week of August 16

• Reactor core isolation cooling (RCIC) and B residual heat removal (RHR) steam leak detection system after an analog module failure during the week of August 29

• A, C, and D EDGs with the B EDG inoperable for planned maintenance during the week of September 27 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders, NOTFs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted the systems performance of its intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the corrective action program (CAP)for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection

Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

• FRH-III-151, Turbine Building, A RFP Turbine, on July 24

• FRH-II-531, Auxiliary Building, Diesel Generator Rooms on July 31

• Review of compensatory measures for the replacement of a fire panel (00-C-340) on August 3

• FRH-II-532, Auxiliary Building, Lower Control Equipment for RCIC and B RHR steam leak detection on August 29

• Review of the use of continuous fire watches over the last 2 years for compliance with fire protection procedures and fire watch expectations on September 6

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to identify internal flooding susceptibilities for the site. The inspectors review focused on the potential internal flooding from spent fuel pool. The review verified the adequacy of equipment seals located below the flood line, floor and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers. It assessed the adequacy of operator actions that PSEG had identified as necessary to cope with flooding in this area and also reviewed the CAP to determine if PSEG was identifying and correcting problems associated with both flood mitigation features and site procedures for responding to flooding.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on September 18, which included the response to a tornado inside the protected area coincident with a loss of an EDG selected to automatically start as required and an anticipated transient without scram (ATWS). The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed planned maintenance on a scram discharge volume (SDV) solenoid valve on July 6, and a planned down power support planned main turbine valve testing, control rod scram time and settle testing, control rod sequence exchange, and plant repairs on September 23. The inspectors observed reactivity manipulations to verify that procedure use and crew communications met established expectations and standards. The inspectors observed pre-job briefings to verify that the briefings met the criteria specified in OP-AA-101-111-1004, Operations Standards, Revision 7, and HU-AA-1211, Pre-Job Briefings, Revision 13. Additionally, the inspectors observed licensed operator performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance work orders, and maintenance rule (MR) basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the MR. For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 10 CFR 50.65 and verified that the (a)(2)performance criteria established by PSEG staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across MR system boundaries.

• Review of multiple B fuel pool cooling (FPC) pump trips on June 14 and July 21

• Review of the A and B main steam line and A and F main steam safety relief valve (SRV) discharge line support snubbers and spring hangers on August 1

• Review of PSEG Nuclear Parts Quality Program and Parts Quality Initiative failures on September 12 (Quality Control)

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.

The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid, and applicable requirements were met.

• Review of the protected equipment and risk assessment for high risk troubleshooting and replacement of a SDV solenoid valve on July 6

• Review of the risk assessment for the troubleshooting on the B emergency core cooling system and RCIC trip unit gross failure on July 19

• Review of the protected equipment and risk assessment for the A EDG lockout relay actuation following surveillance run on July 31

• Review of the protected equipment and risk assessment for B and D CS planned maintenance on August 16

• Review of the protected equipment and risk assessment for actions when removing fire in (a)(4) equipment (B EDG) from service for planned maintenance during the week of September 25

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions based on the risk significance of the associated components and systems:

• Review of the D EDG speed switch failure on June 25

• Review of an operability evaluation (OPEVAL) for the high pressure coolant injection (HPCI) battery capacity and available voltage calculation on July 26

• Review of the suppression chamber to drywell vacuum breaker failure to stroke on July 26

• Review of the B.5.b battery and charger when the equipment was found missing and unavailable on August 22

• Review of the RCIC and B RHR steam leak detection system after an analog module failure on August 23 The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to PSEGs evaluations to determine whether the components or systems were operable. The inspectors confirmed, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

Introduction.

A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings was identified when PSEG did not perform an adequate operability determination in accordance with procedure OP-AA-108-115, Operability Determinations & Functionality Assessments, Revision 4. Specifically, an operability determination evaluating a ground fault alarm received following D EDG post-maintenance testing on June 23, 2017 was narrowly focused, and resulted in operators inappropriately declaring the D EDG operable. Subsequently, the EDG failed to start for a surveillance test on June 25, 2017.

Description.

The HCGS utilizes four EDGs to serve as the standby electrical power source to their safety-related emergency 4.16 kilovolt buses. The control circuit of each EDG contains an electronic speed switch assembly. The speed switch enables and disables select alarms and controls key engine auxiliary components based on engine speed. On June 18, 2017, PSEG began a planned maintenance window on the D EDG that included relay replacements and the first installation of a new style speed switch (Model 416) at HCGS. The D EDG was started and run on June 23, 2017 for its post-maintenance testing. Upon securing the D EDG, a ground fault alarm was received on its 125 VDC bus (1DD417) at 9:26 p.m. Operators returned the D EDG to service and declared it operable at 10:00 p.m. PSEG generated NOTF 20769533 to document the ground fault alarm. The NOTF described the timing of the alarm coinciding with the EDG shutdown and approximated at what engine speed the alarm came in. The NOTF listed a potential challenge to D EDG operability due to indications of a ground on the 10D417 panel. Additionally, the NOTF recommended an action to investigate recent work on the D EDG for possible causes for ground indications. Operators subsequently screened the 125 VDC distribution system as operable, and indicated the D EDG remained operable.

On June 25, 2017, the D EDG failed to start for its monthly surveillance run, and was subsequently declared inoperable. Troubleshooting identified that the air start relay, which should have been de-energized during the shutdown of the EDG on June 23, 2017 was energized. Reviews of available data and field conditions discovered that terminal 22 of the newly installed Model 416 speed switch had shorted to ground. This grounded terminal and energized relay caused the D EDGs failure to start. PSEG re-installed the speed switch (Model A-8) that was removed during the maintenance window and returned the D EDG to service on June 26, 2017.

PSEG generated NOTF 20772931, performed a work group evaluation (WGE) under order 70195866, which determined that operators incorrectly declared the D EDG operable following post-maintenance testing on June 23, 2017. PSEG corrected the LCO and narrative logs to reflect a period of inoperability from June 18, 2017, through June 26, 2017. PSEG procedure, OP-AA-108-115, Operability Determinations &

Functionality Assessments, Revision 4, requires that the scope of an operability determination must be sufficient to address the capability of SSCs to perform their specified safety functions, and should include which SSCs are affected by the degraded or nonconforming condition. PSEGs WGE determined that the association of the receipt of the ground alarm with the shutdown of the EDG was not effectively made to conclusively demonstrate that there was no adverse impact on the ability of the EDG to perform its safety functions. While the D EDG panel indications were satisfactory, the operator assessment of potential operability impact of the ground fault indication was too narrowly focused. With no abnormal indications on the EDG, operability was assumed and the focus of the operability assessment was concentrated on the DC distribution system, caused by the specific direction contained in the overhead alarm and digital alarm response procedure guidance.

The alarm response procedure for the ground fault alarm, HC.OP-AR.ZZ-0014, Overhead Annunciator Window Box D3, directs operators to refer to abnormal procedure, HC.OP-AB.ZZ-150, 125VDC System Malfunction. Step 4.6 states that if a system ground is indicated, implement procedure HC.OP-AB.ZZ-0147, DC System Ground. Operators performed applicable steps of the DC System Ground procedure until Step 4.4.D that directs when conditions permit, open and reclose the individual distribution panel breakers to locate the ground. Because operators had already declared the D EDG operable 34 minutes after receiving the ground fault alarm, plant conditions no longer permitted manipulation of the distribution breakers without TS action statement entry. PSEGs corrective actions include revision to the applicable attachments in the alarm response procedure guidance such that operators are directed to verify and assess operability, and document technical specification compliance, for any supported equipment that was placed into service or removed from service when the ground indications occurred.

Analysis.

The inspectors determined that PSEGs performance of a narrowly focused operability determination of a ground fault alarm following D EDG post-maintenance testing was a performance deficiency that was reasonably foreseeable and preventable. The ground fault alarm was received upon securing the D EDG following a post-maintenance test run. No other related evolutions were ongoing at the time of the alarm. Additionally the NOTF generated for the condition documented a potential challenge to D EDG operability and recommended an action to investigate recent work on the D EDG for possible causes to ground indications that was not performed. The performance deficiency is more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the operability determination performed to evaluate a ground fault alarm received following D EDG post-maintenance testing on June 23, 2017, was narrowly focused, and resulted in operators inappropriately declaring the D EDG operable. For a 26-hour period between 10:00 p.m. on June 23 through 12:02 a.m. on June 25, PSEG incorrectly considered the D EDG available and capable to perform its safety function in an emergency; however, the D EDG was inoperable. In accordance with IMC 0609.04, Initial Characterization of Findings, dated October 7, 2016, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS allowed outage time, did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This finding has a cross-cutting aspect in the area of Human Performance, Resources, in that PSEG did not ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, PSEGs inadequate alarm procedure guidance limited the focus of the operability determination to concentrate on the DC distribution system. [H.1]

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. OP-AA-108-115, Operability Determinations & Functionality Assessments, Revision 4, states, in part, that the scope of an operability determination must be sufficient to address the capability of SSCs to perform their specified safety functions, and that the operability determination should include which SSCs are affected by the degraded or nonconforming condition.

Contrary to the above, on June 23, 2017, the scope of an operability determination performed for a ground fault alarm received following D EDG post-maintenance testing on June 23, 2017, was insufficient to address the capability of the D EDG to perform its safety function to serve as the standby electrical power source to its safety-related emergency 4.16 kilovolt bus. Specifically, the operability determination was narrowly focused, and resulted in operators inappropriately declaring the D EDG operable. PSEGs corrective actions included replacing the D EDG speed switch and revising applicable attachments in alarm response procedure guidance such that operators consider when supported equipment was placed into or removed from service. Because this finding is of very low safety significance (Green) and has been entered into PSEGs CAP as NOTF 20772931, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy.

(NCV 05000354/2017003-01, Inadequate Operability Determination of Ground Fault Alarm)

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors evaluated a modification to: 1.) install spent fuel pool level indication implemented by design change package 80109771; 2.) an electrical modification to implement Diverse and Flexible Coping Strategies implemented by design change package 80112547; and 3.) a modification to the HPCI battery capacity and available voltage calculation implemented by OPEVAL 70195398, technical evaluation 70191342 and revisions to design calculation E-1.4, HC Class 1E 125 and 250 VDC Systems:

Short Circuit and Voltage Drop Calculations. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the upgrade and design change. The inspectors also interviewed engineering and operations personnel.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistent with the information in the applicable licensing basis and/or design basis documents, and that the test results were properly reviewed and accepted and problems were appropriately documented. The inspectors also walked down the affected job site, observed the pre-job brief and post-job critique where possible, confirmed work site cleanliness was maintained, and witnessed the test or reviewed test data to verify quality control hold point were performed and checked, and that results adequately demonstrated restoration of the affected safety functions.

• Replacement of the SDV outboard vent and drain valve air supply solenoid (order

===60135779) on July 6

• Repair of containment atmosphere control system valves (orders 60132147 and 60131907) on July 21

• Replacement of the B FPC pump motor after the pump failed to start (order 60135314) on July 21

• Preventive maintenance on the D RHR system (order 30229368) on July 28

• Repair of A EDG following a lockout condition during engine shutdown (order 60135784) on July 31

• Replacement of the RCIC and B RHR steam leak detection system failed analog module (order 60136235) on August 23

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and PSEG procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

• B station auxiliary cooling system (SACS) pump in-service testing (IST) on July 21 (IST)

• D EDG monthly surveillance test (ST) on July 24

• A EDG monthly ST on July 31

• B control and diesel area temperature control valve IST on August 12 (IST)

• A control area chill water pump IST on August 7, reviewed week of August 14 (IST)

• Reactor coolant system (RCS) leakage review on August 21 (RCS)

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors reviewed PSEGs performance in assessing and controlling radiological hazards in the workplace. The inspectors used the requirements contained in 10 CFR Part 20, TSs, Regulatory Guide 8.38, and the procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors reviewed the performance indicators (PIs) for the occupational exposure cornerstone, radiation protection (RP) program audits, and reports of operational occurrences in occupational radiation safety since the last inspection.

Instructions to Workers ===

The inspectors reviewed high radiation area (HRA) work permit controls and use, observed containers of radioactive materials, and assessed whether the containers were labeled and controlled in accordance with requirements.

The inspectors reviewed several occurrences where a workers electronic personal dosimeter alarmed. The inspectors reviewed PSEGs evaluation of the incidents, documentation in the CAP, and whether compensatory dose evaluations were conducted when appropriate. The inspectors verified follow-up investigations of actual radiological conditions for unexpected radiological hazards were performed.

Contamination and Radioactive Material Control (1 sample)

The inspectors observed the monitoring of potentially contaminated material leaving the radiological controlled area and inspected the methods and radiation monitoring instrumentation used for control, survey, and release of that material. The inspectors selected several sealed sources from inventory records and assessed whether the sources were accounted for and were tested for loose surface contamination. The inspectors evaluated whether any recent transactions involving nationally tracked sources were reported in accordance with requirements.

Radiological Hazards Control and Work Coverage (1 sample)

The inspectors evaluated in-plant radiological conditions and performed independent radiation measurements during facility walkdowns and observation of radiological work activities. The inspectors assessed whether posted surveys; radiation work permits (RWPs); worker radiological briefings and radiation protection job coverage; the use of continuous air monitoring, air sampling and engineering controls; and dosimetry monitoring were consistent with the present conditions. The inspectors examined the control of highly activated or contaminated materials stored within the spent fuel pools and the posting and physical controls for selected HRAs, locked high radiation areas (LHRAs) and very high radiation areas (VHRAs) to verify conformance with the occupational PI.

Risk-Significant HRA and VHRA Controls (1 sample)

The inspectors reviewed the procedures and controls for HRAs, VHRAs, and radiological transient areas in the plant.

Radiation Worker Performance and Radiation Protection Technician Proficiency (1 sample)

The inspectors evaluated radiation worker performance with respect to radiation protection work requirements. The inspectors evaluated radiation protection technicians in performance of radiation surveys and in providing radiological job coverage.

Problem Identification and Resolution (1 sample)

The inspectors evaluated whether problems associated with radiation monitoring and exposure control (including operating experience) were identified at an appropriate threshold and properly addressed in the CAP.

b. Findings

No findings were identified.

2RS2 Occupational As Low As Is Reasonably Achievable Planning and Controls

a. Inspection Scope

The inspectors assessed PSEGs performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements contained in 10 CFR Part 20, Regulatory Guides 8.8 and 8.10, TSs, and procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors conducted a review of HCGSs collective dose history and trends; ongoing and planned radiological work activities; previous post-outage ALARA reviews; radiological source term history and trends; and ALARA dose estimating and tracking procedures.

Verification of Dose Estimates and Exposure Tracking Systems (1 sample)

The inspectors reviewed the current annual collective dose estimate; basis methodology; and measures to track, trend, and reduce occupational doses for ongoing work activities.

The inspectors evaluated the adjustment of exposure estimates, or re-planning of work.

The inspectors reviewed post-job ALARA evaluations of excessive exposure.

Implementation of ALARA and Radiological Work Control (1 sample)

The inspectors reviewed radiological work controls and ALARA practices during the observation of in-plant work activities. The inspectors verified use of shielding, contamination controls, airborne controls, RWP controls, and other work controls were consistent with ALARA plans. The inspectors ensured that work-in-progress reviews were performed in a timely manner and adjustments made to the ALARA estimates when appropriate. The inspectors reviewed the results achieved against the intended ALARA estimates to confirm adequate implementation and oversight of radiological work controls. The inspectors also verified that the ALARA staff was involved with emergent work activities and were revising both dose estimates and ALARA controls in the associated RWPs/ALARA Plans, as appropriate

Radiation Worker Performance (1 sample)

The inspectors observed radiation worker and radiation protection technician performance during radiological work to evaluate worker ALARA performance according to specified work controls and procedures. Workers were interviewed to assess their knowledge and awareness of planned and/or implemented radiological and ALARA work controls.

Problem Identification and Resolution (1 sample)

The inspectors evaluated whether problems associated with ALARA planning and controls were identified at an appropriate threshold and properly addressed in the CAP.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index (5 samples)

a. Inspection Scope

The inspectors reviewed PSEGs submittal of the Mitigating Systems Performance Index (MSPI) for the following systems for the period of October 1, 2016, through September 30, 2017.

• Emergency AC power system (MS06)

• High pressure injection system (MS07)

• Heat removal system (MS08)

• Residual heat removal system (MS09)

• Cooling water system (MS10)

To determine the accuracy of the PI data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors also reviewed PSEGs operator narrative logs, notifications, MSPI derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness (1 sample)

a. Inspection Scope

The inspectors reviewed PSEG submittals for the occupational radiological occurrences PI for the first through third quarter 2017. The inspectors used PI definitions and guidance contained in NEI 99-02, Revision 7, to determine the accuracy of the PI data reported. The inspectors reviewed electronic personal dosimetry accumulated dose alarms, dose reports, and dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized PI occurrences.

The inspectors conducted walkdowns of various LHRA and VHRA entrances to determine the adequacy of the controls in place for these areas.

b. Findings

No findings were identified.

Radiological Effluent Occurrences (1 sample)

a. Inspection Scope

The inspectors reviewed PSEG submittals for the radiological effluent TS/Offsite Dose Calculation Model (ODCM) radiological effluent occurrences PI for the first through third quarter 2017. The inspectors used PI definitions and guidance contained in the NEI 99-02, Revision 7, to determine if the PI data was reported properly. The inspectors reviewed the public dose assessments for the PI for public radiation safety to determine if related data was accurately calculated and reported.

The inspectors reviewed the CAP database to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous and liquid effluent summary data and the results of associated offsite dose calculations to determine if indicator results were accurately reported.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify PSEG entered issues into their CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into their CAP and periodically attended condition report screening meetings. The inspectors also confirmed, on a sampling basis, that, as applicable, for identified defects and non-conformances, PSEG performed an evaluation in accordance with 10 CFR Part 21.

b. Findings

No findings were identified.

.2 Annual Sample: Review of Repetitive Equipment Failures in the Reactor Protection

System, the Reactor Water Cleanup System, and the Fuel Pool Cooling System

a. Inspection Scope

The inspectors reviewed PSEG's identification, evaluation, and CAs associated with equipment and performance issues over the last 12 months involving the RPS, the RWCU system, and the FPC system. The inspectors assessed PSEGs problem identification threshold, technical and causal evaluations, OE and trend reviews, vendor oversight, and the prioritization and timeliness of CAs to evaluate whether PSEG was appropriately identifying, characterizing, and correcting problems associated with these issues and whether the planned and/or completed CAs were appropriate. The inspectors compared the actions taken in accordance with the requirements of PSEGs procurement and maintenance procedures, PSEGs CAP, 10 CFR Part 50, Appendix B, HCGS TSs, and the MR.

b. Observations The inspectors review focused on the repetitive equipment and performance issues over the last 12 months involving the RPS, the RWCU system, and the FPC system which included: 1) three separate occasions of unexpected delays in the tripping of RPS during routine surveillance testing [December 19, 2015, September 16, 2016, and February 24, 2017]; 2) three separate trips of the A RWCU pump [January 27, February 23, and April 30, 2017]; and, 3) two trips of the B FPC pump [June 14 and July 21, 2017].

The inspectors found that for the issues involving the unexpected delays in the trip of RPS, the inspectors noted numerous inconsistencies with PSEGs assigned priority, significance, and level of assigned follow-up evaluation for each event. The inspectors also noted that between second and third events, PSEGs procedure ER-AA-310-1005, MR - Disposition Between (a)(1), required a revision to the existing MR (a)(1) action plan, but that it was either delayed multiple times over 8 months or not tracked in their CAP. The inspectors dispositioned these MR issues and identified one finding which is discussed at the end of this section.

The inspectors noted minor performance deficiencies associated with the causal evaluations (orders 70192491 and 70193887) performed for the trips of A RWCU pump, in that PSEGs evaluations narrowly focused on what failed instead of also including an evaluation of why the failures occurred. The inspectors also found that these evaluations: 1) did not discuss why vendor technical input was not incorporated into operations and maintenance procedures; and, 2) did not account for the improper operation of the pump after the system was restored without the required pump insulation. While these observations were determined by the inspectors to be performance deficiencies, they were determined to be minor issues, as they did not result in system inoperability or maintenance rule system exceeding the performance criteria requiring additional monitoring. These issues were placed into PSEGs CAP under the NOTFs documented at the end of this section.

For the B FPC pump trips, the inspectors only noted minor issues related to improper maintenance rule screenings and not tracking the failure analyses that needed to be performed on the pump motor and breaker. (Note: As of September 30, 2017, PSEG had yet to determine why the pump motor and breaker failed.)

Overall, the inspectors determined that PSEGs causal evaluations and extent-of-condition reviews for all of these repetitive issues were thorough, and that the causes were appropriately identified, with a few minor deficiencies noted above that were dispositioned as minor and placed into PSEGs CAP under NOTFs 20752158, 20764636, and 20774387. The inspectors also determined that the planned and/or completed corrective actions were reasonable, and would address the causes of the repetitive system failures.

c. Findings

Introduction.

The inspectors identified a Green NCV of 10 CFR 50.65(a)(1),

Requirements for monitoring the effectiveness of maintenance at nuclear power plants (MR), because PSEG did not demonstrate that the performance of the RPS was effectively controlled through the performance of appropriate preventive maintenance, did not establish adequate goals and monitoring, and did not take adequate corrective actions when the system experienced repetitive failures due to mechanical binding of the

1. 4 MSV limit switch arm causing unexpected delays in the RPS trip actuation times.

Description.

The RPS is a dual trip electrical alarm and actuating system designed to prevent the reactor from operating under unsafe or potentially unsafe conditions. The RPS is designed to cause rapid insertion of control rods (scram) to shut down the reactor when specific variables exceed predetermined limits. Any trip of the main turbine will initiate closure of its stop valves (MSVs), which can result in a significant addition of positive reactivity to the core as the reactor vessel pressure rise causes steam voids to collapse. The MSV closure trip initiates a reactor scram to provide additional safety margin (in addition to the reactor vessel high pressure scram and pressure relief system)below the required reactor vessel pressure limits to preclude over-pressurization.

The MSV closure inputs to the RPS originate from eight redundant valve stem position switches mounted on the four MSVs. Each switch opens before the valve is closed and provides positive indication of closure as specified in TSs. Each switch provides an input signal to one of the four RPS trip logic channels which is arranged so that closure of three or more valves is required to initiate a reactor scram. PSEG procedure, HC.OP-ST.AC-0002, Turbine Valve Testing - Quarterly, is conducted to verify that RPS functions are maintained by closing the MSVs in pairs (validated RPS half-scrams are received). The MSVs are designed to give an RPS actuation when the two valves go to less than 90 percent open. The MSV closure scram trip is automatically bypassed if the turbine first stage pressure, as sensed by four pressure transmitters, is less than that corresponding to about 24 percent RTP. The bypass is automatically removed above about 24 percent RTP.

On February 24, 2017, while performing HC.OP-ST.AC-0002, and testing the #3 and

1. 4 MSVs, PSEG documented an unexpected delay (approximately 2 minutes) in the trip of RPS channel A2. Although the RPS trip initiation time is not an acceptance criterion in PSEGs surveillance test, an immediate RPS trip initiation was expected. PSEG initiated NOTF 20756636 for the unexpected delay and manually inserted the #4 MSV trip resulting in an A2 RPS and end-of-cycle recirculation pump trip (EOC-RPT) signal in order to meet TS action requirements. PSEGs immediate troubleshooting found no visible issues (mechanical binding) with the limit switch (N006D) and could not rule out the associated relay (K10G) as the cause of the delay. PSEG documented an operational and technical decision making (OTDM),

HC-17-003, on March 3, 2017, to allow operation of the RPS in this configuration until the limit switch and/or the relay could be replaced during the next refueling outage. Further troubleshooting performed by PSEG on May 31, 2017, determined that mechanical binding of the limit switch, and not a failure of the relay, was the cause of the delay.

The inspectors reviewed the history of this issue and found that:

• On December 19, 2015, the A2 RPS trip was delayed by approximately 90 seconds during HC.OP-ST.AC-0002 testing. PSEG determined that an internal MSV mounting bolt caused intermittent contact with the arm of the limit switch resulting in the delay. The mounting bolt was adjusted and PSEGs 18-month testing procedure, HC.IC-DC.ZZ-0329, Turbine Steam Control Valves Limit Switch Adjustment, was revised to provide adequate instruction for the maintenance technician to identify precursors to the vibration induced delay in RPS actuation. Specifically, the procedure was revised on January 20, 2016, with steps to ensure adequate clearance between the lever-arm and switch plate mounting bolts, and to verify free movement of the lever arm during stroke.

• On September 16, 2016, the A2 RPS trip was delayed by approximately 26 seconds during HC.OP-ST.AC-0002 testing. NOTF 20742337 documented the RPS delay as a condition adverse to quality (CAQ) and a functional failure, and the prompt investigation recommended the performance of a causal evaluation but no evaluation was performed and no justification for this decision was documented in PSEGs CAP. PSEGs troubleshooting on September 17, 2016, documented the K10G relay or the limit switch as potential causes and the prompt investigation (PINV) in NOTF 20742337 stated that longer-term corrective actions would be determined from the causal evaluation. On November 12, 2016, during HCGSs scheduled refueling outage, PSEG determined that the limit switch arm was coming in contact with mounting bolt head on the back side of the mounting plate (work order 60131546). The washer was removed from the backside bolt head to allow for better clearance between the bolt head and the limit switch arm.

Based on this, the inspectors questioned why no causal evaluation had been performed for this repeat CAQ as recommended in PSEGs PINV (20742337) for the September 2016 event. PSEG determined that no causal evaluation was assigned from the PINV nor was any justification provided for not performing a causal evaluation for the issue. PSEG documented this in NOTF 20760050 on March 28, 2017. PSEG returned NOTF 20742337 to the Station Ownership Committee (SOC) and Management Review Committee (MRC) to review for assignment of a causal evaluation. On March 30, 2017, SOC recommended an ACE be performed based on medium risk and uncertainty of the issue (actual consequence was the failure of the surveillance test and potentially the failure of a reactor trip signal being generated in a timely manner from the #3 and #4 MSVs going closed on an actual turbine trip; reoccurring issue). The inspectors determined that a causal evaluation had not been assigned for action or completed as of the time of this inspection.

The inspectors also questioned PSEGs use of the MR, the timeliness of their decision making, and the adequacy of their assigned corrective actions associated with the RPS (a)(1) plan (EVAL-H-SB-00114). The inspectors found that:

• On July 6, 2016, PSEG placed RPS in (a)(1) due to exceeding the MR performance criteria and established a monitoring period of 2 years. The RPS (a)(1) plan (EVAL-H-SB-00114), cited the revision to the maintenance procedure that occurred in January 2016 as the corrective action. After the September 2016 event, NOTF 20745197 (dated October 12, 2016) documented a repeat maintenance preventable functional failure (RMPFF) and allocated order 70189545, operation 0060 for developing a revised (a)(1) plan to be presented to the MR expert panel. As indicated above, the next event occurred in February 2017. The inspectors noted that the presentation of a revised (a)(1) plan to the expert panel was either delayed or tabled from January 2017 until August 8, 2017. The approximately 8 months delay was greater than 30 percent of PSEGs established 2-year (a)(1) monitoring period.

• After the troubleshooting on May 31, 2017, determined that mechanical binding was the most likely cause of the delay, PSEG did not assign actions to revise the functional failure causal determination evaluation (FFCDE), revise the (a)(1) plan or present the revised (a)(1) plan to the MR expert panel as required by PSEG procedure, ER-AA-310-1005, Maintenance Rule -Dispositioning Between (a)(1) and (a)(2), until prompted by the inspectors on June 27, 2017.

Title 10 CFR 50.65(a)(1) states that the licensee shall monitor the performance or condition of structures, systems, or components, against licensee-established goals, in a manner sufficient to provide reasonable assurance that these structures, systems, and components, as defined in paragraph

(b) of this section, are capable of fulfilling their intended functions. These goals shall be established commensurate with safety and, where practical, take into account industrywide operating experience. When the performance or condition of a structure, system, or component does not meet established goals, appropriate corrective action shall be taken.

The NRC Enforcement Manual, Part II, Section 2.1.11, discusses issues that are violations of 10 CFR 50.65(a)(1). The Manual states, in part, that the failure to monitor performance or condition against established goals or the failure to take appropriate corrective action when performance or condition goals are not met are examples of 50.65(a)(1) violations.

Analysis.

PSEG not demonstrating that the performance of the RPS was effectively controlled, not establishing adequate goals and monitoring, and not taking adequate corrective actions when the system experienced repetitive maintenance preventable functional failures was a performance deficiency that was within their ability to foresee and correct, and should have been prevented. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG not establishing new goals and monitoring, as well as not performing adequate corrective actions for the mechanical binding of the #4 MSV limit switch arm that was causing unexpected delays in the RPS trip actuation times adversely impacted the reliability of those system. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, dated June 19, 2012, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the inspectors determined the finding was of very low safety significance (Green).

The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that PSEG did not thoroughly evaluate the repetitive issues with the #4 MSV limit switch to ensure that the resolutions addressed the causes and extent of conditions commensurate with their safety significance. Specifically, PSEG did not properly classify, prioritize, and evaluate the issue according to its safety significance allowing the cause to be undetermined and the monitoring of the RPS to be ineffective.

[P.2].

Enforcement.

Title 10 CFR 50.65(a)(1), requires, in part, that the licensee shall monitor the performance or condition of SSCs within the scope of the rule, against licensee-established goals in a manner sufficient to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions. Such goals shall be established commensurate with safety. When the performance or condition of a SSC does not meet established goals, appropriate corrective action shall be taken.

Contrary to the above, since September 16, 2016, PSEG inadequately monitored the performance or condition of the RPS, a system within the scope of the MR, against licensee established goals when the system experienced repetitive maintenance preventable functional failures. Additionally, when the initial goals were not met, the corrective actions were not appropriate to preclude repetitive functional failures and new goals were not established. PSEGs immediate corrective action was to initiate NOTF 20742337 and new operations to order 70192748 to revise the RPS MR (a)(1) action plan and plan the replacement of the limit switch during the next scheduled or forced outage. Since this violation was of very low safety significance (Green) and has been entered into the CAP as NOTF 20742337 and 20760050, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the Enforcement Policy. (NCV 05000354/2017003-02, Inadequate Establishment of Maintenance Rule Goals, Monitoring, and Corrective Actions for the Reactor Protection System)

.3 Annual Sample: Review of Adverse Trend in Increasing Drywell Floor Drain Leakage

a. Inspection Scope

The inspectors reviewed PSEG's identification, evaluation, and CAs associated with an observed rising trend in drywell floor drain leakage (DWFDL) / RCS unidentified leakage (UIL) since the last reactor startup performed on November 10, 2016. The inspectors assessed PSEGs problem identification threshold, technical and cause analyses, OE and trend reviews, vendor oversight, and the prioritization and timeliness of CAs to evaluate whether PSEG was appropriately identifying, characterizing, and correcting problems associated with the adverse trend and whether the planned and/or completed CAs were appropriate. The inspectors compared the actions taken in accordance with the requirements of PSEGs operations, engineering and maintenance procedures, PSEGs CAP, 10 CFR Part 50, Appendix B, HCGS TSs, and the MR.

b. Observations The HCGS TS 3.4.3.2, RCS Operational Leakage, limits RCS UIL to 5 gallon per minute or a 2 gallon per minute increase within any 24-hour period. Should these leakage limits be exceeded, the plant would be required to shut down. Per PSEG procedure ER-AB-331-1006, BWR Reactor Coolant System Leakage Monitoring and Action Plan, an adverse conditioning monitoring (ACM) plan and OTDM document is to be developed when the UIL rate exceeds 0.5 gallon per minute. The drywell leak detection (DLD)sump monitoring system samples level data every 600 milliseconds and corresponding sump liquid volumes are derived from these levels. This results in a running tabulation of volume versus time. Typical readings for DWFDL or UIL for HCGS are between 0.02 and 0.07 gallon per minute.

Following reactor startup from HCGSs most recent refueling outage (H1R20) on November 10, 2016, an upward trend in DWFDL or RCS UIL was observed through normal operations and engineering performance monitoring activities. On June 2, 2017, PSEG documented NOTF 20766453 in accordance with their procedure ER-AB-331-1006, when UIL reached 0.08 gallon per minute. PSEG developed an ACM plan to monitor leakage on an increased frequency and establish action level thresholds.

DWFD chemistry samples obtained by PSEG on July 21, August 21, August 30, and September 20, 2017, demonstrated that the UIL was not indicative of a reactor water leak.

On September 5, 2017, tracking and trending of UIL performed by operations and engineering indicated the leak rate had risen to 0.41 gallon per minute. Due to the rate of increase and the potential for UIL to exceed 0.5 gallon per minute, PSEG made the decision to enter complex troubleshooting for the increase in UIL using their conduct of troubleshooting procedure, MA-AA-716-004.

On September 8, 2017, the UIL trend changed from 0.41 to 0.17 gallon per minute over the course of several hours for no apparent reasons. Coincident with the change, PSEG noted and documented in NOTF 20774647 that seismic activity, as far away as Mexico, was seen to have caused slight (approximately 0.5 inch) TORUS level oscillations.

Other licensees around the country confirmed this phenomenon.

On September 23, 2017, PSEG conducted a planned down power to 76 percent power for approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> to perform scheduled main turbine valve testing and control rod testing. PSEG incorporated a leak investigation for the UIL adverse trend, which include monitoring selected system and DW parameters (control rod drive mechanisms, drywell temperatures / atmosphere, system pressures) to identify the source of the leakage.

Between September 8 and September 30, 2017, HCGSs UIL increased from 0.17 to 0.54 gallon per minute. PSEGs failure modes causal team is currently considering all of this information, and the in-place ACM plan has established predetermined action levels if leakage continues to increase.

During the review of HCGSs UIL, the inspectors noted and PSEG documented in NOTF 20774091 that the decision tree in Attachment 1 of ER-AB-331-1006, could lead to human error in that operators may not take the appropriate actions to address increased UIL at 10 times the baseline UIL level. The inspectors determined that this issue was minor because it did not result in PSEG missing actions required to investigate and determine the cause of the slow rise in UIL.

Overall, the inspectors determined that PSEG had taken appropriate action to date in accordance with their procedures at a conservative threshold and were appropriately addressing the slow rise in UIL in their CAP and through the use of a complex troubleshooting team and ACM plan. The inspectors determined that PSEGs evaluations and extent-of-condition reviews were thorough, and the causes were appropriately identified. The inspectors also determined that the corrective actions were reasonable.

c. Findings

No findings were identified.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

(Closed) LER 05000354/2017-001-00: Secondary Containment Door Not Latched in Closed Position On May 10, 2017, a HCGS secondary containment door (R-4302) was observed to be unlatched in the closed position. The door was being held closed by the negative pressure within the reactor building (secondary containment). PSEG determined that the door had been opened for equipment passage on, May 8, 2017, at 1:23 p.m., and concluded that the door was most likely unlatched for passage at that time and not re-latched following the passage. A review of HCGS design basis accident (DBA)conditions determined that the secondary containment pressure would become slightly positive for a short period of time, under certain DBA events. Based on the area of the door, and the expected pressure rise within secondary containment, the door could not be assured to remain closed. The HCGS TSs require that secondary containment integrity be maintained while in Operational Condition 1. Secondary Containment Integrity is defined as having all doors in the closed position except for normal passage.

Since the closed door position could not be assured under all postulated accident conditions, PSEG reported this as a condition reportable under 10 CFR 50.73 (a)(2)(i)(B)as a condition prohibited by TSs, and under 10 CFR 50.73 (a)(2)(v)(C) as a condition that could have prevented the fulfillment of a safety function needed to control the release of radioactive material. PSEG entered the issue into their CAP as NOTF 20764632, and CAs included securing the unlatched door, conducting training and performance management with the individuals involved, and establishing additional administrative controls for passage through all secondary containment doors.

The inspectors reviewed this event, PSEGs completed causal evaluation completed under order 70194097, and NRC IR 2017007, which documented an NRC identified Green NCV of TS 3.6.5.1 because PSEG did not maintain secondary containment integrity. Specifically, while HCGS was operating in Mode 1, the team identified that secondary containment door R-4302 was not properly latched (dogged) closed in accordance with PSEG procedure CC-AA-201, Plant Barrier Control Program. Because the door was not dogged, secondary containment was determined to be inoperable. The inspectors did not identify any additional performance deficiencies associated with this event. This LER is closed.

4OA6 Meetings, Including Exit

On October 11, 2017, the inspectors presented the inspection results to Mr. Edward Casulli, HCGS Plant Manager, and other members of the PSEG staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report. PSEG management acknowledged and did not dispute the findings.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

E. Carr, Site Vice President

E. Casulli, Plant Manager

D. Bedford, System Engineer

T. Gingerich, System Engineer

A. Hak, System Engineer

R. Heathwaite, Chemistry

J. Krall, Reactor Engineering Manager

D. Mannai, Senior Director Regulatory Operations

T. MacEwen, Regulatory Assurance

A. Ochoa, Regulatory Affairs

J. Priest, Nuclear Shift Operations Manager

N. Rock, System Engineer

K. Torres, Programs Supervisor

H. Trimble, Radiation Protection Manager

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open and

Closed

05000354/2017003-01 NCV Inadequate Operability Determination of Ground Fault Alarm (Section 1R15)

05000354/2017003-02 NCV Inadequate Establishment of Maintenance Rule Goals, Monitoring, and Corrective Actions for the Reactor Protection System (Section 4OA2.3)

Closed

05000354/2017-001-00 LER Secondary Containment Door Not Latched (Section 4OA3.2)