IR 05000354/2017001

Integrated Inspection Report and Exercise of Enforcement Discretion 05000354/2017001

ML17130A831
Person / Time
Site:	Hope Creek
Issue date:	05/09/2017
From:	Michael Scott Reactor Projects Branch 3
To:	Sena P Public Service Enterprise Group
References
EA-17-071 IR 2017001
Download: ML17130A831 (46)

Text

May 9, 2017

SUBJECT:

HOPE CREEK GENERATING STATION UNIT 1 - INTEGRATED INSPECTION REPORT AND EXERCISE OF ENFORCEMENT DISCRETION 05000354/2017001

Dear Mr. Sena:

On March 31, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station (HCGS). On April 13, 2017, the NRC inspectors discussed the results of this inspection with Mr. Edward Casulli, Plant Manager, and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented two self-revealing findings 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.

In addition to the issues identified above, a violation of Technical Specification 3.6.5.1 involving a failure to set secondary containment during operations with the potential to drain the reactor vessel (OPDRVs) was identified during the Hope Creek refueling outage. Because the violation was identified during the discretion period described in Enforcement Guidance Memorandum 11-003, Revision 3, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted. 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/

Michael L. Scott, Director Division of Reactor Projects Docket No. 50-354 License No. NPF-57

Enclosure:

Inspection Report 05000354/2017001 w/Attachment: Supplementary Information

REGION I==

Docket No. 50-354 License No. NPF-57 Report No. 05000354/2017001 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Hope Creek Generating Station (HCGS)

Location: Hancocks Bridge, NJ 08038 Dates: January 1, 2017 through March 31, 2017 Inspectors: J. Hawkins, Senior Resident Inspector S. Haney, Resident Inspector P. Boguszewski, Resident Inspector (Acting)

B. DeBoer, Health Physicist N. Floyd, Resident Inspector (Acting)

J. Furia, Senior Health Physicist H. Gray, Senior Reactor Inspector J. Nicholson, Senior Health Physicist J. Patel, Senior Reactor Inspector J. Schoppy, Senior Reactor Inspector, Team Leader Approved By: Michael L. Scott, Director Division of Reactor Projects Enclosure

SUMMARY

Inspection Report (IR) 05000354/2017001; 01/01/2017 - 03/31/2017; Hope Creek Generating

Station; Problem Identification and Resolution, Follow-Up of Events and Notices of Enforcement Discretion.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. The inspectors identified two self-revealing findings 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 very low safety significance (Green) NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion VIII, Identification and Control of Materials, Parts and Components, was identified because PSEG did not have adequate control measures to prevent the use of defective parts. Specifically, following the C emergency diesel generator (EDG) speed switch (SS) failure on August 4, 2016, PSEGs control measures did not prevent the installation of the previously failed SS, with susceptible degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process, into the A EDG on January 6, 2017. Consequently, less than one month later on February 3, 2017, the A EDG failed to start due to a failed SS. PSEGs corrective actions (CAs) included replacing the SS, identifying an equivalent replacement for the currently installed SS design, scheduling the replacement of the new SSs, and performing extent of condition inspections and testing of all the installed and spare EDG SSs.

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 of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEGs installation of a previously failed SS, with susceptible degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process, into the A EDG on January 6, 2017, led to the A EDG failing to start on February 3, 2017. 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 was Green because it 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 (TSs) allowed outage time, and 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 (MRP) 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 had a cross-cutting aspect in the area of Problem Identification and Resolution,

Evaluation, because PSEG did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance.

Specifically, PSEG did not thoroughly evaluate their previous failure analyses (FA)performed on the failed SSs to ensure that resolutions addressed the actual failure mode

[P.2]. (Section 4OA2.2)

Green.

A self-revealing Green non-cited violation (NCV) of TS 6.8.1, Procedures, was identified because PSEG did not establish an appropriate preventive maintenance (PM)schedule for the high pressure coolant injection (HPCI) overspeed trip system reset spring.

Specifically, PSEGs major inspection PM frequency and scope justification for the HPCI turbine major inspection and overhaul PM was determined to be inadequate. As a result, the HPCI overspeed tappet reset spring was not replaced for 8.5 years, resulting in the reset springs force falling below the required force range. As a result, on April 7, 2016, the HPCI turbine tripped and then reset shortly after being started because of the low reset spring force, making the HPCI system unable to automatically initiate and inject at rated flow within 35 seconds as required per TSs. PSEGs immediate CAs included replacing the reset spring, adding replacement of the spring to the 6.87 year HPCI environmental qualification (EQ) PM, and evaluating the storage requirements for similar springs in inventory.

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. Specifically, the inadequate PM frequency and scope for the reset spring resulted in the low spring force due to the springs age allowing the trip tappet assembly to float upward on a HPCI system start-up and tripping the turbine when no actual overspeed condition existed. 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 was Green because it 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 and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs MRP for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, following the overspeed trip on April 7, 2016, HPCI was restored to operable status in approximately 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance as the inadequate PM schedule for the HPCI overspeed trip tappet assembly reset spring involved multiple missed opportunities to re-evaluate the PM scope and frequency from 2005 through 2009. In accordance with IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance. (Section 4OA3.1)

REPORT DETAILS

Summary of Plant Status

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

On February 24, 2017, operators reduced power to approximately 35 percent to support planned main turbine valve testing, control rod scram time testing, control rod sequence exchange, and to repair a leak on an extraction steam line valve. The unit was returned to 100 percent RTP on February 26, 2017. The unit remained at or near full 100 percent for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed PSEGs preparations for the onset of impending winter storm, including four to six inches of snow/ice on January 6 through 7. The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during this adverse weather condition. The inspectors walked down the EDGs and station service water (SSW) system to ensure system availability. The inspectors verified that operator actions defined in PSEGs adverse weather procedure maintained the readiness of essential systems. The inspectors discussed readiness and staff availability for adverse weather response with operations and work control personnel.

Documents reviewed for each section of this IR 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:

B electrohydraulic control (EHC) pump during A EHC leak repair during the week of January 3 B control room ventilation system during maintenance on the A control room emergency filtration system on February 7 HPCI system during maintenance on the reactor core isolation cooling (RCIC)system on February 22 A core spray (CS) during maintenance on B CS on March 13 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 Updated Final Safety Analysis Report (UFSAR), TSs, work orders (WOs), notifications (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

.1 Resident Inspector Quarterly Walkdowns

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-II-561, Control equipment heating, ventilation and air conditioning, inverter and battery rooms on January 11 FRH-III-123, EHC power unit area, week of January 27 FRH-III-151, Rooms 1516 and 1517, A and B reactor recirculation pump (RRP)motor generator set rooms on February 8 FRH-II-713, SW intake structure on February 16 FRH-II-442, Filtration recirculation ventilation system recirculation unit area on March 1

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed a fire brigade drill scenario conducted on January 11 that involved a simulated fire in the HCGS EDG and auxiliary building ventilation system.

The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that PSEG personnel identified deficiencies, openly discussed them in a self-critical manner at the post-drill debrief, and took appropriate CAs as required.

The inspectors evaluated the following specific attributes of the drill:

Proper wearing of turnout gear and self-contained breathing apparatus (SCBA)

Proper use and layout of fire hoses Employment of appropriate fire-fighting techniques Sufficient fire-fighting equipment brought to the scene Effectiveness of command and control Search for victims and propagation of the fire into other plant areas Smoke removal operations Utilization of pre-planned strategies Adherence to the pre-planned drill scenario Drill objectives met The inspectors also evaluated the fire brigades actions to determine whether these actions were in accordance with PSEGs fire-fighting strategies.

b. Findings

No findings were identified.

1R07 Heat Sink Performance (711111.07A - 1 sample)

a. Inspection Scope

The inspectors reviewed the A and B fuel pool cooling and cleanup (FPCC) heat exchangers (HXs) readiness and availability to perform their safety functions. The inspectors reviewed the design basis for the component. The inspectors reviewed the results of previous inspections on the HXs. The inspectors discussed the results of the most recent inspection with engineering staff and reviewed pictures of the as-found and as-left conditions. The inspectors verified that PSEG initiated appropriate CAs for identified deficiencies. Because these are plate-type HXs, the inspectors also verified that the HXs did not exhibit any external leakage during previous examinations.

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 March 7, which included a seismic event followed by a loss of a vital 4.16 kiloVolt (kV) bus, complete loss of condenser vacuum, loss of coolant accident (LOCA), and failure of multiple emergency core cooling system (ECCS) components. 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 a planned down power to support unlocking the B RRP scope tube following an undemanded speed change and system troubleshooting on March 13. 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 WOs, 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 CAs 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 the AVH-415 A control room return air ventilation fan trip failure due to low flow on November 23, 2016

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.

Protected equipment and risk assessment for a Bailey cabinet power supply monitor failure on January 11 Protected equipment and risk assessment for B RRP undemanded speed change testing during the week of January 27 Protected equipment and risk assessment for A EDG maintenance during the week of January 30 Protected equipment and risk assessment for B EDG maintenance on February 14 Protected equipment and risk assessment for B control room emergency filtration (CREF) maintenance the week of March 20 Protected equipment and risk assessment for B residual heat removal (RHR)maintenance and A reactor water cleanup maintenance the week of March 27

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 A FPCC pump with high oil viscosity during the week of February 20 Review of the A RHR minimum flow valve failure to close during the week of February 25 Review of the fuel conditioning limit being exceeded during power ascension during the week of February 27 Review of the #4 turbine stop valve (TSV) position input to the reactor protection system (RPS) during the week of March 1 Review of the EDG SS voltage regulator chip (LM317) potential degradation during the week of March 22 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

No findings were identified.

1R17 Evaluations of Changes, Tests, or Experiments (IP 71111.17T - 29 samples)

a. Inspection Scope

Three inspectors from the NRC Region I Office completed an inspection between March 27 - 31, 2017, to verify that PSEG staff performed proper screening and evaluations of changes and tests in accordance with regulatory requirements and PSEG implementing guidance. The team specifically reviewed four safety evaluations to evaluate whether the changes to the facility or procedures, as described in the UFSAR, had been reviewed and documented in accordance with 10 CFR 50.59 requirements.

The safety evaluations were sampled from those completed by PSEG staff since the last NRC inspection of this area and had not been previously reviewed by NRC inspectors. In addition, the team evaluated whether PSEG staff had been required to obtain NRC approval prior to implementing the changes. The team interviewed PSEG staff and reviewed supporting information including calculations, analyses, design change documentation, procedures, the UFSAR, the TSs, and plant drawings to assess the adequacy of the safety evaluations. The team compared the safety evaluations and supporting documents to the guidance and methods provided in Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Evaluations, as endorsed by NRC Regulatory Guide (RG) 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, to determine the adequacy of the safety evaluations.

The team also reviewed a sample of 25 screenings and applicability determinations for which PSEG staff had concluded that a 50.59 safety evaluation was not required to be performed. These reviews were performed to assess whether PSEGs threshold for performing safety evaluations was consistent with 10 CFR 50.59. The sample included design changes, calculations, and procedure changes. The screenings and applicability determinations were selected based on the safety significance, risk significance, and complexity of the change to the facility.

In addition, the team compared PSEGs implementing administrative procedures used to control the screening, preparation, review, and approval of safety evaluations to the guidance in NEI 96-07 to evaluate whether those procedures adequately implemented the requirements of 10 CFR 50.59.

The team verified that PSEG staff entered performance issues concerning their 50.59 program into their CAP. The team verified that PSEG staff developed appropriate CAs to address those issues.

b. Findings

No findings were identified.

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors evaluated a modification, design change package (DCP 80098304) that replaced the internal motor control center (MCC) components associated with the 10B212. 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 reviewed revisions to the operating and control room alarm response procedures and interviewed engineering and operations personnel to ensure the procedures could be reasonably performed.

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 A EDG SS after erroneous speed indication during monthly EDG testing (Order 60133121) during the week of January 9 Replacement of failed power supply monitor for Bailey cabinet 1C-C-652 (Order 60133175) during the week of January 17 Replacement of the A EDG SS, after causing the A EDG to fail to start, (Order 50192180) on February 3 Replacement of torque switch for RCIC turbine lube oil cooling water valve (Order 30227757) on February 23 B standby liquid control (SLC) pump valve and discharge relief valve replacement (Order 30260751) on March 16 PM on B RHR motor and installation of new style torque switches on B RHR minimum flow valve (Order 30153325) on March 28.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests (STs) 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 STs:

A loop ECCS jockey pump in-service testing (IST) on December 6 (IST)

A EDG monthly ST on January 6 HPCI in-service testing on January 10 (IST)

CREF system functional monthly ST on January 11

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, RG 8.38, and the procedures required by TSs as criteria for determining compliance.

Radiological Hazard Assessment The inspectors conducted independent radiation measurements during walkdowns of the facility and reviewed the radiological survey program, air sampling and analysis, continuous air monitor use, recent plant radiation surveys for radiological work activities, and any changes to plant operations since the last inspection to verify survey adequacy of any new radiological hazards for onsite workers or members of the public.

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, RGs 8.8 and 8.10, TSs, and procedures required by TSs as criteria for determining compliance.

Radiological Work Planning The inspectors selected the following radiological work activities based on exposure significance for review:

Radiation Work Permit (RWP) 8, Refuel Floor Activities RWP 10, Maintenance Support Activities RWP 11, local leak rate test (LLRT) Activities RWP 12, ISI Activities For each of these activities, the inspectors reviewed: ALARA work activity evaluations, exposure estimates, exposure reduction requirements, results achieved (dose rate reductions, actual dose), person-hour estimates and results achieved and post-job reviews that were conducted to identify lessons learned.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

The inspectors reviewed the control of in-plant airborne radioactivity and the use of respiratory protection devices in these areas. The inspectors used the requirements in 10 Part CFR 20, RG 8.15, RG 8.25, NUREG/CR-0041, TS, and procedures required by TS as criteria for determining compliance. The inspectors reviewed the UFSAR to identify ventilation and radiation monitoring systems associated with airborne radioactivity controls and respiratory protection equipment staged for emergency use.

The inspectors also reviewed respiratory protection program procedures and current performance indicators for unintended internal exposure incidents.

Self-Contained Breathing Apparatus for Emergency Use The inspectors reviewed the following: the status and surveillance records for three SCBAs staged in-plant for use during emergencies, PSEGs SCBA procedures, maintenance and test records, the refilling and transporting of SCBA air bottles, SCBA mask size availability, and the qualifications of personnel performing service and repair of this equipment.

Problem Identification and Resolution The inspectors evaluated whether problems associated with the control and mitigation of in-plant airborne radioactivity were identified at an appropriate threshold and addressed by PSEGs CAP.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors reviewed performance in assuring the accuracy and operability of radiation monitoring instruments used to protect occupational workers during plant operations and from postulated accidents. The inspectors used the requirements in 10 CFR Part 20, RGs, ANSI 323A, N323D, and N42.14, and procedures required by TSs as criteria for determining compliance. The inspectors reviewed Hope Creeks UFSAR, Radiation Protection audits, records of in-service survey instrumentation, and procedures for instrument source checks and calibrations.

Walkdowns and Observations The inspectors conducted walkdowns of plant area radiation monitors and continuous air monitors. The inspectors assessed material condition of these instruments and that the monitor configurations aligned with the UFSAR. The inspectors checked the calibration and source check status of various portable radiation survey instruments and contamination detection monitors for personnel and equipment.

Calibration and Testing Program For the following radiation detection instrumentation, the inspectors reviewed the current detector and electronic channel calibration, functional testing results alarm set-points and the use of scaling factors: laboratory analytical instruments, whole body counter, containment high-range monitors, portal monitors, personnel contamination monitors, small article monitors, portable survey instruments, area radiation monitors, electronic dosimetry, air samplers and continuous air monitors. The inspectors reviewed the calibration standards used for portable instrument calibrations and response checks to verify that instruments were calibrated by a facility that used National Institute of Science and Technology traceable sources.

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 CAs, 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 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 Multiple Emergency Diesel Generator Speed Switch Failures

a. Inspection Scope

The inspectors reviewed PSEG's identification, evaluation, and CAs associated with three EDG SS failures that have occurred beginning on August 4, 2015. The inspectors assessed PSEGs problem identification threshold, technical and cause analyses, operating experience (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 Hope Creek has experienced three failures of their EDG SSs (C EDG on August 4, 2015, and again on August 4, 2016; and A EDG on February 3, 2017). Hope Creek utilizes four EDGs to serve as the standby electrical power source to the safety-related emergency 4.16 kV buses. The control circuit of each EDG contains an electronic SS assembly. The assembly includes a Dynalco Controls SS board, and an external Fairbanks Morse (FM) voltage regulator. The external voltage regulator steps down control power and outputs to input terminals on the SS board. On the SS board, an internal voltage regulator accepts the stepped down power through a protection circuit containing a series of resistors and a Zener diode (CR17) prior to providing power to the rest of the SS board components. The analog and digital output of the SS assembly is checked, and if necessary, calibrated by PSEG on a 24 month frequency.

The inspectors reviewed previous NRC IRs, including:

1. NRC IR 05000354/2016001; Section 4OA2.4, which documented an adverse trend of C EDG equipment failures. This review included PSEGs apparent cause evaluation (ACE) 70179133 for the August 4, 2015, failure of the C EDG SS, which, at the time, PSEG had determined failed due to a manufacturing defect.

2. NRC IR 05000354/2016002; Section 4OA2.2 documented an adverse trend in EDG SS performance. PSEG closed this issue to pending CAs in ACE 70188603 for the August 4, 2016, SS failure, which included actions to replace the SSs with new style.

3. NRC IR 05000354/2017008; Section 4OA2.1.b(3), EDG Speed Switch Failures, which documented observations concerning: a) PSEGs improper CAP tracking of the two C EDG SS failure analyses; and, b) PSEG not re-evaluating their causal evaluation and associated CAs once the FAs were completed.

The inspectors reviewed PSEGs 2016 ACE 70188603 which documented, in part, that the design configuration for the EDG SSs was incorrect. Specifically, the design of the external voltage regulator was determined to be rudimentary and susceptible to noise, which could induce SS board failures. The inspectors also reviewed PSEGs Problem Identification and Resolution Focused Area Self-Assessment (FASA), 80117891, completed on October 14, 2016, which conducted an in-depth review of the EDG system. In the FASA, PSEG documented that the EDG SS failures were reoccurring, and that the cause was determined to be SS design and workmanship issues. The FASA concluded that the sites CAs were appropriate, and noted that one of the current open CAs was to perform periodic monitoring of SS voltage and current draw to determine why the CR17 Zener diode keeps failing. The inspectors found that no formal periodic monitoring had been put into place, but PSEG performed a one-time voltage test during the October 2016 refueling outage, and then once more after the third SS failure on February 3, 2017.

The inspectors reviewed NOTF 20748785 for erroneous speed indication on the A EDG during its monthly ST on January 3, 2017. PSEG completed the ST, and then developed a Fix It Now (FIN) team WO (60133121) per PSEG procedure MA-AA-716-234, FIN Team, for corrective maintenance replacement of the SS to address the speed indication issue under their simple troubleshooting process. The NOTF documented that the SS was not calibrated in-place but was removed from the A EDG, calibrated on the bench revealing a potential issue with the output current, and sent off for FA under Order 70192076. The replacement SS was calibrated on the bench satisfactorily, installed in the A EDG and verified to be operating correctly through performance of an EDG maintenance.

However, the inspectors identified one finding during this review which is discussed below.

c. Findings

Introduction.

A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion VIII, Identification and Control of Materials, Parts and Components, was identified because PSEG did not have adequate control measures to prevent the use of defective parts.

Specifically, following the C EDG SS failure on August 4, 2016, PSEGs control measures did not prevent the installation of a previously failed SS, susceptible degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process, into the A EDG on January 6, 2017. Subsequently, less than one month later on February 3, 2017, the A EDG failed to start due to a failed SS.

Description.

On February 3, 2017, the A EDG failed to start due to a failed SS. PSEG replaced the failed SST2400A-1 (A-1) model SS, with an SST2400A-8 (A-8) model SS, and retested the A EDG satisfactorily. PSEGs causal evaluation (ERE 70192076) and FA determined that the SS, specifically the internal voltage regulating circuit Zener diode (CR17) and adjustable voltage regulator chip (LM317), had failed. The FA postulated that the LM317 was operating marginally, causing it to overheat and fail when energized, resulting in the CR17 and overall SS failure.

The inspectors noted the recent C EDG SS failures that occurred on August 4, 2015, and August 4, 2016, and inspected the history of the A EDG A-1 model SS that failed on February 3, 2017. The inspectors learned that this SS had been originally installed (new) on the D EDG in 2013. It was then removed and installed on the C EDG on July 5, 2016, failing less than one month later on August 4, 2016. Between August 4, and November 1, 2016, this SS was sent out for FA, refurbished by the vendor, damaged (dropped) during PSEGs receipt inspection, repaired and inspected/tested again by the vendor, and sent back to PSEG for reuse as a spare. The SS was then installed in the A EDG on January 6, 2017, following erroneous speed indications on the A EDG during monthly surveillance testing, and in less than one month failed in the A EDG on February 3, 2017.

The inspectors reviewed PSEGs ERE 70188603 for the C EDG SS failure that occurred on August 4, 2016, which documented that the A-1 model SSs were the vendor recommended model in 2013, but shortly thereafter and now exclusively, the vendor recommended using the A-8 model. This recommended change to model A-8 was due to industry feedback concerning other failures involving the margin between the output of the regulating base and the acceptable voltage range of the CR17 in the A-1 model SS.

The evaluation concluded that the A-1 model SSs needed to be replaced because, with minimal operating margin between the SS voltage regulator base and the CR17, there was greater opportunity for component degradation. PSEGs recommended CAs after the August 4, 2016, failure included completing an equivalency change (Order 80119127) to replace the installed A-1 and A-8 model SSs with a newer design (A-416).

PSEG extended the due date for installation of these new SSs from January 13, to March 31, 2017, because of delays in obtaining the A-416s from the vendor. As an interim corrective action until the newer model SSs could be installed, PSEG created a PM activity to periodically test the power supply input and current draw on the installed SSs to monitor them for potential degradation. This CA was scheduled to start on November 30, 2016, but was not implemented until March 20, 2017.

Following the February 3, 2017, SS failure, the inspectors reviewed PSEGs decision to replace the A EDG SS on January 6, 2017, with an A-1 model SS susceptible degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process when a currently vendor recommended A-8 model had been available in PSEGs spare SS inventory. PSEGs causal evaluation found that the spare A-8 model SS had been incorrectly tagged as defective prior to January 2017.

The inspectors reviewed the previous FAs performed on the two C EDG SS failures.

Each of these FAs showed visually identical failures of the CR17 and heat damage to the SS board. The inspectors summarized the FAs below:

PSE-07769, the August 4, 2015, C EDG SS FA, dated September 14, 2015, showed clear evidence of the failed (overheated) Zener diode (CR17), and damage to the opposite side of the circuit board voltage regulating chip (LM317). The FA determined the most likely cause of the CR17 failure was the LM317, and refurbishment/repair was not recommended by the vendor.

PSE-79368, the August 4, 2016, C EDG SS FA dated September 16, 2016, showed the failed (overheated) CR17. The inspectors noted that there was no discussion on the condition of the LM317. The FA determined the most likely cause of the CR17 failure was due to questionable CR17 quality combined with minimal operating margin between the CR17 and the SS external voltage regulator. PSEG expedited the refurbishment of the SS by replacing only the failed CR17 because they needed a spare for inventory/contingency.

PSE-10539, the February 3, 2017, A EDG SS FA dated March 28, 2017, showed the failed (overheated) CR17. The FA determined that failed CR17 was identical to the previous SS failure on August 4, 2016, and that the SS board was damaged due to the overheated CR17. The FA also determined that the LM317 had failed, and postulated that when the CR17 overheated during the previous failure on August 4, 2016, the LM317 was damaged due to its proximity to the CR17. The FA also stated that the damage to the LM317 went unrecognized during the FA and refurbishment process, and caused the LM317 to operate at a higher temperature, which caused the newly replaced CR17 to fail again.

Based on the information above, the inspectors determined that PSEG did not prevent the installation of the previously failed SS in the A EDG on January 6, 2017, susceptible to degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process. Subsequently, less than one month later on February 3, 2017, the A EDG failed to start due to the failure of the SS. PSEGs CAs included replacing the SS, identifying an equivalent replacement for the currently installed SS design, scheduling the replacement of the new SSs, and performing extent of condition inspections and testing of all the installed and spare EDG SSs to determine if the CR17 or LM317 components are degraded. PSEG is also currently assessing the past operability of this condition on the A EDG as part of NOTF 20759444 (initiated on March 22, 2017.

Analysis.

Not having adequate control measures to prevent the use of defective parts was a performance deficiency that was within PSEGs ability to foresee and correct and should have been prevented. The inspectors determined that the finding was 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 reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG not preventing the re-installation of the previously failed SS, susceptible to degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process, into the A EDG on January 6, 2017, led to the A EDG failing to start on February 3, 2017. 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 MRP for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, the EDG was restored to operable status in approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because PSEG did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, PSEG did not thoroughly evaluate their previous FAs performed on the failed SSs. This contributed to PSEGs inadequate level of refurbishment of the failed SS from August 4, 2016. [P.2]

Enforcement.

10 CFR Part 50, Appendix B, Criterion VIII, Identification and Control of Materials, Parts and Components, requires, in part, that measures shall be established for the identification and control of materials, parts, and components, and that these identification and control measures shall be designed to prevent the use of incorrect or defective material, parts, and components. Contrary to the above, between August 4, 2016, and February 3, 2017, PSEG did not have adequate control measures to prevent the reuse of defective parts. Specifically, following the C EDG SS failure on August 4, 2016, PSEGs control measures did not prevent the installation of this previously failed SS, susceptible to degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process, into the A EDG on January 6, 2017. Consequently, less than one month later on February 3, 2017, the A EDG failed to start due to a failed SS. PSEGs CAs included replacing the SS, identifying an equivalent replacement for the currently installed SS design, scheduling the replacement of the new SSs, and performing extent of condition inspections and testing of all the installed and spare EDG SSs to determine if the CR17 or LM317 components are degraded. Because this violation was of very low safety significance (Green), and PSEG has entered this performance deficiency into the CAP as NOTF 20754048, the NRC is treating this as an NCV in accordance with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000354/2017001-01; Inadequate Control of Defective Material Causes the A EDG to Fail to Start)

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

.1 (Closed) Licensee Event Report (LER) 05000354/2016-001-00: High Pressure Coolant

Injection (HPCI) System Found to be Inoperable during Testing In Section 4OA2.2 of NRC IR 2016003, the inspectors identified a Severity Level IV NCV of 10 CFR 50.73(a)(2)(v) for not submitting an LER within 60 days of an event or condition that could have prevented the fulfillment of a safety function at any time within 3 years of the date of discovery. Specifically, on April 7, 2016, while performing an IST of the HPCI system, the turbine tripped on overspeed shortly after startup due to low spring force on the overspeed trip tappet assembly reset spring. This condition allowed the overspeed tappet to trip the turbine without an actual overspeed condition present, rendering the HPCI system inoperable and unable to automatically initiate and inject at rated flow within 35 seconds as required per TSs, and which could have prevented the fulfillment of a safety function.

PSEGs CAs for this event included submitting LER 05000354/2016-001-00 under 10 CFR 50.73(a)(2)(v)(D) on October 4, 2016, entering the issue into their CAP under NOTF 20741046, resetting the reset spring to within the proper pre-load band, replacing the reset spring on October 29, 2016, and completing a causal evaluation (ACE 70192131) on March 27, 2017. The inspectors reviewed the event, PSEGs CAs and their ACE, identifying one finding that is discussed below. This LER is closed.

Introduction.

A self-revealing Green NCV of TS 6.8.1, Procedures, was identified because PSEG did not establish an appropriate PM schedule for the HPCI overspeed trip system reset spring. Specifically, PSEGs PM frequency and scope for the HPCI turbine major inspection and overhaul PM was inadequate. As a result, the HPCI overspeed tappet reset spring was not replaced for 8.5 years, resulting in the reset spring force falling below the required force range. Subsequently, on April 7, 2016, the HPCI turbine tripped and then reset shortly after being started because of the low reset spring force, making the HPCI system unable to automatically initiate and inject at rated flow within 35 seconds as required per TSs and the design basis.

Description.

On April 7, 2016, the HPCI system was placed in service for a retest following system maintenance (a planned 36 month removal, clean and inspection of the HPCI governor tubing for wear, water and particulate contamination). Shortly after the HPCI turbine was started, operators received a HPCI turbine trip alarm, where the turbine was noted to trip and then reset over the course of approximately 45 seconds. The HPCI turbine governor was then able to recover and bring the turbine back up to rated speed. PSEGs troubleshooting determined the as-found reset spring force to be 1.0 pound-force (lbf), which was outside the required range of PSEGs HPCI turbine overhaul procedure, HC.MD-PM.FD-0001 (2.0 to 5.0 lbf). PSEG determined that a low reset spring force would allow the HPCI overspeed trip tappet assembly to float upward on a system start-up, tripping the turbine when no actual overspeed condition existed. PSEGs immediate CAs were to reset the spring force to the required range, retest and declare the HPCI system operable.

PSEGs ACE was completed on March 27, 2017, approximately 1 year after the event due to a number of inspector identified performance deficiencies associated with PSEGs inadequate evaluation of the event (See NRC IRs 2016003 and 2017008). PSEGs ACE determined that the most likely cause of the low spring force was due to the effects of age and environmental conditions. Specifically, the ACE determined that the spring had been installed for a period of 8.5 years and that there was no existing PM that specifically included replacement of the reset spring.

The ACE documented that the EPRI Manual, Terry Turbine Maintenance Guide for HPCI Application, recommended replacing the reset spring during the sites major HPCI turbine inspection and overhaul PM. As part of PSEGs CAs, PSEG added the replacement of the reset spring to their existing 12 year HPCI turbine inspection and overhaul PM (Maintenance Plan HC216171). In addition to the reset springs age, PSEGs metallurgical and chemical FAs of the reset spring found incipient corrosion fatigue and material porosity resulting, in part, from increased HPCI room temperatures and humidity caused by known steam admission valve leakage. The ACE included a CA to replace the reset spring during the 6.87 year EQ overspeed trip mechanism PM (MP HC240233).

The inspectors reviewed PSEGs ACE, HPCI PM MPs, industry OE, vendor manuals, the EPRI Manual, and the HPCI Performance Centered Maintenance (PCM) template.

The inspectors reviewed the frequency and scope for the major HPCI inspection and overhaul recommended in these documents, and found that:

The EPRI manual, Section 4.4, Major Inspections and Planned Maintenance, recommends conducting a major HPCI turbine inspection and overhaul at an interval of every four to five refueling outages (a typical time period of 6 to 10 years, unless operating history dictates the need for more frequent inspections), specifically citing areas of concern which include the turbine overspeed trip assembly by replacing the overspeed trip tappet and tappet reset spring as consumable items. The inspectors determined that based on Hope Creeks 1.5 year refueling outage cycle, the major HPCI turbine inspection and overhaul should be performed every 6 to 7.5 years, not every 12 years.

The current HPCI PCM template for Terry (Style) Turbines BWR & Pressurized Water Reactor (PWR), which was revised in 2014, recommends an 8 year frequency stating that this task is focused on, in part, overhauling the overspeed trip mechanism and that underlying failure data does not permit the task interval to be longer than 10 years.

Prior revisions of the template, from the templates inception in 2005, recommended a 10 year frequency.

PSEG conducted a review of the template in 2005, and documented in CAP in Order 80081773-0030 that HC216171 (for all HPCI components) should be 8 year frequency, not 10 years. The inspectors reviewed this and found PSEG did not correct this issue.

Around 2009, PSEG changed the frequency from 10 to 12 years because the NEIL (plant liability insurance) frequency changed to 12 years. The inspectors reviewed the justification for this PM frequency change, documented in Orders 70083138-0010 and 70080151-0090, determining that PSEGs justification for the change was inadequate in that it only included the NEIL frequency recommendation.

PSEGs ACE notes that the industry HPCI subject matter expert recommended replacing the reset spring any time the reset mechanism is breached for a normal PM inspection or overhaul, which would be during Hope Creeks 6.87 year HPCI overspeed trip tappet assembly EQ PM.

PSEGs reset spring component history reveals that the spring had been replaced by different WOs approximately every 4 years starting in 1999 (99, 03, 07) until the most recent 8.5 year period prior to the low spring force being found on April 7, 2016.

Based on the information above, the inspectors determined that PSEGs HPCI major inspection PM frequency and scope justification was not adequate. PSEGs immediate CAs included replacing the reset spring, adding replacement of the spring to the 6.87 year HPCI EQ PM and evaluating the storage requirements for springs in inventory.

Analysis.

The inspectors determined that PSEG not establishing an appropriate PM schedule for the HPCI overspeed trip system reset spring, specifically, the PM frequency and scope justification for their major inspection and overhaul for the HPCI turbine was a performance deficiency that was within PSEGs ability to foresee and correct, and should have been prevented. This performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate PM frequency and scope for the reset spring resulted in the low spring force due to the springs age allowing the trip tappet assembly to float upward on a HPCI system start-up, tripping the turbine when no actual overspeed condition existed. 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, and 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 MRP for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, following the overspeed trip on April 7, 2016, HPCI was restored to operable status in approximately 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance. Specifically, PSEGs inadequate PM schedule for the HPCI overspeed trip tappet assembly reset spring involved multiple missed opportunities to re-evaluate the PMs scope and frequency from 2005 through 2009. In accordance with IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance.

Enforcement.

Technical Specification 6.8.1 states, in part, that written procedures recommended in Appendix A of RG 1.33, Quality Assurance Program Requirements (Operation), Revision 2, February 1978, shall be established, implemented, and maintained. Section 9.b, Procedures for Performing Maintenance, of Appendix A to RG 1.33 states that preventive maintenance schedules should be developed to specify, in part, the inspection of equipment and the replacement of parts. Contrary to the above, since 2005, PSEGs PM frequency and scope justification for the HPCI overspeed trip system reset spring was inadequate. Since the HPCI overspeed tappet reset spring was not replaced for 8.5 years, the reset springs force was low and outside of the required force range. As a result, on April 7, 2016, the HPCI turbine tripped and then reset shortly after being started because of the low reset spring force, making the HPCI system unable to automatically initiate and inject at rated flow within 35 seconds as required per TSs and the design basis. PSEGs immediate CAs included replacing the reset spring, adding replacement of the spring to the 6.87 year HPCI EQ PM and evaluating the storage requirements for springs in inventory. Because this finding was of very low safety significance (Green) and has been entered into PSEGs CAP (NOTF 20754662), this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000354/2017001-02; Inadequate Preventive Maintenance Replacement Schedule for the HPCI Overspeed Trip Tappet Reset Spring)

.2 (Closed) LER 05000354/2016-004-00: Operations with a Potential to Drain the Reactor

Vessel (OPDRV) Without Secondary Containment On October 23, 24, and 31, 2016, during a planned refueling outage with the reactor cavity flooded up in Mode 5, Hope Creek conducted multiple OPDRVs without an operable secondary containment. The conduct of an OPDRV without establishing secondary containment integrity is a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B). Secondary containment is required by TS 3/4.6.5.1 in Operational Condition (*), which is a condition when recently irradiated fuel is being handled during an OPDRV. The required action for this specification is to suspend handling recently irradiated fuel and OPDRV operations.

In this case, the specific OPDRVs were control rod drive mechanism replacements (8:40 a.m. on October 23, 2016, through 10:50 p.m. on October 23, 2016), local power range monitor replacements (10:50 p.m. on October 23, 2016, through 8:07 a.m. on October 24, 2016), additional control rod drive mechanism and local power range monitor replacements (8:07 a.m. on October 24, 2016, through 8:23 a.m. on October 25, 2016), and the fill and vent for the A and B RRP seal (11:21 a.m. on October 31, 2016, through 12:02 p.m. on November 1, 2016).

The OPDRVs were completed in accordance with PSEG procedure OP-HC-108-102, "Management of Operations with the Potential to Drain the Reactor Vessel (OPDRV),"

Revision 5, dated October 6, 2016. These OPDRVs were completed and exited at 12:02 p.m. on November 1, 2016.

The NRC issued EGM 11-003, Revision 3, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential For Draining the Reactor Vessel, on January 15, 2016, which provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has implemented specific interim actions during any OPDRV activity. The inspectors determined that PSEGs implementation of these specific interim actions during these OPDRV activities were adequate and met the intent of EGM 11-003, Revision 3.

The inspectors assessments of PSEGs implementation of these criteria during each of the multiple OPDRV activities are described below:

The inspectors observed that, as required by the EGM, the OPDRV activity was logged in the control room narrative logs and that the log entry appropriately recorded the safety-related pump (B RHR) that was the standby source of makeup designated for the evolution.

The inspectors noted that the reactor vessel water level was maintained at least 22 feet and 2 inches over the top of the reactor pressure vessel (RPV) flange in compliance with the minimum water level allowed by Hope Creek TS limiting condition for operation (LCO) 3.9.8 applicability.

The inspectors also noted that at least one safety-related pump was the standby source of makeup designated in the control room narrative logs for the evolution with the capability to inject water equal to, or greater than, the maximum potential leakage rate from the RPV for a minimum time period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

PSEG reported that the worst case estimated time to drain the reactor cavity to the RPV flange was 36.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, which met the EGM criteria of greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The inspectors verified that the OPDRV was not conducted in Mode 4 and that PSEG did not move recently irradiated fuel during the OPDRV.

The inspectors noted that PSEG had in place a contingency plan for isolating the potential leakage path.

The inspectors verified that two independent means of measuring RPV water level (one alarming) were available for identifying the onset of loss of inventory events with sufficient time to close secondary containment before reactor water level reached the top of the RPV flange.

Technical Specification 3.6.5.1 is applicable in Operational Conditions 1, 2, 3 and (*).

This TS requires that secondary containment integrity shall be maintained. Operational Condition (*) is defined, in part, as being during OPDRV. TS 3.6.5.1, action b, states, in part, in operational condition (*) suspend operations with a potential for draining the reactor vessel. Contrary to the above, between 8:40 a.m. on October 23, 2016, and 12:02 p.m. on November 1, 2016, Hope Creek Generating Station did not maintain secondary containment integrity while conducting OPDRV activities. Because the violation was identified during the discretion period described in EGM 11-003 Revision 3, the NRC is exercising enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.5, Violations Involving Special Circumstances, and, therefore, will not issue enforcement action for this violation.

In accordance with EGM 11-003 Revision 3, each licensee that receives discretion must submit a license amendment request within 4 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the STS to provide more clarity to the term OPDRV. The inspectors observed that PSEG is tracking the need to submit a license amendment request in its CAP as NOTF 20559547 (Order 70138857). No findings were identified. This LER is closed.

.3 (Closed) LER 05000354/2016-005-00 and -01: Reactor Protection System Actuation

while the Reactor was Shutdown On November 5, 2016, a RPS actuation occurred during a valid scram discharge volume high water level signal, causing the B reactor recirculation pump to trip and the scram air header to depressurize. The reactor was in cold shutdown at the time of the RPS actuation, with all control rods inserted and shutdown cooling was removed from service to support planned excess flow check valve testing. PSEG determined that the RPS actuation was the result of a Redundant Reactivity Control System (RRCS) Alternate Rod Insertion (ARI) signal that was inadvertently generated during planned testing.

PSEG reported this as a condition reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual or automatic actuation of RPS. PSEG concluded that the apparent causes for this inadvertent signal were inadequate testing procedures, specifically, unc lear direction for the performance of required steps during excess flow check valve testing and incorrect logic used for disabling system trips for RRCS. PSEG entered the issue into their CAP as NOTF 20746413, and CAs included revising the multiple testing procedures involved and conducting training with all operators on the event and the use of the procedures. The inspectors determined that:

1) all plant systems responded as designed; 2) the RPS actuation did not cause any required system to become inoperable or any design limits to be exceeded; and, 3) there were no adverse safety consequences as a result of this event. While the inspectors determined that PSEGs inadequate procedures was a performance deficiency, the issue was determined not to be more than minor because there was no actual safety consequence and the mitigating systems cornerstone was not adversely affected as result of this event. This LER is closed.

.4 (Closed) LER 05000354/2016-006-00 and -01: Mode Change without B Channel Level

Instrumentation Operable On November 9, 2016, with the Hope Creek reactor in operational condition 2 (OPCON 2), startup, the B channel reactor level instrumentation was found to be inoperable. The inoperable instrumentation was discovered as reactor water level was being lowered into the normal band in preparation for reactor startup. The B channel reactor level instrumentation is required to be operable in order to enter OPCON 2 to support the B division of RPS, the ECCS, and the primary containment isolation system. PSEG determined the cause to be an improperly filled reference leg for the B channel reactor level instrumentation. PSEG reported this as a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as a condition which was prohibited by TSs. PSEG entered the issue into their CAP as NOTF 20749938, and CAs included securing the reactor startup, conducting system troubleshooting/restoration prior to recommencing the reactor startup, performing an extent of condition on all DCPs completed during the refueling outage, and revising their preventive maintenance procedures to ensure that the instrument racks are properly backfilled on a frequent reoccurring basis and following any instrument rack maintenance. The inspectors reviewed this event, PSEGs completed causal evaluation completed under Order 70190770, and NRC Inspection Report 2016004, which documented a Green self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, and TS 3.0.4 for PSEG inadequately implemented their configuration change control procedure, CC-AA-103, and a design change package (DCP 80108179) for rerouting a B channel instrument line (LT-N085B)by not fully restoring the system upon completion of the DCP on November 3, 2016. As a consequence, multiple MCR indicators became inoperable without PSEG identifying the problem until operators transitioned the reactor plant to startup, OPCON 2 or Mode 2, on November 9, 2016. This constituted a violation of TS 3.0.4 because PSEG transitioned to OPCON 2 while multiple LCOs were not met. The inspectors did not identify any additional performance deficiencies associated with this event. This LER is closed.

4OA5 Other Activities

.1 Operation of an Independent Spent Fuel Storage Installation at Operating Plants

(60855, 60855.1)

a. Inspection Scope

On March 6, 2017, the inspectors were onsite to observe PSEGs loading of a multi-purpose canister (MPC) - 484, the second of six canisters to be loaded during the licensees Independent Spent Fuel Storage Installation (ISFSI) dry cask campaign. The inspectors reviewed documentation related to PSEGs planned activities for the loading of a MPC. However, due to equipment and scheduling issues, PSEGs loading campaign was rescheduled to June 2017. As of March 23, 2017, the loading campaign was cancelled for the year and the casks planned for this campaign will be added to the next campaign planned for 2020. The inspectors reviewed NOTF 20756568, WO 60133849, and interviewed plant personnel to ensure PSEG was taking appropriate corrective action for the equipment issues.

b. Findings

No findings were identified.

.2 Temporary Instruction 2515/192, Inspection of the Licensees Interim Compensatory

Measures Associated with the Open Phase Condition Design Vulnerabilities in Electric Power Systems.

a. Inspection Scope

The objective of this performance based temporary instruction (TI) is to verify implementation of interim compensatory measures associated with an open phase condition (OPC) design vulnerability in electric power system for operating reactors. The inspectors conducted an inspection to determine if PSEG had implemented the following interim compensatory measures. These compensatory measures are to remain in place until permanent automatic detection and protection schemes are installed and declared operable for OPC design vulnerability. The inspectors verified the following:

PSEG had identified and discussed with plant staff the lessons-learned from the OPC events at the US operating plants including the Byron station OPC event and its consequences. This includes conducting operator training for promptly diagnosing, recognizing consequences, and responding to an OPC event.

PSEG had updated plant operating procedures to help operators promptly diagnose and respond to OPC events on off-site power sources credited for safe shutdown of the plant.

PSEG had established and continue to implement periodic walkdown activities to inspect switchyard equipment such as insulators, disconnect switches, and transmission line and transformer connections associated with the offsite power circuits to detect a visible OPC.

PSEG had ensured that routine maintenance and testing activities on switchyard components have been implemented and maintained. As part of the maintenance and testing activities, PSEG assessed and managed plant risk in accordance with 10 CFR 50.65(a)(4) requirements.

b. Findings and Observations

No findings were identified. The inspectors verified the TI or above criteria were met.

4OA6 Meetings, Including Exit

On April 13, 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

C. Barnes, Used Fuel Loading Project Manager

S. Bier, Operations Shift Manager

J. Boyer, Mechanical/Structural Design Manager, Design Engineering

L. Clark, Nuclear Technical Supervisor

B. Doody, Principal Engineer, Corporate IST

A. Hak, System Engineer

K. Hutko, Senior, Hope Creek Program Engineering

W. Kopchick, Site Engineering Director

M. Loewenstein, Design Engineer

S. Madden, Manager, Design Engineering

A. Ochoa, Regulatory Assurance Senior Compliance Engineer

S. Poinsett, Q-Technician

L. Powell, Technical Analyst, Design Engineering

J. Thompson, Procurement Engineer

H. Trimble, Radiation Protection Manager

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open and

Closed

05000354/2017001-01 NCV Inadequate Control of Defective Material Causes the A EDG to Fail to Start (Section 4OA2.2)

05000354/2017001-02 NCV Inadequate Preventive Maintenance Replacement Schedule for the HPCI Overspeed Trip Tappet Reset Spring)

(Section 4OA3.1)

Closed

05000354/2016-001-00 LER High Pressure Coolant Injection (HPCI)

System Found to be Inoperable during Testing (Section 4OA3.1)

05000354/2016-004-00 LER Operations with a Potential to Drain the Reactor Vessel (OPDRV) Without Secondary Containment (Section 4OA3.2)

05000354/2016-005-00 and-01 LER Reactor Protection System Actuation While the Reactor was Shutdown (Section 4OA3.3)

05000354/2016-006-00 and -01 LER Mode Change without B Channel Level Instrumentation Operable (Section 4OA3.4)