IR 05000354/2015007

IR 05000354/2015007; 9/21/15 to 10/23/15; Hope Creek Generating Station; Component Design Bases Inspection

ML15329A157
Person / Time
Site:	Hope Creek
Issue date:	11/25/2015
From:	Paul Krohn Engineering Region 1 Branch 2
To:	Braun R Public Service Enterprise Group
References
IR 2015007
Preceding documents:	ML16040A345 (9 February 2016)
Download: ML15329A157 (42)

Text

UNITED STATES ember 25, 2015

SUBJECT:

HOPE CREEK GENERATING STATION - COMPONENT DESIGN BASES INSPECTION REPORT 05000354/2015007

Dear Mr. Braun:

On October 23, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Hope Creek Generating Station. The enclosed inspection report documents the inspection results, which were discussed on October 23, 2015, with Mr. Eric Carr, Plant Manager, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

In conducting the inspection, the team examined the adequacy of selected components to mitigate postulated transients, initiating events, and design basis accidents. The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.

This report documents two NRC-identified findings that were of very low safety significance (Green). These findings were determined to involve violations of NRC requirements. However, because of the very low safety significance of the violations and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Senior Resident Inspector at Hope Creek. In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 Regional Administrator, Region I, and the NRC Senior Resident Inspector at Hope Creek. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for the public inspection in the NRC Public Docket Room or from the Publicly Available Record System (PARS) component of NRCs document system, Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Paul G. Krohn, Chief Engineering Branch 2 Division of Reactor Safety Docket No. 50-354 License No. NPF-57

Enclosure:

Inspection Report 05000254/2015007 w/Attachment: Supplementary Information

REGION I==

Docket No: 50-354 License No: NPF-57 Report No: 05000354/2015007 Licensee: Public Service Enterprise Group (PSEG) Nuclear LLC Facility: Hope Creek Generating Station (HCGS)

Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Inspection Period: September 21 through October 23, 2015 Inspectors: J. Schoppy, Senior Reactor Inspector, Team Leader Division of Reactor Safety (DRS)

J. Brand, Reactor Inspector, DRS J. Kulp, Senior Reactor Inspector, DRS S. Makor, Reactor Inspector, RIV/DRS S. Kobylarz, NRC Electrical Contractor M. Yeminy, NRC Mechanical Contractor Approved By: Paul G. Krohn, Chief Engineering Branch 2 Division of Reactor Safety i Enclosure

SUMMARY

IR 05000354/2015007; 9/21/15 - 10/23/15; Hope Creek Generating Station; Component Design

Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of four NRC inspectors and two NRC contractors. Two findings of very low safety significance (Green) were identified, both of which were considered to be non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process. Cross-cutting aspects associated with findings are determined using IMC 0310, Components Within the Cross-Cutting Areas.

The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision

Cornerstone: Mitigating Systems

Green.

The team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not establish appropriate acceptance criteria for the time allowed for starting the residual heat removal (RHR) and core spray pumps during simulated loss-of-coolant accident/loss-of-offsite power (LOCA/LOP) conditions in the 18-month integrated emergency diesel generator (EDG) surveillance test (ST) for the vital 4KV buses.

Specifically, the ST acceptance criteria failed to confirm that the pumps started in accordance with the design basis loading sequence described in the design analyses and Updated Final Safety Analysis Report Table 8.3-1. PSEGs short-term corrective actions included reviewing LOCA/LOP test results and plant historical data to confirm current operability of the RHR and core spray pumps, and initiating corrective action notifications to determine the appropriate ST acceptance criteria and to trend pump start times.

The team determined that the failure to specify adequate acceptance limits for the design basis assigned start times for the RHR and core spray pumps during LOCA/LOP conditions in the 18-month integrated EDG ST procedure was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a design deficiency that did not result in the loss of operability or functionality. The team determined that this finding has a cross-cutting aspect in Human Performance, Documentation, in that PSEG failed to maintain accurate test acceptance documentation to aid plant staff in the identification of equipment performance that was outside the acceptable limits of design.

(H.7) (Section 1R21.2.1.1)ii

Green.

The team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not provide adequate work order instructions for the reinstallation of service water (SW) pump discharge isolation valve EAHV-2198C following planned valve maintenance in October 2013. Specifically, the inadequate work order instructions contributed directly to maintenance technicians installing the valve in the opposite orientation compared to the intended orientation. PSEG entered this issue into their corrective action program. In addition, PSEGs corrective actions included completing several associated technical evaluations, calculations, operability determinations, and motor-operated valve performance tests.

The team determined that the failure to provide adequate work order instructions for the installation of safety-related SW valve 2198C was a performance deficiency. The team determined that this performance deficiency was more than minor in accordance with IMC 0612, Power Reactor Inspection Report, Appendix B, because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems (SW)that respond to initiating events to prevent undesirable consequences. Additionally, the team determined that it was more than minor in accordance with IMC 0612, Appendix E,

Example 3j, because PSEGs associated operability and technical evaluations did not adequately consider the worst case conditions, resulting in a potential underestimation of the maximum required opening torque and in a condition where there was a reasonable doubt on the operability of the C SW train. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a deficiency that affected the design and qualification of safety-related SW valve 2198C but did not result in the loss of operability or functionality. The team determined that this finding has a cross-cutting aspect in Human Performance, Documentation, in that PSEG failed to ensure that design documentation and work packages were complete, thorough, accurate, and current.

(H.7) (Section 1R21.2.1.2)

Other Findings

None iii

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R21 Component Design Bases Inspection (IP 71111.21)

.1 Inspection Sample Selection Process

The team selected risk significant components for review using information contained in the Hope Creek Probabilistic Risk Assessment (PRA) model and the U. S. Nuclear Regulatory Commissions (NRC) Standardized Plant Analysis Risk (SPAR) model for the Hope Creek Generating Station (HCGS). Additionally, the team referenced the Plant Risk Information e-Book (PRIB) for Hope Creek in the selection of potential components for review. In general, the selection process focused on components that had a Risk Achievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW)factor greater than 1.005. The components selected were associated with both safety-related and non-safety related systems, and included a variety of components such as pumps, tanks, diesel engines, batteries, electrical buses, circuit breakers, and valves.

The team initially compiled a list of components based on the risk factors previously mentioned. Additionally, the team reviewed the previous component design bases inspection (CDBI) reports and excluded the majority of those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 16 components and 5 operating experience (OE) items. The team selected the suppression pool and a drywell spray valve to review for large early release frequency (LERF) implications. The teams evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, Maintenance Rule (a)(1) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry OE. Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins.

The team performed the inspection as outlined in NRC Inspection Procedure (IP)71111.21. This inspection effort included walkdowns of selected components; interviews with operators, system engineers, and design engineers; and reviews of associated design documents and calculations to assess the adequacy of the components to meet design basis, and licensing basis requirements. Summaries of the reviews performed for each component and OE sample are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the Attachment.

.2.1.1 C' Emergency Diesel Generator (Electrical Review) and C 4KV Bus 10A403

a. Inspection Scope

The team inspected the C EDG and its associated 4KV electrical bus (10A403) to verify that they were capable of performing their design functions in response to transients and accidents. The team reviewed technical specifications (TSs), operating procedures, and the Updated Final Safety Analysis Report (UFSAR) to determine the licensing and operating basis for selected electrical components utilized for starting the C EDG and for connecting the generator to the safety-related C 4KV bus. The team reviewed the EDG loading design basis requirements for postulated loss-of-coolant accident (LOCA)and loss-of-offsite power (LOP) conditions. The team reviewed ST results to verify that operation of the EDG, and selected emergency core cooling system (ECCS) pumps, conformed to design basis loading requirements. The team reviewed voltage drop calculations for the diesel air starting solenoids and the generator field flash circuitry to assure that adequate voltage was available during limiting design basis conditions. The team interviewed the system engineer, reviewed the system health report, and performed a walkdown of the C EDG and the C 4KV bus to assess the observable material condition. The team also reviewed maintenance records and corrective action documents to ensure that PSEG properly maintained the components and identified and corrected deficiencies.

b. Findings

Introduction.

The team identified a Green non-cited violation (NCV) Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not establish appropriate acceptance criteria for the time allowed for starting the residual heat removal (RHR) and core spray pumps during simulated LOCA/LOP conditions in the 18-month integrated EDG ST for the vital 4KV buses. Specifically, the ST acceptance criteria failed to confirm that the pumps started in accordance with the design basis loading sequence described in the design analyses and UFSAR Table 8.3-1.

Description.

The team noted that the start time acceptance criteria in the 18-month integrated C EDG ST for the RHR and core spray pump motors in HC.OP-ST.KJ-0007, Steps 5.4.8.S and 5.4.8.V, respectively, was 40 seconds and 27 seconds, respectively, after initiation of a simulated LOCA/LOP condition. Based on a review of the General Electric (GE) design drawings for the RHR and core spray pump start circuits, the team noted that the RHR pump was designed to start immediately when 4KV bus power was available either during a LOCA condition (with offsite power available) or during LOCA/LOP conditions after the EDG established bus power, and then for the core spray pump to start six seconds later by a timer circuit which was initiated when the bus power was available.

The team identified that the integrated EDG 18-month ST acceptance criteria did not correctly incorporate the GE pump start design criteria for the RHR and core spray pumps. For example, the EDG was designed to establish bus power nominally within 13-seconds after LOCA conditions and the RHR pump should then start immediately, but the ST acceptance criteria allowed for the pump to start up to 27 seconds later (40 seconds minus the 13 seconds for power to be established by the EDG after the LOCA conditions are detected). In addition, although the RHR pump should start immediately when the EDG breaker closes and 4KV power is available, followed 6 seconds later by the core spray pump in accordance with GE criteria, the acceptance criteria for the RHR pump was 40 seconds and 27 seconds for the core spray pump.

These acceptance criteria could allow the core spray pump to start before the RHR pump, resulting in an unanalyzed condition contrary to the design basis loading sequence described in the design analyses and UFSAR Table 8.3-1. In fact, the team identified that technicians recorded pump start times in the last integrated B EDG 18-month ST conducted in April 2015 that indicated that the core spray pump had started before the RHR pump, which would have been contrary to the GE design criteria for the pump starting sequence. The team also noted that PSEG had failed to identify this test anomaly during their post-test acceptance review. The team noted that PSEG had based the ST acceptance criteria on the maximum time for pump flow to be delivered to the reactor vessel and not the designed pump start time for the RHR and core spray pumps. Based on this, the team concluded that the ST start time acceptance criteria for the RHR and core spray pumps was incorrect and non-conservative. During the inspection, upon further review of the plant historical data and strip chart recordings from the April 2015 test, PSEG determined that the RHR and core spray pump start times recorded by the technicians were inadvertently swapped in the ST documentation as the actual recorded test data confirmed that the RHR pump actually started before the core spray pump in accordance with the GE design. This NRC-identified test discrepancy was neither identified nor evaluated by PSEG during their review of the test results in April 2015.

Notwithstanding, upon further review of the swapped data, the team found that the core spray pump started approximately 3.8 seconds after the EDG breaker was closed to establish bus power. However, starting the core spray pump 3.8 seconds after power was established during a LOCA/LOP was not in accordance with TS acceptance criteria for the minimum time for the core spray pump to start which was 5 seconds (6 seconds

+/- 1 second) when power was available. For this case, during the inspection, PSEG engineers reviewed the strip chart recorder record traces for the EDG voltage and frequency conditions during the core spray pump start and confirmed that the voltage and frequency recovered within acceptable limits, thereby assuring EDG operability.

Based on a review of the two most recent LOCA/LOP STs for each 4KV vital bus (completed in the Fall of 2013 and the Spring of 2015), the team also identified several additional examples of discrepant RHR and core spray pump start time data in the recorded and accepted test results. These discrepancies included:

1. During the A EDG test in 2013, the core spray pump started only 3 seconds

after bus power was established by the EDG (the TS minimum acceptance limit was 5 seconds as noted above). During the D EDG test in 2013, the core spray pump started 4.9 seconds after power was established, which was also not in accordance with the minimum TS acceptance limit. Subsequent STs performed since 2013 confirmed the proper operation and operability for the subject core spray pumps.

2. For the A EDG test in 2015, for the corrected data for the B EDG test in

2015, and for the C EDG test in 2013, the recorded test data indicated that the RHR pump started before the EDG breaker was closed to establish bus power. The team noted that this condition was not possible based upon a review of GEs design drawings for the RHR pump start circuit.

Based upon further review and discussions onsite, the team noted that the accuracy of technicians recorded data was questionable and that some (see item 2 above), but not all, of the above discrepant conditions could be due to technician response time when using a stopwatch to record pump start times. Once again, the above NRC-identified discrepancies were neither identified nor evaluated by PSEG during their review of the test results at the time of the testing.

The team noted that the non-conservative ST acceptance criteria for the RHR and core spray pump start times had the potential to mask conditions where equipment performed outside expected design limits, and these conditions could neither be detected nor evaluated by PSEG for impact to plant equipment and systems. PSEG initiated notification (NOTF) 20706543 to evaluate test results for any adverse trend in pump start times and NOTF 20706542 to evaluate the ST test acceptance criteria for the RHR and core spray pump start times.

Analysis.

The team determined that the failure to specify adequate acceptance limits for the design basis assigned start times for the RHR and core spray pumps during LOCA/LOP conditions in the 18-month integrated EDG ST procedure was a performance deficiency. The team determined that this finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG failed to identify appropriate EDG loading acceptance criteria for the RHR and core spray pump motor start timing that was used in the ST to confirm that safety-related equipment was operating in accordance with the limits specified in the design analyses. The team evaluated the finding in accordance with Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a design deficiency that did not result in the loss of operability or functionality. The team determined that this finding had a cross-cutting aspect in Human Performance, Documentation, in that PSEG failed to maintain accurate test acceptance documentation to aid plant staff in the identification of equipment performance that was outside the acceptable limits of design. (H.7)

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, prior to October 22, 2015, PSEG had not established appropriate acceptance criteria in HC.OP-ST.KJ-0007, Steps 5.4.8.S and 5.4.8.V, respectively, for the time allowed for starting the RHR pump and core spray pumps during simulated LOCA/LOP conditions in the 18-month integrated EDG ST for the vital 4KV buses.

Specifically, the ST acceptance criteria failed to confirm that the pump(s) starting would be in accordance with the design basis loading sequence described in design analyses and UFSAR Table 8.3-1, Emergency Loads Assignment of Class 1E and Selected Non-Class 1E Loads on Standby Diesel Generator Buses. PSEGs short-term corrective actions included reviewing LOCA/LOP test results and plant historical data to confirm current operability of the RHR and core spray pumps and initiating corrective action NOTFs to determine the appropriate ST acceptance criteria and trend pump start times. Because this finding was of very low safety significance and because it was entered into PSEGs corrective action program (NOTFs 20706542 and 20706543), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000354/2015007-01, Failure to Establish Appropriate Acceptance Criteria for RHR and Core Spray Pump Start Times during Simulated LOCA/LOP Testing)

.2.1.2 Service Water Pump Discharge Valves (EAHV- 2198C and EAHV- 2198D)

a. Inspection Scope

The team reviewed applicable portions of TSs, the UFSAR, and system design basis documents (DBDs) to identify design basis requirements for service water (SW) pump discharge valves EAHV-2198 C and D. The team reviewed drawings and vendor documents to verify that the installed configuration of the valves and their Limitorque motor operators supported the design basis function under normal and accident conditions. The team reviewed the valves orientation and their distance from elbows and from the pumps discharge check valves to assess possible cavitation and flow disturbances. The team interviewed the system engineer and the motor-operated valve (MOV) engineer to discuss the valves analyses and operational and maintenance history, and to verify that PSEG appropriately addressed potentially degraded conditions.

The team reviewed test procedures and recent test results against design bases documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. The team also reviewed MOV test data and valve operator test traces to validate that the torque required to open the valves did not exceed the rating of their Limitorque operators. The team reviewed vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action system documents to verify that potential degradation was monitored or prevented, and that scheduled component inspections or replacements were consistent with trend data and vendor recommendations. The team conducted several detailed walkdowns to visually inspect the physical/material condition of the valves, their motor operators and support systems, and to ensure adequate configuration control.

b. Findings

Introduction.

The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not provide adequate work order instructions for the installation of SW pump discharge isolation valve 2198C following planned valve maintenance in October 2013. Specifically, the inadequate work order instructions contributed directly to maintenance technicians installing the valve in the opposite orientation compared to the intended orientation.

Description.

1EAHV-2198C is the C SW pump discharge isolation valve. The valve is a 28-inch Weir Tricentric butterfly valve with a SMB-1/HBC-4 (60-1) Limitorque motor operator. The valve has an active safety function in the open position to provide normal SW flow to the safety-related safety auxiliaries cooling system (SACS) heat exchangers (HXs) and non-1E reactor auxiliaries cooling system (RACS) HXs, and emergency SW flow to other systems. PSEG had originally intentionally installed all four 1EAHV-2198 valves in the reverse flow direction to permit the downstream header pressure to seat the valve tighter to minimize seat leakage during SW pump and strainer on-line maintenance. During refueling outage 18 (RF18) in October 2013, PSEG performed a planned refurbishment of the 2198C valve and SMB-1 actuator under work order 60112463-410, Step 1.D. On October 22, 2013, maintenance technicians initiated NOTF 20626219 to document that while installing the 1EAHV-2198C adapter plate, they noticed that the valve was installed 180 degrees different from where it was removed and requested support. The NOTF also documented that the MOV engineer agreed that reconfiguring the valve operator would be the easiest way to correct the issue. In an October 23, 2013, update to the NOTF, maintenance stated that they had applied match marks to ensure that the valve would be installed in the same orientation, but during the course of the work the match marks were erased. Maintenance also updated the NOTF to reflect that they had identified that the 2198 valve installation orientation design specification was not documented in valve drawing M-10-1 or the vendor manual (VTD 323981) as expected. The team also noted that several diagrams within the work order depicted the wrong valve orientation and may have contributed to the configuration control error. Finally, the team noted that there was no documented evaluation of the impact of this misalignment and configuration error prior to operations declaring the C SW pump operable following the 2198C maintenance on October 23. PSEG initiated NOTF 20705874 for this operability screening performance gap.

Based on the narrative logs, the team noted that operators started and stopped the C SW pump several times during the period October 23 - 26, 2013 (with proper function of the 2198C). At 10:59 p.m. on October 26, 2013, operators started the C SW pump (in support of the ongoing A LOCA/LOP ST), but the 2198C failed to open.

Operators promptly initiated NOTF 20627235 and entered an unplanned TS limiting condition for operation (LCO) for the C SW pump. PSEG performed troubleshooting and identified that a high opening torque (> ~ 9500 ft-lbs) tripped the torque switch removing power to the valve actuator and resulting in a failure to stroke. PSEG bumped up the torque switch setting to ~ 13,200 ft-lbs and successfully stroked the valve open.

At 4:44 p.m. on October 27, 2013, while stroking open the valve, engineers recorded a maximum opening torque of 10,201 ft-lbs via a MOV dynamic trace. At 8:53 p.m. on October 27, 2013, operators declared the C SW pump operable and exited the TS LCO.

The team noted that there was no apparent documented evaluation of the cause of the unexpected high opening torque or an assessment of the recorded maximum opening torque (10,201 ft-lbs) relative to the maximum expected opening torque under design basis conditions compared to the MOVs weak link analysis and Limitorque limits.

On February 7, 2014, Weir Valves & Controls USA filed an Interim 10 CFR Part 21 Report for a potential failure associated with Weir valves installed in the forward flow orientation (like the 2198C valve). Based on testing (by PSEG and Weir in December 2013), Weir determined that there existed an unseating load which was not accounted for in Weir's Tricentric triple offset product line operator sizing methodology. A potential operator sizing issue could exist on Tricentric valves which have an open safety function during an event. Weir identified that the direction of flow across the non-symmetrical disc had an impact on the torque required to open/close the valve. PSEG initiated NOTF 20639544 and order 70163546 to evaluate and resolve the potential issue. For Hope Creek, PSEG determined that 17 MOVs could be affected by this issue. The preliminary evaluation under order 70163546-020 only identified one potential operational issue requiring any further evaluation (the 1EAHV-2198C valve that maintenance had installed backwards during RF18, prior to the issuance of the Part 21).

For this installation, the maximum differential pressure (DP) only exists on the inlet side of the disc during disc opening when the C SW pump is the first pump started in the A SW loop. Engineering determined that the required stem torque to open the 2198C valve was above the component rating. PSEGs MOV program procedure guidance allows this condition (up to 113 percent of the rated torque) for a limited number of strokes (100). PSEG also initiated NOTF 20673076 to reverse the flow direction of the valve during RF20 in October 2016, so the allowed strokes would not be exceeded. In addition, PSEG performed a technical evaluation to assess the adequacy of MOV 1EAHV-2198C in its installed orientation and evaluated it for a Use-As-Is interim disposition as defined by PSEG procedure CC-AA-11 (70163546-070).

While performing the technical evaluation, engineering identified that the 2198C opening torque would exceed the 113 percent rated torque (14,464 ft-lbs) if they used the SW pump shutoff head in their calculation of maximum DP. PSEG contracted with MPR Associates to perform a more detailed evaluation. MPRs associated calculation reduced the required opening torque from 17,479 ft-lbs to 13,814 ft-lbs (108 percent of the Limitorque limit). The team observed that PSEGs associated technical evaluation noted the high opening torque (10,201 ft-lbs) recorded on October 27, 2013; however, the evaluation only cited it as evidence that the opening torque remained acceptable when opening the 2198C valve (while starting the C SW pump) with the A SW pump running under normal operating conditions (less than the maximum DP expected under design basis conditions). The team noted that there was no apparent documented evaluation comparing the recorded actual opening torque (10,201 ft-lbs) to the expected opening torque (calculated based on the DP at the time) to ensure validity and applicability of the Weir calculation methodology.

During the 2015 CDBI, based on the extremely high opening torque recorded under normal conditions and the valves lack of margin, the team questioned the operability of the 2198C valve to function under design basis conditions (starting the C SW pump without the A SW pump running). Based on the teams concern, engineering initiated NOTF 20704783 to perform a technical evaluation to determine if the 2198C actuator was capable of opening the valve under all required conditions based on the actual measured data. Engineering used conservative assumptions and appropriate engineering rigor to determine the approximate DP that existed when the 2198C valve opened on October 27, 2013, when the dynamic MOV trace recorded an opening torque of 10,201 ft-lbs. Engineering estimated the DP at 50.2 pounds square inch differential (PSID). PSEG entered this DP into the Weir spreadsheet (provided with the associated Interim Part 21 Report) and noted that it resulted in a much lower required opening torque (8,375 ft-lbs compared to 10,201 ft-lbs). The apparent disparity between the measured value (10,201 ft-lbs) and the calculated value (8,375 ft-lbs) affirmed the teams concern that other factors may be at play affecting the torque required to open this particular valve and/or called into question the validity of the Weir spreadsheet calculation for this particular configuration (parallel pump operation, closing the discharge isolation valve with the parallel pump running). Based on the 21.8 percent difference between the calculated Weir expected opening torque of 8,375 ft-lbs at 50.2 PSID and the measured torque of 10,201 ft-lbs, PSEGs technical evaluation (70180794-010) added an additional 3,039 ft-lbs (22 percent) to the Weir expected maximum opening torque of 13,814 ft-lbs at the MPR calculated maximum DP of 80.7 PSID to bound the potential impact.

This resulted in an expected maximum opening torque of 16,853 ft-lbs utilizing the Weir Tricentric unseating torque evaluation model. However, PSEG recognized that this final expected torque would exceed the Limitorque 113 percent rating of 14,464 ft-lbs, requiring additional analysis. To ensure sufficient torque margins, PSEG contracted with Kalsi Engineering to perform H4BC gear box torque analyses for the 2198C valve.

Based on the Kalsi analysis, the EAHV-2198C H4BC gear box can continue to operate safely for at least 9 cycles (open strokes) at an opening torque level up to 20,000 ft-lbs.

In addition, PSEGs technical evaluation noted that the torque switch is bypassed during C SW pump starts under LOCA/LOP conditions ensuring that the torque switch would not preclude valve opening if the open torque exceeded 13,200 ft-lbs. Based on the Kalsi analysis and bypass of the open torque switch under accident conditions, the team concurred with PSEGs determination that the 2198C valve remained operable (although non-conforming).

The team noted that PSEGs technical evaluation also credited starting the C SW pump twice in RF19 in April 2015, with the A SW pump not running, demonstrating that the EAHV-2198C valve was fully capable of opening under the worst case condition (highest expected DP) without tripping the torque switch (not needing the additional torque margin calculated by Kalsi). The team independently reviewed the operator narrative logs and plant historical SW flow data associated with the two credited C SW pump starts to verify that the conditions actually represented worst case conditions. The team confirmed that the A SW pump was indeed out of service when operators started the C SW pump on both occasions. However, the team identified that the A SW pump was also not running on both occasions when the operators stopped the C SW pump. More importantly, the A SW pump discharge pressure was not present on the backside of the 2198C valve while it was closing (prior to the subsequent opening). The team recalled that the Weir Interim Part 21 Report stated that the DP across the valve while closing the valve made a noted difference to the subsequent unseating torque when re-opening the valve. The team noted that the A SW pump was running when closing the 2198C on both occasions in October 2013 prior to the 2198C experiencing a relatively high torque on the subsequent opening. Thus, based on the facts and actual plant configuration during the October 2013 and April 2015 C SW pump starts, the team determined that the C SW pump starts in April 2015 did not adequately demonstrate the capability of the 2198C valve to function under worst case design basis conditions, and could not be credited solely to confirm continued operability of the 2198C. Also, based on the information provided during the inspection, the team noted that Weirs testing in support of their February 2014 Interim Part 21 Report did not include parallel pump combinations and potential effects of closing the subject valve with the redundant (parallel) pump in service.

During the inspection, the team also noted that engineering did not completely and accurately follow PSEG procedure CC-AA-11, Nonconforming Materials, Parts, or Components, during their technical evaluation in response to the Weir Interim Part 21 Report (70163546-070). In particular, the team identified that engineering did not enter the operability determination process (OP-AA-108-115) as required by procedure CC-AA-11 for safety-related components which would likely had resulted in a determination of operable but non-conforming for the degraded 2198C valve. The team noted that this represented a minor procedure violation; however, failing to properly classify the condition as operable non-conforming represented a potential missed opportunity as PSEG management may have elected to correct the condition in May 2015 (RF19). PSEG initiated NOTF 20707031 for this issue.

The team noted that PSEG identified the underlying performance deficiency (less than adequate work order instructions and drawings) associated with the issue of concern discussed above. However, in accordance with NRC IMC 0612, NRC-identified findings include issues initially identified by the licensee to which the inspector has identified a previously unknown weakness in the licensees classification, evaluation, or corrective actions associated with the licensees correction of a finding or violation (i.e., NRC added value). As noted above, the NRC-identified PSEG shortcomings included:

operability determination screenings and evaluations, procedure use and adherence, and adequacy of engineering rigor and questioning attitude in technical evaluations.

Analysis.

The team determined that the failure to provide adequate work order instructions for the installation of safety-related SW isolation valve 2198C was a performance deficiency. Specifically, PSEG did not provide adequate instructions and drawings for the reinstallation of valve 2198C, which was previously removed for maintenance, nor did PSEG adequately analyze the resulting condition. The team determined that this performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems (SW) that respond to initiating events to prevent undesirable consequences. Additionally, the team determined that it was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, and Appendix E, Example 3j, because PSEGs associated operability and technical evaluations did not adequately consider the worst case conditions, resulting in a potential underestimation of the maximum required opening torque and in a condition where there was a reasonable doubt on the operability of the C SW train.

The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a deficiency that affected the design and qualification of safety-related SW valve 2198C but did not result in the loss of operability or functionality. The team determined that this finding had a cross-cutting aspect in Human Performance, Documentation, in that PSEG failed to ensure that design documentation and work packages were complete, thorough, accurate, and current.

(H.7)

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. Contrary to the above, on October 22, 2013, PSEG did not provide proper procedures for the installation of SW pump discharge isolation valve EAHV-2198C in work order 60112463-410, Step 1.D, after it was removed from service during RF18 for maintenance activities. Because this violation is of very low safety significance and has been entered into PSEGs corrective action program (NOTF 20704783), this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000354/2015007-02, Inadequate Work Order Instructions and Drawings Resulting in Improper Installation of a Safety-Related SW Valve)

.2.1.3 High Pressure Coolant Injection Steam Supply Isolation Valve (FD-HV-F001) and Steam

Supply Piping

a. Inspection Scope

The team inspected the high pressure coolant injection (HPCI) turbine steam supply outboard containment isolation (FD-HV-F001) to verify that it was capable of performing its design function in response to transients and accidents. The normally closed FD-HV-F001 valve is required to open for the HPCI system to perform its ECCS function and is required to close to isolate the main steam line and reactor vessel to prevent depressurization in case of a HPCI steam line break. The team reviewed applicable portions of Hope Creeks TSs, the UFSAR, and the HPCI system DBD to identify design basis requirements for FD-HV-F001.

The team reviewed design calculations, including environmental qualifications, valve specifications, and the operating history to verify that the valve was acceptable for HPCI service, and to verify that it met the applicable American Society of Mechanical Engineers (ASME) Code in-service testing requirements. The team reviewed a sample of ST results to verify that valve performance met the acceptance criteria and that the criteria were consistent with the design basis. The team interviewed the system engineer and reviewed MOV diagnostic test results and trending to assess valve performance capability and design margin. The team reviewed a sample of HPCI system corrective action NOTFs, technical evaluations, the HPCI system health report, and applicable test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions. The team also performed several walkdowns of the valve, adjacent area, accessible portions of the HPCI system steam piping, and associated control room instrumentation to assess the material condition, operating environment, and configuration control.

b. Findings

No findings were identified.

.2.1.4 C and D Service Water Strainers and Motors (1C-F-509 & 1D-F-509)

a. Inspection Scope

The team inspected the C and D SW strainers to evaluate whether they were capable of meeting their design basis and operational requirements to pass the required SW flow rate while maintaining the SW system reasonably clean, to prevent debris from plugging the safety-related SACS HXs, and to prevent a high pressure drop across the strainers under all accident conditions. The team evaluated the strainers pressure drop and the adequacy of their continuous backwash function to ensure continuous operation without impeding the proper operation of the SW System. The team reviewed monthly testing, flow rates and pressure drops as well as acceptance criteria affecting the strainers function to verify that they were capable of performing their safety function and to determine if PSEG had adequately evaluated the potential for strainer degradation. The team interviewed the system and design engineers to assess the material condition of the strainers and scheduled maintenance activities. The team conducted several detailed walkdowns to visually inspect the physical/material condition of the strainers, their motors, and their support systems to validate their design details such as the seismic support of the cantilevered motor located at the top of each strainer, and to ensure adequate configuration control. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse operating trends and to assess PSEGs ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.5 Safety Auxiliaries Cooling System Air-Operated Valves EG-AOV-2457B and

EG-AOV-2520B

a. Inspection Scope

The team inspected SACS air operated valves (AOVs) EG-AOV-2457B and EG-AOV-2520B to verify that they were capable of performing their design function. The SACS system has a safety-related function to provide cooling water to the engineered safety features (ESFs) equipment, including the RHR pumps and HXs, during normal operation, normal plant shutdown, LOP, and a LOCA. The 2457B valve is the SACS HX temperature control bypass isolation valve. This valve is normally open and has an active safety function to close to prevent flow diversion around the SACS HXs, which could prevent the SACS system from performing its design heat removal safety function.

This valve has no safety function in the open position. The 2520B valve is the B RHR pump cooler SACS supply valve. This valve has an active safety function in the open position to provide SACS cooling water flow to the B RHR pump seal and motor bearing coolers. This valve has no safety function in the closed position. The valve fails open on loss of power or air and automatically opens on a B RHR pump start.

The team reviewed the UFSAR, calculations, associated TSs, and procedures to identify the design basis requirements of the valves. The team also reviewed accident system alignments to determine if component operation would be consistent with the design and licensing bases assumptions. The team also reviewed valve testing procedures and valve specifications to ensure consistency with design basis requirements. The team reviewed periodic verification diagnostic test results and stroke test documentation to verify acceptance criteria were met and consistent with the design basis. The team interviewed the AOV program engineer to gain an understanding of maintenance issues and overall reliability of the valves. The team conducted a walkdown to assess the material condition of the valves, associated piping and supports, and to verify that the installed valve configuration was consistent with design basis assumptions and plant drawings. The team also reviewed the maintenance and operating history of the valves, the SACS system health report, and applicable system test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions. Finally, the team reviewed specific corrective action documents to verify that PSEG appropriately identified and resolved deficiencies, and properly maintained the valves.

b. Findings

No findings were identified.

.2.1.6 C 125 Volt Direct Current Battery

a. Inspection Scope

The team reviewed the design, testing, and operation of the C 125 volt direct current (Vdc) station battery (1CD411) to verify that it was capable of performing its design function of providing a reliable source of direct current (DC) power to connected loads under operating, transient, and accident conditions. The team reviewed design calculations to assess the adequacy of the batterys sizing to ensure that it could power the required equipment for a sufficient duration, and at a voltage above the minimum required for equipment operation. The team reviewed short circuit and breaker coordination calculations to ensure that breakers were adequately sized and were capable of interrupting short circuit faults. The team verified that proper breaker coordination existed to provide adequate isolation of the affected portion of the circuit.

The team reviewed battery test results to ensure that the testing was in accordance with design calculations, the HCGS TSs, and industry standards, and that the results confirmed acceptable performance of the battery. The team interviewed design engineers regarding design margin, operation, and testing of the DC system. The team performed a walkdown of the battery, DC buses, battery chargers, and associated distribution panels to assess the material condition, configuration control, and the operating environment. Finally, the team reviewed a sample of corrective action NOTFs to ensure that PSEG identified and properly corrected issues associated with the C 125 Vdc (1CD411) station battery.

b. Findings

No findings were identified.

.2.1.7 Suppression Pool Water Level, Temperature, and Water Quality Control

a. Inspection Scope

The team inspected the suppression pool to verify that it was capable of performing its design function. The team reviewed the design basis documents pertaining to the suppression pool (torus) and the applicable sections of the UFSAR to determine the design requirements. The team also reviewed torus internal coating inspection results from inspections performed during the last two refueling outages to assess the material condition and structural integrity of the torus. The team reviewed recent pressure suppression chamber to drywell vacuum breaker and pressure suppression chamber to reactor building vacuum breaker test results to verify that the vacuum breakers remained operable and capable of performing their design function supporting suppression pool integrity. The team also reviewed associated corrective action NOTFs, and applicable instrumentation and control test results for the suppression pool temperature, pressure, and level instruments to determine if there were any adverse trends and to ensure that PSEG adequately identified and addressed any adverse conditions. The team conducted an extensive walkdown of the accessible portions of the exterior of the torus structure to assess the material condition (including evidence of leakage), structural supports, potential hazards, and configuration control.

b. Findings

No findings were identified.

.2.1.8 C Emergency Diesel Generator Load Sequencer

a. Inspection Scope

The team reviewed TSs, the UFSAR, and system DBDs to identify design basis requirements for the emergency load sequencer (ELS). The team reviewed drawings and vendor documents to verify that the installed configuration supported the design basis function under accident conditions. The team interviewed the system engineer, reviewed the system health report, and performed several walkdowns of the ELS cabinet to assess the observable material condition and operating environment. The team also verified that the location and installation of the cabinet mounting fasteners were in accordance with the installation drawings to ensure seismic adequacy. The team reviewed test procedures and recent test results against DBDs to verify that acceptance criteria for the tested sequenced time parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. The team reviewed vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action system documents in order to verify that potential degradation was monitored or prevented, and that scheduled component inspections or replacements were consistent with vendor recommendations.

b. Findings

No findings were identified.

.2.1.9 Emergency Diesel Generator Fuel Oil Transfer Pumps

a. Inspection Scope

The team reviewed applicable portions of TSs, the UFSAR, and system DBDs to identify design basis requirements for the EDG fuel oil transfer pumps (FOTPs). The team inspected the FOTPs to evaluate whether they were capable of meeting their design basis and operational requirements to maintain each EDG fuel oil day tank (FODT) with sufficient fuel oil and with a flow rate greater than the peak fuel oil consumption rate of the EDGs under all accident conditions, including LOP. The team evaluated the pumps net positive suction head (NPSH) and suction under the minimum level at the storage tank to ensure that pump operation would not be disrupted. The team reviewed the sizing of the FODTs and the levels associated with the FOTPs start and stop to verify that the TS-required fuel oil quantity was not compromised. The team reviewed flow rate testing and in-service test (IST) results to verify that the pump performance bounded the analyzed performance of each of the eight FOTPs, and to determine if PSEG had adequately evaluated the potential for pump degradation. The team interviewed the system and design engineers to assess the material condition of the FOTPs and scheduled maintenance activities. The team also conducted several detailed walkdowns to visually inspect the physical/material condition of the FOTPs and their support systems, to validate the data associated with the instruments supporting FOTP operation, and to ensure adequate configuration control. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse operating trends and to assess PSEGs ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 0 A Safety Auxiliaries Cooling System Expansion Tank and A Safety Auxiliary

Cooling System Piping Integrity

a. Inspection Scope

The team reviewed the design, testing, inspection, and operation of the A SACS expansion tank (1-EG-1AT-205), its associated tank level instruments, and associated piping to evaluate whether it could perform its design basis function. The team reviewed design calculations, drawings, and vendor specifications (including tank sizing and level uncertainty analysis) to evaluate the adequacy and appropriateness of design assumptions and operating limits. The team interviewed engineers, and reviewed test records, alarm response procedures, and operating procedures to evaluate whether maintenance and testing were adequate to ensure reliable operation, and to evaluate whether those activities were performed in accordance with regulatory requirements, industry standards, and vendor recommendations. The team also conducted walkdowns of the tank and associated piping and supports to assess the material condition. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse trends associated with the A SACS expansion tank and to assess PSEG's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 1 A 250 Volt, Direct Current Motor Control Center (10D251)

a. Inspection Scope

The team reviewed the design, testing, and operation of the A 250 Vdc motor control center (MCC) to verify its ability to meet design basis requirements during plant transients and accidents. The MCC provides 250 Vdc power to HPCI system main and auxiliary components, including the HPCI steam supply isolation valve (FD-HV-F001).

The team interviewed design engineers regarding design margin, operation, and testing of the DC system. The team performed several walkdowns of the MCC to assess the material condition, configuration control, and the operating environment. The team reviewed HPCI MCC internal inspection preventive maintenance (PM), battery sizing calculations, and voltage drop calculations. Finally, the team reviewed a sample of corrective action NOTFs to ensure that PSEG identified and properly corrected issues associated with the HPCI MCC.

b. Findings

No findings were identified.

.2.1.1 2 Drywell Spray Valve (BC-HV-F021B)

a. Inspection Scope

The team inspected the B drywell spray valve (BC-HV-F021B) to verify that it was capable of performing its design function in response to transients and accidents. The normally closed drywell spray valve has a safety function in the open position to allow the RHR system to perform its containment cooling function of reducing and maintaining primary containment pressure and temperature to within acceptable limits following a LOCA. The drywell spray valve also has a safety function to close to provide a primary containment isolation. The team reviewed applicable portions of Hope Creeks TSs, the UFSAR, and the RHR system DBD to identify design basis requirements for BC-HV-F021B. The team reviewed design calculations, including environmental qualifications, valve specifications, and the operating history to verify that the valve was acceptable for RHR service, and to verify that it met the applicable ASME Code in-service testing requirements. The team reviewed a sample of ST results to verify that valve performance met the acceptance criteria and that the criteria were consistent with the design basis. The team interviewed the system engineer, and reviewed MOV diagnostic test results and trending to assess valve performance capability and design margin. The team reviewed a sample of related RHR system corrective action NOTFs, technical evaluations, the RHR system health report, corrective and preventive maintenance records, and applicable test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions. The team also performed a walkdown of both drywell spray valves (F021A and F021B), accessible portions of the RHR system piping, and associated control room instrumentation to assess the material condition, operating environment, and configuration control.

b. Findings

No findings were identified.

.2.1.1 3 C Residual Heat Removal Pump Breaker, C Service Water Pump Breaker, and

C Emergency Diesel Generator Output Circuit Breaker

a. Inspection Scope

The team reviewed TSs, the UFSAR, and system DBDs to identify design basis requirements for the C RHR and C SW pump motors and the C EDG output circuit breakers. The team reviewed voltage drop calculations for the breaker closing circuits to assure that adequate voltage was available during limiting design basis conditions. The team also reviewed the current system health report, selected drawings and calculations, maintenance and test procedures, and corrective action NOTFs associated with the C RHR and C SW pump motors and the C EDG output circuit breakers.

Specifically, the team reviewed the pump maximum brake horsepower requirements to confirm the adequacy of the motor capability to supply power during worst case design conditions. The team reviewed the adequacy of motor starting and running during degraded offsite voltage conditions coincident with a postulated design basis accident.

The team verified motor overcurrent relay settings and periodic relay calibration test results for adequacy to ensure reliable motor operation during the most limiting design basis operating conditions. The team interviewed the system engineers and performed several walkdowns of the motors and the associated 4KV switchgear, including the control room panels, to assess the observable material condition, configuration control, and operating environment.

b. Findings

No findings were identified.

.2.1.1 4 Emergency Instrument Air Compressor (10K100) and Instrument Air Header Piping

a. Inspection Scope

The team reviewed the design, testing, inspection, and operation of the emergency instrument air compressor (EIAC) and instrument air header piping to evaluate whether they could perform their design basis function. The non-safety related service air (SA)system supplies normal air to the instrument air (IA) system. The IA system is also non-safety related; however, it is important to safety and has a high risk function to provide clean, dry, oil-free air at the normal temperature and pressure for the air-operated instruments and devices throughout the plant. The EIAC provides the motive force required to maintain IA system pressure should both SA compressors be non-operational.

The team reviewed design calculations, drawings, system modifications, and vendor specifications to evaluate the adequacy and appropriateness of design assumptions and operating limits. The team interviewed engineers, and reviewed test records, alarm response procedures, and operating procedures to evaluate whether maintenance and testing were adequate to ensure reliable operation, and to evaluate whether those activities were performed in accordance with regulatory requirements, industry standards, and vendor recommendations. The team also conducted several walkdowns of the SA compressors, IA dryers, EIAC, local alarm panels, associated control room instrumentation, and accessible IA piping and supports to assess the material condition, configuration control, and operating environment. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse trends associated with the EIAC or IA system and to assess PSEG's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 5 C 125Vdc Bus 10D430 and Distribution Panel 1CD417

a. Inspection Scope

The team inspected the C 125 Vdc bus (10D430) and DC distribution panel (1CD417)to verify that they were capable of meeting their design basis requirements to distribute preferred power to safety-related essential loads. The team reviewed the one-line diagrams, control schematics, and the design basis as defined in the UFSAR to verify the adequacy of the 125V bus to supply adequate voltage and current to the loads. The team reviewed the associated voltage drop, load flow, and short circuit calculations to verify that adequate voltage was available to components supplied by the bus under worst case loading and degraded voltage conditions. The team reviewed the bus supply and feeder breaker ratings and trip settings to verify that protection coordination was provided for the loads and for the feeder conductors. The team reviewed vendor specifications, nameplate data, and calculations related to the 125V bus supply. The team interviewed system and design engineers to answer questions that arose during document reviews to determine the adequacy of maintenance and configuration control.

The team performed several walkdowns of the 10D430 bus and associated DC distribution panel to assess the material condition, configuration control, and the operating environment. Finally, the team reviewed corrective action NOTFs and system health reports to verify that PSEG appropriately identified and resolved deficiencies.

b. Findings

No findings were identified.

.2.1.1 6 A Standby Liquid Control Pump and Standby Liquid Control Tank

a. Inspection Scope

The team reviewed applicable portions of TSs, the UFSAR, and the system DBD to identify design basis requirements for the standby liquid control (SLC) system. The team inspected the A SLC pump and SLC tank to evaluate whether the pump, taking suction from the tank, was capable of meeting its design basis and operational requirements to provide the required borated water to the reactor vessel under the most limiting accident conditions. The team evaluated the ability of the SLC pump to deliver the design and licensing bases flow rates while the redundant B pump was operating and assessed possible interactions between the two pumps. The team reviewed surveillance testing using the SLC test tank, as well as IST acceptance criteria associated with the SLC pump. The team also validated the tank capacity and reviewed its operational capabilities with respect to Anticipated Transients Without Scram (ATWS)and the reactor pressure vessel (RPV) control portion of the emergency operating procedures (EOPs). The team also verified that the pump performance bounded the flow requirements in the safety analysis and verified that PSEG had adequately evaluated the potential for pump degradation. The team interviewed system and design engineers as well as the IST Program Manager to gather information regarding the condition of the pump, adequacy of pump maintenance, and outstanding issues affecting the pump. The team conducted several detailed walkdowns of the pump, SLC tank, associated support components and instruments, and control room indications to visually inspect the physical/material condition and to ensure adequate configuration control.

Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse operating trends and to assess PSEGs ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.2 Review of Industry Operating Experience and Generic Issues (5 samples)

The team reviewed selected OE issues for applicability at Hope Creek. The team performed a detailed review of the OE issues listed below to verify that PSEG had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.2.1 NRC Information Notice 2013-14: Potential Design Deficiency in Motor-Operated Valve

Control Circuitry

a. Inspection Scope

The team assessed PSEGs applicability review and disposition of NRC Information Notice (IN) 2013-14. This information notice discussed recent industry OE regarding a potential control circuit design deficiency in MOVs that could result in incorrect valve position indication with the valve in an improper position during a LOCA. The team reviewed PSEGs evaluation (70158062) performed in response to this OE. In addition, the team reviewed design drawings and circuit diagrams to assess PSEGs review of the issue.

b. Findings

No findings were identified.

.2.2.2 NRC Information Notice 2011-12: Reactor Trips Resulting from Water Intrusion into

Electrical Equipment

a. Inspection Scope

The team assessed PSEGs applicability review and disposition of NRC IN 2011-12.

The NRC issued the IN to inform licensees about OE regarding recent events involving water intrusion into electrical equipment that resulted in reactor trips. In addition, the IN described the root causes and corrective actions taken to prevent recurrence. The team assessed PSEGs evaluation of the IN as it applied to HCGS, including their review of the electrical equipment design to ensure that it remained reliable and that there were no vulnerabilities associated with possible water intrusion events. The inspection included a review of corrective action documents, interviews with electrical and design engineering and operations personnel, and a complete walkdown of all accessible safety-related and non-safety related electrical panels, MCCs, electrical cable spreading rooms, and switchgear rooms.

b. Findings

No findings were identified.

.2.2.3 NRC Information Notice 2012-03: Design Vulnerability in Electric Power System

a. Inspection Scope

The team assessed PSEGs applicability review and disposition of NRC IN 2012-03.

The NRC issued the IN to inform licensees about OE involving the loss of one of the three phases of the offsite power circuit. The team assessed PSEGs evaluation of the IN as it applied to Hope Creek to confirm that PSEG performed an adequate review and assessment of the issue, and to verify that adequate indications and procedures were available to the operators to take appropriate actions when necessary. The inspection also included a review of associated corrective action documents.

b. Findings

No findings were identified.

.2.2.4 NRC Information Notice 2013-17: Significant Plant Transient Induced by Safety-Related

Direct Current Bus Maintenance at Plant

a. Inspection Scope

The team assessed PSEGs applicability review and disposition of NRC IN 2013-17 for Hope Creek. The NRC issued the IN to inform licensees of recent OE involving the loss of one train of a DC distribution system at power in a nuclear power plant. The team reviewed PSEGs evaluation of the systems, components, processes, and procedures described in the assigned OE document to determine if similar deficiencies could represent potential operability issues. PSEG determined that Hope Creek was not vulnerable to the failure as their design differed in that the HCGS DC system has a fuse with a 4 second time delay (rated at 500 percent) to allow the fuse to pass normal current and surges instead of a breaker. The team reviewed the adequacy of PSEGs determination that there were no similar deficiencies that could represent potential operability issues and that the OE was not applicable at Hope Creek.

b. Findings

No findings were identified.

.2.2.5 NRC Information Notice 2010-03: Failures of Motor-Operated Valves due to Degraded

Stem Lubricant

a. Inspection Scope

The team assessed PSEGs applicability review and disposition of NRC IN 2010-03.

This IN discussed industry OE regarding recent failures and corrective actions for MOVs due to degraded lubricant on the valve stem and actuator stem nut threaded area. The team verified that PSEG entered the OE into their corrective action program (CAP) for review (NOTF 20453813). The team reviewed PSEGs evaluation (70108019)performed in response to this OE as well as PSEGs follow-up actions. The team also reviewed changes to maintenance procedures and lubrication databases made in response to this OE. In addition, the team assessed the adequacy of the PSEGs corrective actions during walkdowns of various MOVs.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems (IP 71152)

a. Inspection Scope

The team reviewed a sample of problems that PSEG had previously identified and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions. In addition, the team reviewed NOTFs written on issues identified during the inspection to verify adequate problem identification and incorporation of the problem into the CAP. The specific corrective action documents that the team sampled and reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA6 Meetings, including Exit

On October 23, 2015, the team presented the inspection results to Mr. Eric Carr, Plant Manager, and other members of the PSEG staff. The team verified that no proprietary information was retained by the inspectors or documented in the report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

PSEG Personnel

E. Carr, Plant Manager

M. Conroy, AOV Program Engineer

A. Contino, 4KV System Manager

S. DelMonte, Branch Manager

K. Denny, SW System Manager

P. Duca, Senior Engineer, Regulatory Assurance

D. Dunn, RHR System Manager

A. Ghose, Design Engineer Civil Structural

J. Lane, Design Engineer

T. MacEwen, Hope Creek Compliance Engineer

S. Madden, Design Manager

S. Nevelos, Regulatory Assurance Manager

C. Payne, HPCI & RCIC System Manager

M. Peterson, IA System Manager

C. Reed, Remote Shutdown System Manager

N. Rock, SACS System Manager

C. Torres, NSSS Manager

A. Tramontana, Hope Creek Programs Engineering Manager

Z. VanNess, Design Engineer

E. Wagner, Capital Projects

NRC personnel

C. Cahill, Senior Reactor Analyst

S. Haney, Resident Inspector

J. Hawkins, Senior Resident Inspector

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open and

Closed

NCV

05000354/2015007-01 NCV Failure to establish appropriate acceptance criteria for RHR and core spray pump start times during simulated LOCA/LOP testing.

(Section 1R21.2.1.1)

NCV

05000354/2015007-02 NCV Inadequate work order instructions and drawings resulting in improper installation of a safety-related SW valve. (Section 1R21.2.1.2)