IR 05000443/2016007

Component Design Bases Inspection Report 05000443/2016007

ML16350A034
Person / Time
Site:	Seabrook
Issue date:	12/14/2016
From:	Mel Gray Engineering Region 1 Branch 1
To:	Mccartney E NextEra Energy Seabrook
References
EA 16-238 IR 2016007
Download: ML16350A034 (43)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ber 14, 2016

SUBJECT:

SEABROOK STATION, UNIT 1 - COMPONENT DESIGN BASES INSPECTION REPORT 05000443/2016007

Dear Mr. McCartney:

On September 1, 2016 the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Seabrook Station, Unit 1. On September 1 and October 5, 2016, the NRC discussed the interim results of this inspection with you and other members of your staff; and on November 10, 2016, the NRC discussed the final results of the inspection with you and other members of your staff. The results of this inspection are documented in the enclosed report.

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, and both were of very low safety significance (Green). The findings were determined to be violations of NRC requirements.

However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCV)

consistent with Section 2.3.2.a of the NRCs Enforcement Policy. If you contest any of the NCVs 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 DC, 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Senior Resident Inspector at Seabrook Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; and the NRC Senior Resident Inspector at Seabrook Station. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Mel Gray, Chief Engineering Branch 1 Division of Reactor Safety Docket No. 50-443 License No. NPF-86

Enclosure:

Inspection Report 05000443/2016007 w/Attachment: Supplemental Information

REGION I==

Docket No: 50-443 License No: NPF-86 Report No: 05000443/2016007 Licensee: NextEra Energy Seabrook, LLC (NextEra)

Facility: Seabrook Station, Unit 1 Location: Seabrook, New Hampshire 03874 Inspection Period: August 1 through September 1, 2016 Inspectors: S. Pindale, Senior Reactor Inspector, Division of Reactor Safety (DRS) - Team Leader J. Richmond, Senior Reactor Inspector, DRS J. Schoppy, Senior Reactor Inspector, DRS M. Orr, Reactor Inspector, DRS S. Gardner, NRC Electrical Contractor W. Sherbin, NRC Mechanical Contractor Approved By: Mel Gray, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY

IR 05000443/2016007; 8/1/2016 - 9/1/2016; Seabrook Station, Unit 1; Component Design

Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of four U.S. Nuclear Regulatory Commission (NRC) inspectors and two NRC contractors. Two findings of very low safety significance (Green) were identified. 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 6, dated July 2016.

Cornerstone: Initiating Events

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, Part 50, Appendix B, Criterion XVI,

Corrective Action, for not performing corrective actions to preclude repetition of a significant condition adverse to quality. Specifically, in 2008, two of four primary component cooling water (PCCW) pump motors failed within a four month period due to a manufacturing defect. NextEra established but did not perform a corrective action to replace all four motors with re-wound motors, free of the identified manufacturing defect.

Subsequently, in 2015, a third motor failure occurred due to the same manufacturing defect.

NextEras immediate corrective actions included entering this issue into their corrective action program (AR 2153536), implementing an electrical testing program that would provide an early indication of further degradation of the manufacturing defect until motor replacement, and completing a prompt operability determination to assess current PCCW system operability.

This finding was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the team screened the finding for safety significance and determined that a detailed risk evaluation (DRE) was required because the finding involved a partial loss of a support system (PCCW pump B) that would increase the likelihood of an initiating event and impacted mitigating equipment (Item C - Support System Initiators of Exhibit 1). The DRE, performed by a Region I senior reactor analyst (SRA), concluded that the performance deficiency resulted in a change in core damage frequency of high E-7/yr, or very low safety significance (Green).

The finding had a cross-cutting aspect in Problem Identification and Resolution (Resolution),

because NextEra did not take effective corrective actions to address this issue in a timely manner commensurate with its safety significance. Specifically, NextEra did not perform motor replacements for susceptible installed PCCW motors within a reasonable due date as specified by the 2009 corrective action to preclude repetition (CAPR); and plant procedures, programs and resources were available for the decision-making process to schedule the motor replacement. (Section 1R21.2.1.3.1)

Cornerstone: Barrier Integrity

Green.

The team identified a finding of very low safety significance, involving a non-cited violation of Seabrook Technical Specification Surveillance Requirement 4.0.5, Surveillance Requirements for In-Service Inspection and Testing of American Society of Mechanical Engineers (ASME) Code Class 1, 2, and 3 Components. Specifically, the manual isolation valves for the atmospheric steam dump valves had an active safety function to close, in order to mitigate the radiological consequences of a steam generator tube rupture (SGTR)accident, but had not been placed in the Seabrook In-Service Test Program and tested, as required by the Technical Specifications and ASME Code. As a result, degraded valve performance could go uncorrected without adequate acceptance criteria to ensure that a SGTR would not result in an unacceptable increase in the consequences of that accident (e.g., a more than minor reduction in the margin between the postulated licensing basis radiological release and the regulatory limits). In response, NextEra entered the issue into their corrective action program (AR 2153195) and performed a preliminary assessment of the valves, which concluded that they were fully operable.

This finding was more than minor because it was associated with the System, Structure, or Component (SSC), and Barrier Performance attribute of the Containment Barrier Cornerstone and adversely affected the cornerstone objective of ensuring the reliability of associated risk-important SSCs. The team determined that the finding was of very low safety significance (Green) because it was a deficiency confirmed not to represent an actual open pathway in the physical integrity of reactor containment and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The finding did not have a cross-cutting aspect because it was not considered indicative of current licensee performance. (Section 1R21.2.1.17)

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 Seabrook Station, Unit 1 (Seabrook) Probabilistic Risk Assessment (PRA) and the NRC Standardized Plant Analysis Risk (SPAR) model for Seabrook. Additionally, the team referenced the Risk-Informed Inspection Notebook for Seabrook 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, transformers, operator actions, electrical busses, 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 (05000443/2007006, 05000443/2010006, and 05000443/2013008) and reviewed those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 17 components and 3 operating experience (OE) items. Several of the components, such as a containment building spray pump, the service water intake, and the steam generator (SG) atmospheric steam dump valve were selected based on 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 inspection performed by the team was conducted 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, licensing basis, and risk-informed beyond design 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.

.2.1.1 480 Volt Bus E61 (EDE-US-61)

a. Inspection Scope

The team inspected the 480 Volts, alternating current (Vac) vital unit substation (EDE-US-61) to determine if it was capable of performing its design basis functions. The team reviewed design and licensing documents, including the updated final safety analysis report (UFSAR), the technical specifications (TS) and technical requirements manual (TRM), the system design basis document (DBD), drawings, and other design documents to determine the specific design functions. Specifically, the team evaluated whether the bus and associated supply transformer were capable of transferring supplied power to downstream loads following a postulated accident. The team also reviewed electrical distribution calculations, including load flow, voltage drop, short-circuit, and electrical protection coordination to evaluate the adequacy and appropriateness of design assumptions; and determined if substation capacity and voltages remained within acceptable values under design basis conditions. Electrical overcurrent protective relay settings for the substation supply breaker and selected load center breakers were reviewed to determine if the trip setpoints would ensure the ability of the supplied equipment to perform its design basis safety functions and provide adequate load center protection during fault conditions. Additionally, the team reviewed maintenance and test results, interviewed system and design engineers, and conducted field walkdowns to assess the material condition of the load center. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.2 Motor Control Center E512

a. Inspection Scope

The team inspected the 480 Vac motor control center (MCC) E512 to assess whether it was capable of performing its design basis functions. The team reviewed design and licensing documents, including TSs, DBD, and selected drawings and calculations to determine specific design functions. The team reviewed electrical distribution calculations including load flow, voltage drop, short-circuit, overcurrent protection, and circuit breaker trip coordination to evaluate the adequacy and appropriateness of design assumptions. The team compared the MCC's capacity rating to assumed design loading conditions to evaluate whether the worst case loading exceeded the MCC's capacity.

The team also evaluated whether load voltages would remain above minimum acceptable values under worst case conditions. The team compared the overcurrent trip settings for selected load breakers to the MCC supply breaker to verify whether there was adequate coordination to ensure that a load fault would not result in a loss of the MCC. The team reviewed operating procedures to assess whether design limitations could be exceeded during MCC cross-tie operation and to verify whether adequate separation would be maintained between electrical divisions, consistent with design and TS requirements. The team reviewed maintenance and test results, interviewed system and design engineers, and conducted field walkdowns to verify whether the MCC alignment and breaker positions were consistent with design drawings, and to independently assess material conditions. Finally, the team reviewed a sample of corrective action documents and system health reports to determine if there were any adverse trends and to assess NextEra's capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.3 C Primary Component Cooling Water Pump Motor (CC-P-11-C)

a. Inspection Scope

The team reviewed the C PCCW pump motor to verify that it was capable of performing its design basis function. The team reviewed design and licensing documents, including the UFSAR, the TSs and TRM, the DBD, drawings, and other design documents to determine the specific design functions. The team reviewed available short circuit current versus breaker interrupting capability as well as NextEras evaluation of the breaker protective relay settings and breaker coordination study to verify adequate protection of the pump motor without interruption of service to other components during circuit overload or faulted conditions.

The team also reviewed the load analysis and voltage drop calculation to confirm that adequate voltage was available at the PCCW pump motor terminals under degraded grid voltage conditions. Specifically, the team confirmed that the motor terminals supplied by the safety-related 4160 Vac bus E5 were operated within the motor design range of 3600 - 4400 Vac. Control logic and wiring diagrams and calculations that determined the available control voltage were reviewed to verify that the control of the PCCW motor supply breaker conformed to the design requirements. The team also reviewed test procedures and associated results to evaluate the current health of the pump motor and circuit. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were any adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

1. Inadequate Corrective Action for Primary Closed Cooling Water Pump Motor Failure

Introduction:

The team identified a finding of very low safety significance (Green)involving a Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for not performing corrective actions to preclude repetition of a significant condition adverse to quality. Specifically, in 2008, two of four PCCW pump motors failed within a four month period due to a manufacturing defect. NextEra established but did not perform a corrective action to replace all four motors with re-wound motors, free of the identified manufacturing defect. Subsequently, in 2015, a third motor failure occurred due to the same manufacturing defect.

Description:

The PCCW system consists of two trains, with two 100 percent PCCW pumps in each train. The A and C pumps are in one train, while the B and D pumps are in the other train. The PCCW is the safety-related cooling system for reactor decay heat removal and safety-related engineered safety features. The relevant chronology of PCCW motor failures and replacements is as follows:

• A Motor March 2009, replaced with Unit 2 spare (interim corrective action)

• B Motor March 2009, replaced with Unit 2 spare (interim corrective action)

June 2015, in-service failure; replaced with re-wound motor

• C Motor November 2008, in-service failure; replaced with Unit 2 spare October 2012, replaced with re-wound motor (action to preclude recurrence)

• D Motor July 2008, in-service failure; replaced with Unit 2 spare In 2008, when the C and D motors failed, NextEra initiated a root cause evaluation (RCE) in accordance with their Corrective Action Program, and documented the two motor failures as being significant in the associated RCE report. After the C and D motors failed, NextEra replaced them with Unit 2 spare motors. The failed motors were sent to a motor vendor for failure analysis and repair (re-wind). Based on the failure analysis, NextEra's RCE concluded that the failures were attributed to poor workmanship by the original motor manufacturer (i.e., a manufacturing defect). Specifically, the failure analysis determined that the coil insulation wrapping had air pockets (i.e., voids)between the wrapping and the coil wires (i.e., the insulation wrapping was not sufficiently tight). The voids, in turn, prevented adequate epoxy penetration, which resulted in poor thermal conductivity between the coil and the motor casing, and caused localized hot spots which accelerated insulation breakdown. Subsequently, the insulation breakdown resulted in turn-to-turn short circuits, which eventually resulted in a coil to ground short circuit (i.e., a ground-wall insulation failure) in both the C and D motors. The RCE determined that the C and D motors only had approximately 10 years of run-time each, but had a qualified life of 32 years.

NextEra's 2008 RCE concluded that the Unit 2 motors could have the same manufacturing defect as the failed Unit 1 motors because they were manufactured in about the same time period as the failed Unit 1 motors. As an interim corrective action, until re-wound motors could be obtained and installed, the RCE determined that the A and B motors (the remaining Unit 1 motors still installed in the plant) should be replaced with Unit 2 spares by mid-2009. The RCE concluded that this was appropriate because the failed Unit 1 motors (C and D) had about 10 years of run-time before they failed, while the Unit 2 spares had zero run-time. This action was completed in March 2009 when the A and B motors were replaced with Unit 2 spares. In addition, the RCE required enhanced monitoring of the installed motors to detect any adverse trend in insulation degradation. The RCE identified a specific corrective action to preclude recurrence (CAPR), which was to replace all the motors with re-wound motors by December 2012, to ensure that the installed motors would not be susceptible to the identified manufacturing defect.

NextEra subsequently changed the motor replacement activity from an on-line activity to an outage activity, as a risk management action to reduce on-line maintenance risk.

During an outage in October 2012, NextEra replaced the C motor (which was a Unit 2 spare, installed in 2008) with a re-wound motor, and extended the CAPR due date to replace the remaining three motors with re-wound motors no later than December 15, 2015.

In June 2015, the B motor (a Unit 2 spare, installed in 2009) failed in-service, with similar symptoms to the two 2008 motor failures, and was replaced with a re-wound motor. NextEra's 2015 apparent cause evaluation (ACE) for this failure determined that this was the third occurrence of this type of failure since 2008. At that time, NextEra did not send the failed B motor (Unit 2 spare) out for failure analysis and instead, placed it in interim on-site storage. Although NextEra's ACE concluded that the B motor failure was due to untimely corrective action to replace the susceptible motors with re-wound motors, NextEra again extended the CAPR due date, to replace the remaining two motors with re-wound motors, to November 6, 2016. The team noted that the B motor only had about 3 years of run-time when it failed, and concluded that NextEra appeared to be relying on its enhanced monitoring of installed motors as the principle basis for continued operability.

NextEra's enhanced motor monitoring, scheduled at three year intervals, consisted of winding resistance tests, coil insulation to ground megger tests, polarization index tests, and surge comparison tests. Collectively, these tests were referred to as a Baker motor test (i.e., a set of different tests performed using a Baker Static Motor Analyzer Test Set).

The 2008 RCE referenced Electric Power Research Institute (EPRI) NP-7502, Electric Motor Predictive and Preventive Maintenance Guide, which recommended test periods of 12 to 18 months.

The team concluded that the Unit 2 motors were likely to be susceptible to the same manufacturing defect as the original Unit 1 C and D motors because the B motor was a Unit 2 spare installed in 2009 (short in-service period), had similar failure symptoms to the previous motor failures, was the same motor type, style and vendor as the failed Unit 1 motors, and was manufactured in about the same time period as the Unit 1 motors. The team further concluded that by postponing motor replacements by more than eight years after the first two failures, and more than four years beyond the initial December 2012 CAPR due date, NextEra had not adequately implemented corrective actions to prevent repetition for a significant condition adverse to quality, as required by regulation.

In response to the team's conclusion, NextEra postulated that the 2015 ACE may have reached an incorrect apparent cause regarding the Unit 2 motor failure because the Unit 2 motors had been manufactured in 1977, while the Unit 1 motors had been manufactured in 1978, a year later. Based on the difference in manufacturing dates, NextEra initially believed that the Unit 2 motors were not susceptible to the same manufacturing defect as the Unit 1 motors. To demonstrate continued operability of the A and D motors (Unit 2 spares, installed in 2009 and 2008, respectively), NextEra performed the following:

• Baker motor tests on the A and D motors, with satisfactory results;

• Sent the B motor to the original motor manufacturer for failure analysis; and

• Completed a Prompt Operability Determination (POD) for the A and D motors.

NextEra's POD stated that there was no evidence that any Unit 2 motor had a similar manufacturing defect to the failed Unit 1 motors, based on test and inspection results.

NextEra referenced EPRI EL-5036-V16, Handbook to Assess the Insulation of Large Rotating Machines, Section 6.5.2.1, Assessment of Turn Insulation, which stated:

• Turn insulation condition acceptable: If there are no failures from surge testing, no evidence of any of the aging mechanisms that could affect the turn insulation, and no significant operational or environmental changes that would affect aging, the turn insulation should perform reliably for at least the next few years.

In addition, NextEra contacted the Baker Test Set vendor, whom NextEra described as a recognized industry expert in the field of motor testing. That vendor provided the following additional information regarding surge test capability:

• Surge testing checks the turn-to-turn insulation (i.e., copper to copper) and can detect weakening copper insulation months before a failure that will manifest itself through weak insulation turning into a shorted turn, then burning through the ground-wall insulation in minutes at that point.

Based on the EPRI technical reports, the team determined that the surge test was the only test that had the capability to detect insulation degradation within a coil winding (i.e., a turn-to-turn short) prior to a turn-to-turn short inside the coil winding becoming a coil to motor case short (i.e., a ground-wall insulation failure). The team also determined that the identified manufacturing defect in the Unit 1 motors appeared to constitute an aging mechanism that could affect the turn insulation. Therefore, the team concluded that NextEra's enhanced monitoring at a three-year interval was not sufficient to detect an adverse trend in turn-to-turn insulation, prior to an in-service failure.

NextEra entered this issue in their corrective action program as AR 2153536. The POD for the A and D PCCW motors determined that the motors were degraded but operable, established compensatory measures to perform Baker motor testing quarterly until replaced, and assigned a motor replacement due date of December 28, 2016. The team reviewed NextEra's POD, compensatory measures, and planned corrective actions and concluded they were reasonable.

NextEra received the failure analysis report for the B motor (Unit 2 spare) from the original motor manufacturer, dated September 29, 2016. That vendor report confirmed that the Unit 2 motor failure was due to the same manufacturing defect as the previous two Unit 1 motor failures in 2008.

Analysis:

As stated previously, NextEra considered the two motor failures in 2008 to be significant. Similarly, the team considered the presence of a manufacturing defect potentially affecting all PCCW motors to be a significant condition adverse to quality. In accordance with 10 CFR 50, Appendix B, Criterion XVI, in the case of significant conditions adverse to quality, measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.

The team determined that not precluding repetition of a significant condition adverse to quality was a performance deficiency that was reasonably within NextEra's ability to foresee and prevent. Specifically, in 2008, two PCCW pump motors failed due to a manufacturing defect. NextEra established a CAPR to replace all of the PCCW motors by December 2012 with re-wound motors, free of the identified manufacturing defect, but repeatedly delayed motor replacements. Subsequently, in 2015, seven years later, a third motor failure occurred due to the same manufacturing defect.

This finding is more than minor because it was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of NRC IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the team screened the finding for safety significance and determined that a detailed risk evaluation (DRE) was required because the finding involved a partial loss of a support system (PCCW pump B) that would increase the likelihood of an initiating event and impacts mitigating equipment (Item C - Support System Initiators of Exhibit 1).

An NRC Region I SRA completed the DRE and estimated the increase in core damage frequency (CDF) associated with this performance deficiency to be in the high E-7 per year range or very low safety significance (Green). To complete the DRE, the SRA used the Systems Analysis Programs for Hands-On Evaluation (SAPHIRE) Revision 8.1.4, the Seabrook SPAR Model, Version 8.21 (limited use model, dated October 3, 2016), and guidance in Section 2.1 of Volume 1 of the Risk Assessment of Operational Events (RASP) Handbook for evaluating support system performance deficiencies. The SRA made the following assumptions and associated changes to the SPAR Model to estimate the internal risk contribution: 1) the exposure time for this issue was one year, inclusive of 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> of repair time; 2) for the one year period, PCCW pump motors A, B, and D were susceptible to the nonconforming condition relative to motor quality of construction and their associated mission time failure probabilities were increased using statistical analysis (i.e., a Bayesian update with a Jeffereys non-informative prior methodology)from a nominal value of 7.25E-5 to 2.6E-4; 3) the Seabrook SPAR model was modified to invoke support system initiating event estimates and associated A, B and D PCCW pump initiating event frequencies were increased from their nominal value of 2.6E-2/year to 9.6E-2/year; 4) for the 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> of PCCW pump B unavailability, basic event PCCW-MDP-FR-P11B was set to TRUE with the resulting PCCW pump common cause failure mission time probability increased from 2.67E-7 to 3.69E-3; 5) the 68-hour period also included the increased conditional failure probability for the other affected A and D motors to 2.6E-4 along with increased initiating event frequencies to 9.6E-2; and 6)truncation was set at 1E-11.

Based upon these modeling changes, the internal CDF risk contribution from the assumed one-year of exposure time, given the increased pump conditional failure probabilities, was 4E-7/year. An additional internal CDF risk increase of 3.3E-7/year was calculated associated with the unavailability of the B PCCW pump due to its failure and repair time of 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br />. The year-long dominant core damage sequences involved a loss of B Loop of PCCW with a loss of seal cooling (seal stage 2 failure), failure of high pressure injection (HPI) and failure of reactor coolant system (RCS) cooldown. The two dominant core damage sequences while the B PCCW pump was unavailable (68 hour7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> repair time) involved total loss of PCCW with loss of seal cooling (seal stage 2 failure),failure of HPI and failure of RCS cooldown, along with a loss of alternate current (AC)

Bus E5 with common cause failure of the A, B and D PCCW pumps and RCP seal stage 2 failure.

The SRA noted that NextEras internal risk estimate and dominant sequences were consistent with the SPAR model results. SRA review of external event contributions determined that other than fire, the high winds, flooding, and seismic events were not significant contributors to risk for this issue. The dominant fire contributions involved switchgear A fires with a loss of Bus E5 and the unavailability of the B Loop of PCCW.

The estimated increase in external risk contribution due to these fire scenarios was in the low E-7/year range. As a result, the total of internal and external risk contributions was in the high E-7/year range or very low safety significance (Green). Based upon review of the dominant core damage sequences, LERF was not a risk consideration.

This determination was consistent with NextEras risk analysis.

The finding had a cross-cutting aspect in Problem Identification and Resolution (Resolution), because NextEra did not take effective corrective actions to address this issue in a timely manner commensurate with its safety significance. Specifically, NextEra did not perform motor replacements for susceptible installed PCCW motors within a reasonable due date as specified by the 2009 CAPR; and plant procedures, programs and resources were available for the decision-making process to schedule the motor replacement. As a result, the PCCW B motor failed on June 13, 2015. [P.3]

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that for significant conditions adverse to quality, measures shall assure that corrective action is taken to preclude repetition. Contrary to the above, NextEra established but did not perform corrective action to preclude repetition of a significant condition adverse to quality. Specifically, in 2008, two of four primary component cooling water (PCCW) pump motors failed within a four month period, due to a manufacturing defect. NextEra established a CAPR to replace all four motors with re-wound motors, free of the identified manufacturing defect, but that action was repeatedly delayed. As a result, a third motor failure occurred in 2015 from the same cause.

NextEra entered this issue into their corrective action program as AR 2153536, performed a prompt operability determination, and implemented quarterly enhanced motor testing to provide an early indication of degradation associated with the identified manufacturing defect until the scheduled December 2016 motor replacement is completed. The NRC is treating this violation as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy, dated August 1, 2016, because this finding was of very low safety significance and was entered into NextEra's corrective action program (AR 2153536). (NCV 05000443/2016007-01, Inadequate Corrective Actions to Preclude Repetition of a Significant Condition Adverse to Quality)

2. Potential Missed Evaluation for an Adverse Condition for Reportability to the NRC

Introduction:

The team identified an unresolved item (URI) to further review whether NextEras evaluations associated with two PCCW pump motor failures in 2008 and one in 2015, and the associated conclusions not to report the conditions to the NRC, constituted a violation of NRC regulations.

Description:

As described in Section 1R21.2.1.3.1 above, the team reviewed two time periods where NextEra concluded that PCCW motor failures were the result of a manufacturing defect, however, these were not reported to the NRC. Specifically, a manufacturing defect was identified in a third-party failure analysis, dated January 21, 2009, following the failure of PCCW motors C and D in 2008. A third PCCW motor (B) failure occurred due to the same manufacturing defect in June 2015. These failures appeared to occur from one common cause.

During this inspection, the team questioned whether the reporting requirements of 10 CFR Part 21 (Part 21), Reporting of Defects and Noncompliance, were satisfied, because no report was made to the NRC. In response to this concern, NextEra initiated AR 2153374, and initiated a substantial safety hazard (SSH) evaluation for the PCCW pump motor deviations in accordance with Part 21 and NextEra procedure LI-AA-102-1002, Part 21 Reporting. NextEra subsequently completed the SSH determination, and concluded that the deviation (i.e., the manufacturing defect) constituted a defect that could contain an SSH. They notified the NRC in accordance with 10 CFR 21.21(d)(3)(i)reporting requirements on October 20, 2016, via fax (Event Notification 52310).

Subsequent to the onsite inspection, and while evaluating NextEras compliance with Part 21 evaluation and reporting requirements, the NRC noted that 10 CFR 21.2(c)stated, in part, that evaluation of potential defects and appropriate reporting of defects under 10 CFR 50.72 and 50.73 satisfies the evaluation, notification, and reporting obligation to report defects under Part 21.

While the NRC recognized that NextEra had not made an NRC notification related to the identified PCCW motor manufacturing defect in accordance with 10 CFR 50.72, 50.73 or Part 21, the team did not review NextEras specific reportability evaluations with respect to 10 CFR 50.72 and 50.73. The team did note that NextEras Part 21 reviews, both in 2009 and 2015 did not specifically perform the evaluation specified in 10 CFR 21.21(a)(1) to determine whether the deviation in a basic component, which, on the basis of an evaluation, could create a substantial safety hazard.

Since there appears to be overlapping reporting requirements among 10 CFR 50.72, 50.73 and 21.21, and the team did not specifically review NextEras reportability considerations for 10 CFR 50.72 and 50.73, additional inspection is necessary in order to determine whether there was a violation of any of the three reporting regulations.

Accordingly, this issue is being treated as an unresolved item (URI) pending further inspection by the NRC staff to determine whether not evaluating and reporting the manufacturing defect associated with the PCCW motors constituted a more than minor violation of NRC reportability regulations. (URI 05000443/2016007-02, Potential Missed Evaluation and Reporting of an Adverse Condition to the NRC)

.2.1.4 B Emergency Diesel Generator (Electrical)

a. Inspection Scope

The team inspected the B emergency diesel generator (EDG) electrical systems to evaluate if they were capable of operating during design basis events. The team reviewed design and licensing documents, including the UFSAR, the TSs and TRM, the DBD, drawings, and other design documents to determine the specific design functions.

The team reviewed loading and voltage regulation calculations, including the bases for brake horsepower values used, to verify that design bases and design assumptions have been appropriately translated into the design calculations. The team reviewed analyses, surveillance testing results, and maintenance history to assess EDG capability under required operating conditions. The team also reviewed calculations, operating procedures, and technical evaluations to verify that steady-state and transient loading were within design capabilities, adequate voltage would be present to start and operate connected loads, and operation at maximum allowed frequency would be within the design capabilities. The EDG load sequence time delay setpoints, calibration intervals, and results of last calibration were reviewed to determine if the results were consistent with the design requirements.

The team reviewed protection, coordination and short-circuit calculations to verify that the EDG was adequately protected with properly set protective devices during test mode and emergency operation under worst fault conditions. The teams review included the interfaces and interlocks associated with 4.16 kV Bus A5, including voltage protection schemes that initiate connection to the EDG to verify adequacy. The team interviewed system and design engineers and walked down the EDG to independently assess the material condition and to determine if the system alignment and operating environment were consistent with design assumptions. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems. In particular, the team reviewed the NextEra's response to three 1B EDG load excursions that occurred at various times over the last three years.

b. Findings

No findings were identified.

.2.1.5 Unit Auxiliary Transformer X-2A (1-ED-X-2-A)

a. Inspection Scope

The team inspected the X-2A unit auxiliary transformer (UAT) to verify it was capable of performing its design basis function. The team reviewed design and licensing documents, including the UFSAR, drawings, and other design documents to determine the specific design functions. The team also reviewed the system one-line diagram and vendor descriptions to verify that the loadings on the UAT and the associated circuit breakers were within the corresponding transformer and switchgear design ratings. The team reviewed the design assumptions and calculations related to the short-circuit currents, voltage drops and protective relay settings associated with the equipment to verify that output voltage was adequate and the settings were appropriate to meet design requirements. The team also reviewed a sample of completed maintenance activities and test results to verify that the high and low voltage cable feeders had sufficient capacity to supply the current and voltage requirements of the associated substation during normal and postulated accident conditions. The team interviewed engineers and walked down the UAT to independently assess the material condition and to determine if the system alignment and operating environment were consistent with design assumptions. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.6 Solid State Protection System Logic Train A

a. Inspection Scope

The team inspected the solid state protection system (SSPS) 'A' train control panels and relays to determine if they were capable of meeting their design basis requirements.

The team reviewed design and licensing documents, including TSs, drawings, and other design documents to determine the specific design functions. Specifically, the team inspected the design, testing, and operation of the SSPS and associated relays to determine if they could perform their design basis function to actuate the reactor trip breakers upon a valid reactor trip condition and actuate engineered safety features upon a valid initiation signal. The team reviewed functional logic diagrams, TSs, and vendor specifications to determine the performance requirements. The team reviewed maintenance, surveillance, and test procedures to determine whether the established acceptance limits were adequate to ensure reliable operation and to verify whether the equipment performed in accordance with design and licensing basis requirements, industry standards, and vendor specifications. The team also compared as-found and as-left inspection and test results to the established acceptance criteria in order to determine if the SSPS logic and relay test results met the established criteria.

Additionally, the team interviewed system and design engineers and walked down accessible portions of the SSPS system (both installed in the plant and at NextEra's SSPS training and mockup facility) to independently assess the material condition of the system, and to determine if the system alignment and operating environment were consistent with design assumptions. Finally, the team reviewed corrective action documents and system health reports to determine if there were adverse trends and to assess NextEra's capability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.7 Emergency Feedwater System Recirculation Common Check Valve FWV-349

a. Inspection Scope

The team inspected the emergency feedwater (EFW) system recirculation common check valve, FWV-349, to verify that it was capable of meeting its design basis requirements. This check valve is normally closed, and is required to open when the EFW pumps are operating on minimum flow through their respective minimum flow valves. In addition, the check valve closes to provide backup protection to check valve FWV-351 (EFW pump turbine bearing oil cooler return line check valve). The team reviewed design and licensing documents, including the UFSAR, the TSs and TRM, the DBD, the In-Service Test (IST) basis document, drawings, and other design documents to determine the specific design functions. The team reviewed the corrective and preventive maintenance history, as well as test results, to ensure that the design basis and licensing requirements were met.

The team reviewed the EFW recirculation piping calculations and related engineering evaluations to verify adequate pump minimum flow protection under all normal operating and design basis events. Additionally, the team interviewed engineers and conducted several walkdowns of the check valve and surrounding area to verify that the material condition and valve orientation were consistent with the design basis and plant drawings.

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

b. Findings

No findings were identified.

.2.1.8 Safety Injection Accumulator 9A

a. Inspection Scope

The team reviewed the design, testing, and operation of the No. 9A safety injection accumulator to determine whether it could perform its design basis function as a source of borated water, pressurized with nitrogen, in the event of a design basis accident. The team reviewed design and licensing documents, including the UFSAR, the TSs, the drawings, and other design documents to determine the specific design functions.

Specifically, 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 system and design engineers, and reviewed test records and tank pressure boundary tests (and results) to determine 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 reviewed accumulator pressure and level trends to ensure the accumulator was maintained in accordance with design and TS requirements. As an extension of the accumulator, the team assessed the maintenance and operation of the related accumulator discharge isolation and discharge check valves. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.9 B Train Service Water Return Isolation Motor-Operated Valve (1-SW-V19)

a. Inspection Scope

The team inspected the B Train Primary Auxiliary Building service water (SW) return isolation motor-operated valve (MOV), 1-SW-V19, to determine if the valve was capable of performing its design basis function. Valve 1-SW-V19 normally remains open to provide the SW return flow path to the circulating water discharge transition structure during all normal operating modes. The team reviewed design and licensing documents, including the UFSAR, the TSs, the DBD, the IST basis document, drawings, and other design documents to determine the specific design functions. Specifically, the team determined if the valve was capable of isolating the SW discharge flow path to the Atlantic Ocean as required upon receipt of a cooling tower actuation signal to prevent draining down of the cooling tower and maintaining cooling tower basin inventory following a design basis event. The team reviewed MOV diagnostic test results and stroke-timing test data to verify acceptance criteria were met. The team also evaluated whether the MOV safety functions, performance capability, and design margins were adequately monitored and maintained in accordance with NRC Generic Letter 96-05 guidance. The MOV weak link calculation was reviewed to ensure the ability of the valve to remain structurally functional while stroking under design basis conditions; and the team verified that the valve analysis used the maximum differential pressure expected across the valve during worst case operating conditions. Additionally, the team reviewed motor data and degraded voltage conditions to confirm that the MOV would have sufficient voltage and power available to perform its safety function at degraded voltage conditions. The team discussed the design, operation, and component history of the valve with engineering and operations staff and conducted walkdowns of 1-SW-V19 along with accessible SW system piping and components to assess material condition and determine if the installed configuration was consistent with plant drawings, procedures, and the design bases. Finally, the team reviewed corrective action documents to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 0 Service Water Intake

a. Inspection Scope

The team inspected the SW intake to determine whether it could fulfill its design basis function of supplying cooling water to safety-related and non-safety-related systems during normal and accident conditions. The team reviewed applicable portions of the UFSAR, the TSs, the TRM, the DBD, drawings, and other design documents to identify the design basis requirements for the SW intake structure. Silting levels within the SW bay were reviewed to ensure proper SW pump operation. The team reviewed operating and alarm response procedures, SW pump surveillances, operating logs, and instrumentation to ensure that NextEra maintained and operated the SW intake SSC in accordance with the design and licensing basis. The team discussed the design, operation, and component history of the intake structure and related components with engineering and operations staff; and conducted several detailed walkdowns of accessible areas of the intake structure (including the intake transition structures) and associated components to assess configuration control and the material condition of risk-significant SSCs. Material condition of inaccessible areas was assessed by performing a review of periodic inspection reports performed by NextEra and their contractors. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 1 B Emergency Diesel Generator Fuel Oil Transfer Pump (1-DG-P-38-B)

a. Inspection Scope

The team inspected the B EDG fuel oil transfer pump to verify its capability to perform as required during design basis accident conditions for EDG operation. The positive displacement diesel fuel oil transfer pump transfers fuel from the B diesel fuel oil storage tank to the B diesel fuel oil day tank, with manual operator crossover alignment capability from and to the respective A train tanks, if necessary. The team reviewed design and licensing documents, including the UFSAR, the TSs, the DBD, the IST basis document, drawings, and other design documents to determine the specific design functions. The team verified the capability of the fuel oil transfer pump to provide its design flowrate to support EDG operation. In addition, the team verified the basis for the pumps IST acceptance criteria, the basis of various setpoints associated with pump operation, and the availability of adequate net positive suction head during fuel oil transfer pump operation. The team reviewed the control schematic wiring diagram to ensure that the pump would function in accordance with the design basis requirements.

Additionally, the team interviewed engineers and conducted walkdowns of both the A and B fuel oil transfer pumps and systems to verify material condition and pump alignment were consistent with the design basis and plant drawings. Further, the team reviewed NextEras response to operating experience involving tornado missile protection of the systems fuel oil tank vents. Finally, the team reviewed corrective action documents to evaluate whether there were any adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 2 B Emergency Diesel Generator Ventilation

a. Inspection Scope

The team inspected the B EDG ventilation support system to verify its capability to perform as required during design basis accident conditions for EDG operation. The team reviewed design and licensing documents, including the UFSAR, the TSs and TRM, the DBD, drawings, and other design documents to determine the specific design functions. The team reviewed EDG test results and operating procedures to ensure the EDG ventilation support system was operating as designed, and verified appropriate maintenance was being performed on the system. The team also reviewed the EDG system procedures to determine if the ventilation system was being operated within the vendor design limits. The team reviewed the fan curve and worst-case environmental conditions to evaluate whether EDG fan capacity was sufficient to provide adequate flow for heat removal during design basis events. The team reviewed inspection and testing procedures to evaluate whether appropriate maintenance activities were being performed and reviewed past test results to determine if the fan was capable of removing the required heat load. The team conducted a walkdown of the EDG ventilation system and associated equipment and interviewed engineers regarding the maintenance and operation of the fan, in order to assess the material condition of the ventilation system. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 3 B Emergency Diesel Generator Jacket Water Cooling System

a. Inspection Scope

The team inspected the B EDG jacket water (JW) cooling system to verify its capability to perform as required during design basis accident conditions for EDG operation. The team reviewed design and licensing documents, including the UFSAR, the TSs and TRM, the DBD, drawings, and other design documents to determine the specific design functions. The team reviewed EDG test results and operating procedures to ensure the EDG JW cooling system was operating as designed, and verified appropriate maintenance was being performed on the system. The team also reviewed the EDG system procedures to determine if the JW cooling system was being operated within the vendor design limits. The team reviewed the JW heat exchanger specification sheet and maintenance to evaluate whether the subsystems capacity was sufficient to provide adequate heat removal for the EDG during design basis events. The team reviewed inspection and testing procedures to evaluate whether appropriate maintenance activities were being performed and reviewed past test results to determine if the cooling system was capable of removing the required heat load. The team conducted walkdowns of both the A and B EDGs, along with their respective JW cooling systems and associated equipment, prior to and after scheduled TS surveillance operational runs to assess the material condition of the equipment and systems. The team interviewed engineers and operators regarding the maintenance and operation of the associated components, and had the opportunity to observe NextEra staffs removal and replacement of the A EDGs lubricating system prelube pump due to a shaft seal oil leak. Finally, the team reviewed corrective action documents to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 4 B Containment Building Spray Pump (CBS-P-9B)

a. Inspection Scope

The team inspected the B containment building spray (CBS) pump to determine if it was capable of meeting its design basis functions. The team reviewed design and licensing documents, including the UFSAR, the TSs, the IST basis document, drawings, and other design documents to determine the specific design functions. Specifically, the team evaluated whether the B CBS pump was capable of providing adequate flow to provide containment cooling and pressure reduction during postulated design basis scenarios.

The team reviewed the CBS system hydraulic analysis/calculations to determine whether the required total developed head, net positive suction head, and pump run-out conditions had been properly evaluated under all applicable design basis conditions.

The adequacy of water supply sources to the pump, including an assessment of the potential for vortex conditions during pump operation, was also reviewed. The team reviewed system operating and emergency procedures to ensure they were consistent with the design requirements. The team reviewed pump IST procedures, test results, and trends in test data to determine whether pump performance was consistent with design basis assumptions; and verified IST acceptance criteria were appropriately correlated to accident analyses requirements. NextEras actions and response to NRC Bulletin No. 88-04, Potential Safety-Related Pump Loss were reviewed to ensure they were consistent with Next Eras response to the Bulletin.

The team conducted a walkdown of the accessible portions of the pump and associated piping components and interviewed engineers regarding the maintenance and operation of the components, in order to assess the material condition of the CBS system. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 5 B Safety Injection Pump (SI-P-6B)

a. Inspection Scope

The team inspected the B safety injection (SI) pump, SI-P-6B, to determine if it was capable of performing its design basis functions. The team reviewed design and licensing documents, including the UFSAR, the TSs, the DBD, the IST basis document, drawings, and other design documents to determine the specific design functions.

Specifically, the team evaluated whether the B SI pump was capable of providing adequate flow to provide core cooling during postulated design basis scenarios. The team reviewed the SI system hydraulic analysis/calculations to determine whether the required total developed head, net positive suction head, and pump run-out conditions had been properly evaluated under all applicable design basis conditions. The adequacy of water supply sources to the pump, including an assessment of the potential for vortex conditions during pump operation, was also reviewed. The team reviewed system operating and emergency procedures to ensure they were consistent with the design requirements. The team also reviewed pump IST procedures, test results, and trends in test data to determine whether pump performance was consistent with design basis assumptions; and verified IST acceptance criteria were appropriately correlated to accident analyses requirements. NextEras actions and response to NRC Bulletin No. 88-04, Potential Safety-Related Pump Loss were reviewed to ensure they were consistent with NextEras response to the Bulletin.

The team conducted a walkdown of the accessible portions of the pump and associated piping/components and interviewed engineers regarding the maintenance and operation of the components, in order to assess the material condition of the SI system. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings identified.

.2.1.1 6 B Containment Building Spray System Heat Exchanger (1-CBS-E-16-B)

a. Inspection Scope

The team inspected the B CBS system heat exchanger (1-CBS-E-16-B) to evaluate its ability to meet its design basis requirement to provide cooling water to the CBS system during postulated accident conditions. The team reviewed design and licensing documents, including the UFSAR, the TSs, drawings, and other design documents to determine the specific design functions. The team reviewed applicable operating and emergency procedures to determine whether NextEra properly translated design input into the procedures. The team reviewed completed surveillance test results, inspections, and system walkdown reports to ensure that NextEra appropriately addressed potential adverse trends or conditions. The team reviewed the maintenance history, design changes, calculations, design specifications, drawings, and surveillance tests to ensure that the heat exchanger condition and heat removal capability were consistent with accident analyses assumptions. The team conducted several walkdowns of the accessible portions of the heat exchanger and associated piping/components, and interviewed engineers regarding the maintenance and operation of the components, in order to assess the material condition and operating environment of the CBS system. Finally, the team reviewed corrective action documents and system health reports to evaluate whether there were adverse operating trends and to assess NextEra's ability to evaluate and correct problems.

b. Findings

No findings were identified.

.2.1.1 7 Steam Generator Atmospheric Steam Dump Valve 1-MS-PV-3002

a. Inspection Scope

The team inspected the air-operated SG atmospheric steam dump valve (ASDV),1-MS-PV-3002, to verify its ability to meet the design basis requirements in response to postulated transient and accident events. The team reviewed design and licensing documents, including UFSAR, TSs, drawings, and other design documents to determine the specific design functions. The team verified that instrument setpoints were properly translated into system procedures and tests, and reviewed diagnostic and valve stroke test results to verify whether acceptance criteria were met. The team reviewed selected calculations to determine whether design inputs and assumptions were accurate and justified. The team reviewed the ASDV's backup nitrogen supply system to determine if the as-built configuration and operating procedures satisfied design assumptions. The team reviewed the ASDV's maintenance, test results, and functional history, and interviewed the air-operated valve and main steam system engineers to assess whether the ASDV was properly maintained and operated. In addition, the team walked down accessible portions of the ASDV and associated piping and components in order to independently assess the material condition and configuration of the SG pressure relief system. Finally, the team reviewed corrective action documents and system health reports to determine if there were adverse trends and to assess NextEra's capability to evaluate and correct problems.

b. Findings

Failure to Perform Required ASME In-Service Testing of Manual Isolation Valves for the Atmospheric Steam Dump Valves

Introduction:

The team identified a finding of very low safety significance (Green)involving an NCV of TS Surveillance Requirement (SR) 4.0.5, Surveillance Requirements for In-Service Inspection and Testing of American Society of Mechanical Engineers (ASME) Code Class 1, 2, and 3 Components, for the failure to perform testing in accordance with the ASME Operation and Maintenance (OM) Code for four manual valves which had active safety functions. Specifically, the SG tube rupture (SGTR) accident analysis and the emergency operating procedures relied upon an operator manual action to locally close a manual isolation valve to mitigate the consequences of a failed open ASDV on a faulted SG during a SGTR accident.

However, those isolation valves were incorrectly designated as passive valves. As a result, the valves had not been placed in the Seabrook IST Program and tested, as required by the TS and ASME OM Code.

Description:

During plant walk downs, the team observed that two of the four ASDV manual isolation valves (1-MS-V-5 and 35) had material deficiency tags that stated valve has indication of seat leakage, identified during ASDV testing in December 2011.

In follow-up, the team reviewed the associated ARs 1717292 and 1717294, which were both closed to unplanned work orders. NextEra's operability determination, performed in 2011, stated that the slight leakage would not impact offsite dose and is bounded by analysis. However, during this inspection, NextEra staff were unable to provide any basis for their 2011 determination that the observed leakage was bounded by analysis and would not have had an impact on offsite dose during a SGTR event. NextEra reviewed the open work orders and valve history, and determined that no work, repairs, or other corrective actions had been performed on either valve since 2011 to correct the identified leakage, other than routine quarterly ASDV valve testing which also stroked the isolation valves.

NextEras IST surveillance test procedure OX1430.04, Main Steam System Valve Operability Tests, performed a quarterly full stroke exercise test of each ASDV, as required by the OM Code. The test procedure closed the isolation valve associated with each ASDV, stroked the ASDV, then re-opened the isolation valve. The test procedure also performed a leak tightness check of the isolation valve by observing the discharge silencer outlet for the presence of steam flow. The leak tightness acceptance criteria stated:

• A SAT reading is an absence of steam leak-by from the ASDV isolation.

• Steam flow greater than minor wisps is an UNSAT.

• An UNSAT requires initiation of a work request to document the condition.

The team reviewed the test results of the isolation valve leak tightness checks performed in December 2011 (original documentation of seat leakage), the quarterly tests performed in 2014 and in 2015, and the most recent test performed in June 2016, to evaluate the current material conditions of the isolation valves. All of the test results were satisfactory, indicating that the observed steam leakage was not greater than a minor wisp. Although operators stroked the isolation valves each quarter, as part of the ASDV IST test, the team determined that procedure OX1430.04 did not contain acceptance criteria regarding the ability to fully close the isolation valves. Based on the documented qualitative seat leakage checks performed in 2014 thru 2016, the team concluded that the valve seat leakages observed in 2011 were not current issues and that the valves appeared to be reasonable leak tight.

The UFSAR Section 15.6.3, Steam Generator Tube Rupture, assumed the ASDV on the faulted SG would fail open (i.e., worst case single active failure for the event) and the operators would terminate the radiological release by locally manually closing the ASDV isolation valve within 20 minutes. Emergency operating procedure E-3, Steam Generator Tube Rupture, Step 3, Isolate Flow from Ruptured SG, directed operators to locally close the ASDV isolation valve if the ASDV could not be closed. Procedure SM 7.20, Time Critical Operator Action Program, Figure 5.1 Item 3, Locally Isolate Failed Open ASDV to Minimize SGTR Radiological Consequences, verified that the time critical task could be performed within the 20 minute time requirement assumed in the SGTR analysis. Therefore, the team concluded that during a SGTR event, the normally open manual valves in question would have an active safety function to close.

The UFSAR Section 3.9(B).3.2., Pump and Valve Operability Assurance, in part, stated that valves identified as active, which must perform a mechanical motion during the course of performing their safety function in mitigating the consequences of a postulated event, were listed in Table 3.9(B)-27. The team identified that the ASDV isolation valves 1-MS-V-5, 21, 35, and 49 were not listed in the active valve list. Therefore, the team concluded that the UFSAR's active valve list did not list all valves relied upon to change position to mitigate the consequences of design basis accidents or relied upon in execution of the emergency operating procedures.

The team identified that the ASDV isolation valves 1-MS-V-5, 21, 35, and 49 were not included in NextEra's IST Program. OM ISTA-1100, in part, required valves which change position to mitigate the consequences of an accident to be in scope of the OM Code IST requirements. Section ISTC-1300 of the ASME OM, in part, required NextEra to categorize and list each valve to be tested and establish acceptance criteria. The OM Code further required that valves shall be designated as either Category A, seat leakage limited to a specific maximum value, or Category B, seat leakage inconsequential.

ISTC-3540 required manual valves be exercised every 5 years. In addition, ISTC-5210, in part, required NextEra to immediately declare a valve inoperable if it failed to exhibit the required change of position during a valve exercise test.

In response, NextEra stated that the valves had been considered to be passive, with no active safety function, because they were not listed in the UFSAR active valve list. As such, they had not been placed in the IST Program. As a consequence of not being in the IST Program, NextEra had also not determined whether seat leakage would be inconsequential (Category B) or whether seat leakage needed to be limited to a specific maximum value (Category A), as required by the OM Code. NextEra entered this deficiency into their corrective action program as AR 2153195, and verified that the valves had been satisfactorily exercised, as required by the ASME OM Code, during the last surveillance of the ASDVs, performed on June 23, 2016.

NextEra preliminarily assessed seat leakage requirements for the ASDV isolation valves using calculation NAI-1131-001, SGTR Radiological Analysis with Alternate Source Term. NextEra determined that the radiological analysis assumed the isolation valves were leak tight because the analysis had not quantified or evaluated any specific leakage value for those valves. In addition, NextEra preliminarily determined that there was approximately a 13 percent margin between regulatory limit, at the design basis exclusion area boundary, and the results of the radiological consequence analysis.

Based on the results of the qualitative leakage checks performed quarterly, NextEra concluded that the valves were currently sufficiently leak tight, such that there was no significant reduction in the radiological release margin. The team reviewed NextEra's evaluations and determined that their conclusions regarding current operability were reasonable.

Analysis:

The team determined the failure to conduct valve testing in accordance with the IST Program, for valves which had an active safety function, was a performance deficiency. Specifically, degraded valve performance could go uncorrected without adequate acceptance criteria to ensure that a SGTR would not result in an unacceptable increase in the consequences of that accident (i.e., a more than minor reduction in the margin between the postulated licensing basis radiological release and the regulatory limits). As a result of this performance deficiency, unacceptable valve leakage was identified in 2011 without corrective actions being performed, other than to initiate a work order, which did not result in further evaluation or repairs. The team did note that recent valve testing indicated that the current leakage was acceptable.

This finding is more than minor because it was associated with the SSC and Barrier Performance attribute of the Containment Barrier Cornerstone and adversely affected the cornerstone objective of ensuring the reliability of associated risk-important SSCs.

The team performed an SDP screening, in accordance with NRC IMC 0609, Appendix A, SDP for Findings At-Power. The finding screened as very low safety significance (Green) because it was a deficiency confirmed not to represent an actual open pathway in the physical integrity of reactor containment and did not involve an actual reduction in function of hydrogen igniters in the reactor containment.

The finding did not have a cross-cutting aspect because it was not considered to be indicative of current licensee performance. Specifically, UFSAR Table 3.9(B)-27, Active Valve List, listed those valves which were required to mechanically change position to mitigate the consequences of an event, and had been established more than 3 years ago. The team determined that NextEra had not had a reasonable opportunity to identify this issue (i.e., an active valve not on the list) within the last 3 years.

Enforcement:

Seabrook TS SR 4.0.5, in part, required NextEra to perform IST of ASME Code Class 2 valves with active safety functions, in accordance with the ASME OM Code. Specifically, ASME OM Section ISTA-1100, in part, required valves which change position to mitigate the consequences of an accident to be in scope of the OM testing requirements. Section ISTC-1300, in part, required NextEra to categorize and list each valve to be tested and establish acceptance criteria. Section ISTC-5210, in part, required NextEra to immediately declare a valve inoperable if it failed to exhibit the required change of position during a valve exercise test.

Contrary to the above, since 1990 (original construction) until present, four main steam system manual isolation valves, which were designated as ASME Code Class 2 valves and had active safety functions, were not tested in accordance with IST Program requirements. Specifically, isolation valves, which were required to be manually closed to mitigate the consequences of a failed open ASDV during a SGTR accident, were not designated as IST Program valves, seat leakage had not been categorized, and the valve test procedure did not have established acceptance criteria to verify valve operability, as required by the ASME OM Code. NextEras short-term corrective actions included entering the issue into their corrective action program and performing a preliminary operability assessment of the valves. The NRC is treating this violation as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy, dated August 1, 2016, because this finding was of very low safety significance and was entered into NextEra's corrective action program (AR 2153195). (NCV 05000443/2016007-03, Failure to Perform Required ASME In-Service Testing for Manual Isolation Valves for the Atmospheric Steam Dump Valve Block Valves)

.2.2 Review of Industry Operating Experience and Generic Issues (3 samples)

The team reviewed selected operating experience (OE) issues for applicability to the Seabrook Station. The team performed a detailed review of the OE issues listed below to verify that NextEra had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.2.1 NRC Information Notice 2014-03, Turbine-Driven Auxiliary Feedwater Pump Overspeed

Trip Mechanism Issues

a. Inspection Scope

The team assessed NextEras applicability review and disposition of NRC Information Notice (IN) 2014-03, Turbine-Driven Auxiliary Feedwater Pump Overspeed Trip Mechanism Issues. This IN discussed industry OE related to improper adjustments of control mechanisms that led to inoperability of turbine-driven auxiliary feedwater pumps.

The team reviewed NextEras evaluations of the IN to determine whether they appropriately considered the applicable details of the IN and whether potential vulnerabilities were identified and corrected. Additionally, the team reviewed the Seabrook overspeed trip mechanism design with respect to the in-plant configuration and operating history and whether Seabrook was vulnerable to the concerns identified in the IN. The team also performed several walkdowns of turbine driven EFW pump, EFW overspeed trip mechanism, and supporting SSCs; reviewed system corrective action reports; reviewed maintenance and inspection records; reviewed operating and maintenance procedures; and interviewed design engineers to independently evaluate the relevant aspects of the design and configuration of Seabrooks turbine driven EFW pump.

b. Findings

No findings were identified.

.2.2.2 NRC Information Notice 2015-05, Inoperability of Auxiliary and Emergency Feedwater

Auto-Start Circuits on Loss of Main Feedwater Pumps

a. Inspection Scope

The team reviewed NextEra's evaluation of NRC IN 2015-05, Inoperability of Auxiliary and Emergency Feedwater Auto-Start Circuits on Loss of Main Feedwater Pumps. This IN described a design vulnerability identified at several plants which could prevent the EFW system from automatically starting as intended when one main feedwater pump was in a standby or reset mode (e.g., pump running but not injecting). Specifically, the team reviewed the EFW system auto-start logic circuitry to independently evaluate whether the described vulnerability existed. In addition, the team assessed NextEra's evaluation to determine whether it had appropriately considered the applicable details described in the IN and whether NextEra had identified and corrected any potential vulnerabilities.

b. Findings

No findings were identified.

.2.2.3 NRC Information Notice 2014-04, Potential for Teflon Material Degradation in

Containment Penetrations, Mechanical Seals and Other Components

a. Inspection Scope

The team assessed NextEras applicability review and disposition of NRC IN 2014-04, Potential for Teflon Material Degradation in Containment Penetrations, Mechanical Seals and Other Components, with specific focus in the area of containment penetration seals. This IN discussed industry OE regarding environmental qualifications (i.e.,

qualifications to ensure that equipment will be capable of withstanding the ambient conditions under an accident scenario) of particular components containing Teflon which analyses had determined would receive failure threshold doses during a design basis accident. Specifically, containment penetration seals for both safety related and non-Class 1E electrical system cabling must be capable of maintaining pressure-boundary function for containment integrity. Independent testing revealed that Teflon used in containment penetration seals is not qualified for postulated loss of coolant accident radiation environments due to a tendency to embrittle and deteriorate.

The team reviewed NextEras actions, reviews and response to the IN; and verified material lists, vendor material properties, and design of the feedthrough and the seal construction of the electrical penetration assemblies.

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

b. Findings

No findings were identified.

4OA6 Meetings, including Exit

On September 1 and October 5, 2016, the team presented interim inspection results to Mr. Eric McCartney, Site Vice President, and other members of the Seabrook staff.

Following the completion of additional inspection and follow-up activities, the team presented the final inspection results via telephone to Mr. Eric McCartney, Site Vice President, and other members of the Seabrook staff on November 10, 2016. The team verified that no proprietary information was documented in the report.

ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Exelon Personnel

S. Ball, System Engineer

R. Belanger, Senior Mechanical Design Engineer

P. Brangiel, System Engineer

A. Dundin, Operations

H. Ham, Mechanical Supervisor

D. Kelsey, Superintendent, Mechanical and Maintenance Services

J. Klempa, System Engineer

M. Lee, Mechanical Design Engineer

E. Mathews, System Engineer

B. Matte, Electrical Design Engineer

R. Parry, Engineering Supervisor

J. Porozinski, Programs Electrical Engineer

C. Thomas, Senior Licensing Engineer

LIST OF ITEMS

Opened and Closed

05000443/2016007-01 NCV Inadequate Corrective Actions to Preclude Repetition of a Significant Condition Adverse to Quality (Section 1R21.2.1.3.1)

05000443/2016007-02 URI Potential Missed Evaluation and Reporting of an Adverse Condition to the NRC (Section 1R21.2.1.3.2)

05000443/2016007-03 NCV Failure to Perform Required ASME In-

Service Testing of Manual Isolation Valves for the Atmospheric Steam Dump Valve Block Valves (Section 1R21.2.1.17)