IR 05000335/2017001

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NRC Integrated Inspection Report 05000335/2017001 and 05000389/2017001
ML17129A510
Person / Time
Site: Saint Lucie  NextEra Energy icon.png
Issue date: 05/09/2017
From: Ladonna Suggs
NRC/RGN-II/DRP/RPB3
To: Nazar M
Florida Power & Light Co
References
IR 2017001
Download: ML17129A510 (40)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION May 9, 2017

SUBJECT:

ST. LUCIE PLANT - NRC INTEGRATED INSPECTION REPORT 05000335/2017001 AND 05000389/2017001

Dear Mr. Nazar:

On March 31, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your St. Lucie Plant Units 1 and 2. The enclosed integrated inspection report documents the inspection results, which were discussed on April 13, 2017, with Mr. DeBoer, Site Director, and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented one finding of very low safety significance (Green) in this report.

This finding involved a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation or significance of the NCV, or 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 denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator Region II; the Director, Office of Enforcement; and the NRC Resident Inspector at the St. Lucie Power Plant. 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/

LaDonna B. Suggs, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos.: 50-335, 50-389 License Nos.: DPR-67, NPF-16

Enclosure:

IR 05000335/2017001 and 05000389/2017001 w/Attachment: Supplemental Information

REGION II==

Docket Nos: 50-335, 50-389 License Nos: DPR-67, NPF-16 Report Nos: 05000335/2017001, 05000389/2017001 Licensee: Florida Power & Light Company (FP&L)

Facility: St. Lucie Plant, Units 1 & 2 Location: 6501 South Ocean Drive Jensen Beach, FL 34957 Dates: January 1, 2017 to March 31, 2017 Inspectors: T. Morrissey, Senior Resident Inspector S. Roberts, Resident Inspector A. Wilson, Project Engineer (Sections 1R07, 1R20 and 1R22)

A. Butcavage, Reactor Inspector (Section 1R08)

B. Collins, Reactor Inspector (Section 1R08)

S. Sanchez, Sr. Emergency Preparedness Inspector (Sections 1EP2, 1EP3, 1EP4, 1EP5, and 4OA1)

J. Hickman, Emergency Preparedness Inspector (Sections 1EP2, 1EP3, 1EP4, 1EP5, and 4OA1)

J. Panfel, Health Physicist Inspector (Sections 1EP2, 1EP3, 1EP4, 1EP5, and 4OA1)

Approved by: LaDonna B. Suggs, Chief Reactor Projects Branch 3 Division of Reactor Projects

SUMMARY

IR 05000335/2017001, 05000389/2017001; 01/01/2017 - 03/31/2017; St. Lucie Nuclear Plant,

Units 1 and 2; Operability Determinations and Functionality Assessments.

The report covered a three-month period of inspection by the resident inspectors and region based specialist inspectors. One finding of very low safety significance was identified by the inspectors. This finding was considered a Non-Cited Violation (NCV) of NRC requirements.

The significance of inspection findings are indicated by their color (i.e., Green, White, Yellow, or Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, (SDP) dated April 29, 2015. The cross-cutting aspect was determined using IMC 0310, Aspects Within the Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements were dispositioned in accordance with the NRCs Enforcement Policy dated November 1, 2016. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

  • Green: An NRC-identified Green, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for the licensees failure to establish, implement, and maintain written procedures covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, the licensees failure to maintain a plant lubrication manual with correct lubrication oil specifications for the 1B containment spray (CS) pump motor resulted in adding unacceptably low viscosity lubrication oil to the inboard bearing of the 1B CS pump motor. Immediate corrective actions included restoring the 1B CS pump inboard bearing with the correct lubrication oil and placing the issue in the licensees corrective action program.

The licensees failure to correctly specify the 1B CS pump motor inboard bearing lubrication requirements in licensee general maintenance procedure GMP-22 was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the inadequate procedure resulted in adding the incorrect lubrication oil to the 1B CS pump motor bearing, causing the pump to be declared inoperable for approximately 56.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The finding screened to Green because the failure did not: (1) affect the design or qualification of the systems, structures and components, (2) represent an actual loss of function, and (3) represent an actual loss of function of at least a single train for greater than its TS allowed outage time. The finding involved the cross-cutting area of human performance, in the aspect of avoid complacency, in that, the individuals involved with the procedure revision did not implement appropriate error reduction tools to ensure the procedure was appropriately changed to reflect the new lubrication oil requirement [H.12]. (Section 1R15)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power (RTP). On January 31, 2017, the unit was shutdown to investigate and repair reactor coolant system (RCS)leakage from the 1B2 reactor coolant pump (RCP) seal area. The unit was cooled down to Mode 5 (<200o Fahrenheit (F)) in accordance with Technical Specifications (TS) when the leakage was determined to be reactor coolant pressure boundary leakage. The leakage emanated from a through-wall crack on the RCPs lower seal heat exchanger piping which was repaired. The unit was restarted on February 7, 2017 and reached 100 percent RTP on February 8, 2017. The unit was at 100 percent RTP for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent RTP. On February 19, 2017, the control room operators commenced a planned power reduction and manually tripped the reactor at 25 percent RTP on February 20, 2017, to start a planned refueling outage. The unit was restarted on March 23, 2017 and reached 100 percent RTP on March 27, 2017. The unit was at 100 percent RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment (IP 71111.04)

Partial Equipment Walkdowns

a. Inspection Scope

The inspectors conducted partial alignment verifications of the safety-related systems listed below. These inspections included reviews using plant lineup procedures, operating procedures, and piping and instrumentation drawings, which were compared with observed equipment configurations to verify that the critical portions of the systems were correctly aligned to support operability. The inspectors also verified that the licensee had identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers, and that the issues were documented in the licensees corrective action program (CAP). Documents reviewed are listed in the Attachment. This inspection constitutes four samples.

  • Unit 2, 2B and 2C charging pumps while 2A charging pump was out of service (OOS) for maintenance
  • Unit 1, 1B trains of high pressure safety injection (HPSI), low pressure safety injection (LPSI), and containment spray (CS) while their corresponding 1A trains were OOS for maintenance
  • Unit 2, 2B train HPSI system while the 2A train was OOS for maintenance

b. Findings

No findings were identified.

1R05 Fire Protection (IP 71111.05Q)

Fire Area Walkdowns

a. Inspection Scope

The inspectors toured the following plant areas during this inspection period to evaluate conditions related to control of transient combustibles, ignition sources, and the material condition and operational status of fire protection systems, including fire barriers used to prevent fire damage or fire propagation. The inspectors reviewed these activities against provisions in the licensees administrative procedure 1800022, Fire Protection Plan. The licensees fire impairment lists, updated on an as-needed basis, were routinely reviewed. In addition, the inspectors reviewed the CAP database to verify that fire protection problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment. This inspection constitutes six samples.

  • Unit 1 cable spreading room
  • Unit 1 and 2 intake cooling water (ICW) pump area
  • Unit 1 and 2 condensate storage tank areas
  • Unit 2 reactor containment building (RCB) all elevations
  • Unit 2 reactor auxiliary building (RAB), -0.5 foot (ft.) elevation

b. Findings

No findings were identified.

1R06 Flood Protection Measures (IP 71111.06)

.1 Underground Manhole Inspections

a. Inspection Scope

The inspectors performed inspections of manholes MH129, MH130 and MH136. The manholes contained safety-related cables associated with the Unit 1, 1A and 1B emergency diesel generator (EDG) systems and safety-related cables associated with the Unit 1 component cooling water (CCW) system. The inspectors verified cables were not submerged in water, cable support structures were not damaged, splices (if present)appeared intact, and adequate drainage was provided. The inspectors interviewed the responsible licensee personnel performing manhole inspections to determine whether they were knowledgeable of the inspection requirements contained in work order (WO)40426947. Documents reviewed are listed in the Attachment. This inspection constitutes one sample and completes the underground cable inspection.

b. Findings

No findings were identified.

.2 Internal Flooding

a. Inspection Scope

The inspectors conducted a walkdown of the 1A HPSI, LPSI, and CS pump flood area located on the -0.5 ft. elevation of the Unit 1 RAB. The walkdown included inspection of the floor drains to ensure they were clear of debris and that the building structures that ensure flood protection were in accordance with design specifications. The inspectors reviewed the Unit 1 Updated Final Safety Analysis Report (UFSAR), Chapter 9.5A, that describes design features that mitigate a Unit 1 RAB internal flood from a severed fire main. The inspectors reviewed plant procedures that discussed the protection of areas containing safety-related equipment that may be affected by internal flooding. Specific plant attributes that were checked included structural integrity, sealing of penetrations, control of debris, and operability of sump pump systems. Documents reviewed are listed in the Attachment. This inspection constitutes one sample of the internal flooding inspection.

b. Findings

No findings were identified.

1R07 Heat Sink Performance (IP 71111.07)

a. Inspection Scope

The inspectors interviewed engineering personnel responsible for the Unit 2, 2A and 2B CCW heat exchangers (HX) monitoring and performance to ensure that HX preventative maintenance was properly implemented. The inspectors observed and assessed the as-found conditions of both HXs when they were opened for inspection during the Unit 2 refueling outage. The inspectors reviewed action requests (ARs) 2187444 and 2190574 that documented the licensees inspection observations. The inspectors verified the periodic maintenance activities documented in WOs 40421283 and 40421281 were conducted in accordance with licensee procedure 0-PMM-14.01, Component Cooling Water Heat Exchanger Clean/Repair. The inspectors monitored HX tube cleaning activities and verified the HX was properly cleaned and placed back in service. The inspectors walked down portions of the CCW system for signs of degradation and to assess overall material condition, as well as to monitor system parameters for proper operation. The inspectors verified that significant heat sink issues were being identified and entered into the CAP. This inspection constitutes one sample and completes the annual review for heat sink performance inspection.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08

a. Inspection Scope

Non-Destructive Examination Activities and Welding Activities From February 27, 2017, through March 9, 2017, the inspectors conducted an onsite review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the RCS boundary, risk-significant piping and component boundaries, and containment boundaries in Unit 2.

The inspectors either directly observed or reviewed the following non-destructive examinations (NDEs) mandated by the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Code of Record: 2007 Edition with 2008 Addenda) to evaluate compliance with the ASME Code,Section XI and Section V requirements and, if any indications or defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC approved alternative requirement. The inspectors also reviewed the qualifications of the NDE technicians performing the examinations to determine whether they were current and in compliance with the ASME Code requirements.

  • Penetrant Testing (PT), Welded Lug Attachments, SI-2416-352-IA, ASME Code Class 2 (observed)

The inspectors reviewed the following welding activities, qualification records, and associated documents in order to evaluate compliance with procedures and the ASME Code,Section XI and Section IX requirements. Specifically, the inspectors reviewed the work order, repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, and NDE reports.

  • Component ID I-12-SI-499, EC 283720, Weld New Spool Pieces in Place, ASME Code Class 2
  • Component ID V09826, EC 279191, U2, AFW-Add Valve 09826 Flex Connection, ASME Code Class 3 During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any relevant indications that were analytically evaluated and accepted for continued service; therefore, no NRC review was completed for this inspection procedure attribute. Documents reviewed are listed in the

.

Pressurized Water Reactor (PWR) Vessel Upper Head Penetration Inspection Activities The inspectors verified that for the Unit 2 reactor vessel head, a bare metal visual (BMV)examination was required during this outage, in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors observed examinations in the field of the upper reactor vessel closure head surface in the area of the closure flange. The Inspectors also reviewed samples of the video recordings made during the bare metal visual examination of the reactor vessel upper head penetrations annulus areas for penetration numbers 1, 81, 82, 83, 88, 89, 92, 94 and 95, in conjunction with the NDE Level III reviewer. The final NDE summary report for the head examination including the penetrations noted previously was also reviewed to determine if the examinations were performed in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D).

Additionally, the inspectors discussed NRC observations made on penetrations associated with the boric acid stains on in-core instrumentation (ICI) nozzle penetrations.

This discussion resulted in the licensee entering the identified condition in the corrective action program for corrective measures (AR 2189368).

The licensee did not identify any relevant indications that were accepted for continued service. Additionally, the licensee did not perform any welding repairs to the vessel head penetrations since the beginning of the last Unit 2 refueling outage; therefore, no NRC review was completed for these inspection procedure attributes. Documents reviewed are listed in the Attachment.

Boric Acid Corrosion Control Inspection Activities The inspectors reviewed the licensees boric acid corrosion control (BACC) program activities to determine if the activities were implemented in accordance with the commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants, and applicable industry guidance documents. Specifically, the inspectors performed an onsite records review of procedures and the results of the licensees containment walkdown inspections performed during the current refueling outage. The inspectors also interviewed the BACC program owner, conducted an independent walkdown of containment to evaluate compliance with licensees BACC program requirements, and verified that degraded or non-conforming conditions, such as boric acid leaks, were properly identified and corrected in accordance with the licensees BACC and corrective action programs.

Documents reviewed are listed in the Attachment.

The inspectors reviewed the following engineering evaluations, completed for evidence of boric acid leakage, to determine if the licensee properly applied applicable corrosion rates to the affected components; and properly assessed the effects of corrosion-induced wastage on structural or pressure boundary integrity in accordance with the licensee procedures.

  • AR 2094553, SS-07-1B inactive discolored boric acid on downstream flange Steam Generator Tube Inspection Activities The inspectors reviewed the eddy current (EC) examination activities performed in Unit 2 steam generators 2A and 2B during this current refueling outage to verify compliance with the licensees TS, ASME BPVC Section XI, and Nuclear Energy Institute 97-06, Steam Generator Program Guidelines.

The inspectors reviewed the scope of the EC examinations, and the implementation of scope expansion criteria, to verify these were consistent with the Electric Power Research Institute (EPRI) Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7. The inspectors reviewed documentation for a sample of EC data analysts, probes, and testers to verify that personnel and equipment were qualified to detect the applicable degradation mechanisms in accordance with the EPRI Examination Guidelines. This review included a sample of site-specific examination technique specification sheets (ETSS) to verify that their qualification and site-specific implementation were consistent with Appendix H or I of the EPRI examination guidelines. The inspectors also reviewed a sample of EC data for steam generator tubes 2A-R84C99, 2A-R115C68, 2A-R136C83, 2B-R91C76, 2B-R128C103 and 2B-R135C82, with a qualified data analyst, to confirm that data analysis and equipment configuration were performed in accordance with the applicable ETSS and site-specific analysis guidelines. The inspectors verified that recordable indications were detected and sized in accordance with vendor procedures. Documents reviewed are listed in the

.

The inspectors selected a sample of degradation mechanisms from the Unit 2 Degradation Assessment report (i.e. anti-vibration bar wear, wear at V-shaped support pads, and wear at the broached tube support plates in straight sections) and verified that their respective in-situ pressure testing criteria were determined in accordance with the EPRI Steam Generator Integrity Assessment Guidelines, Revision 3. Additionally, the inspectors reviewed EC indication reports to determine whether tubes with relevant indications were appropriately screened for in-situ pressure testing. The inspectors also compared the latest EC examination results with the last Condition Monitoring and Operational Assessment report for Unit 2 to assess the licensees prediction capability for maximum tube degradation and number of tubes with indications. The inspectors verified that the licensees evaluation was conservative and that current examination results were bound by the operational assessment projections.

The inspectors assessed the latest EC examination results to verify that new degradation mechanisms, if any, were identified and evaluated before plant startup. The review of EC examination results included the disposition of potential loose part indications on the steam generator secondary side to verify that corrective actions for evaluating and retrieving loose parts were consistent with the EPRI Guidelines. The inspectors also reviewed a sample of primary-to-secondary leakage data for Unit 2 to confirm that operational leakage in each steam generator remained below the detection or action level threshold during the previous operating cycle.

The inspectors review included the implementation of tube repair criteria and repair methods to verify they were consistent with plant TS and industry guidelines. The inspectors verified that the licensee had selected the appropriate tubes for plugging based on the required plugging criteria. The inspectors reviewed the tube-plugging procedure and directly observed tube-plugging activities for tubes 2A-R84C99, 2A-R115C68 and 2A-R136C83, to determine if the licensee installed the tube plugs in accordance with the applicable procedures.

Furthermore, the inspectors interviewed licensee staff and reviewed a sample of inspection results for the inspection conducted in the secondary side internals of steam generators 2A and 2B, to verify that potential areas of degradation based on site-specific operating experience were inspected, and appropriate corrective actions were taken to address degradation indications. This review included the results of foreign object search and retrieval (FOSAR) activities in both steam generators and an evaluation for a potential loose part in the secondary side of steam generator (SG) 2A.

Additionally, the inspectors reviewed documentation and interviewed licensee staff regarding evaluations and corrective actions for the event(s) which led to the deformation of the SG 2B feed ring and its associated supports which occurred during Cycle 21.

Identification and Resolution of Problems The inspectors reviewed a sample of ISI-related issues entered into the corrective action program to determine if the licensee had appropriately described the scope of the problem and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant.

The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements.

This inspection completes one sample under this inspection procedure.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance (IP

71111.11)

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On January 19, 2017, the inspectors observed and assessed two licensed operator crews during evaluated emergency plan mini-evaluations on the control room simulator.

The first simulated scenario included a RCS leak which progressed into a small break loss of coolant accident (SBLOCA) that required a manual reactor trip. The RCS leak resulted in an Unusual Event emergency classification and the SBLOCA an Alert emergency classification. The second simulated scenario included a loss of offsite power (LOOP) concurrent with a failure of one of the two EDGs. The event degraded further when the second EDG failed. The LOOP concurrent with one EDG failing resulted in an Alert emergency classification. The LOOP with both EDGs failed resulted in a Site Area Emergency classification. All emergency classifications for both scenarios each required a notification to the State.

Documents reviewed are listed in the Attachment. The inspectors also reviewed simulator physical fidelity and specifically evaluated the following attributes related to the operating crews performance:

  • Clarity and formality of communication
  • Ability to take timely action to safely control the unit
  • Prioritization, interpretation, and verification of alarms
  • Correct use and implementation of abnormal and emergency operation procedures, and emergency plan implementing procedures (EPIPs)
  • Control board operation and manipulation, including high-risk operator actions
  • Oversight and direction provided by supervision, including ability to identify and implement appropriate TS actions, regulatory reporting requirements, and emergency plan classification and notification
  • Crew overall performance and interactions
  • Effectiveness of the post-evaluation critique This inspection completes one sample under this inspection procedure.

b. Findings

No findings were identified.

.2 Control Room Observations

a. Inspection Scope

The inspectors observed and assessed licensed operator performance in the main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Documents reviewed are listed in the Attachment.

Specifically, the inspectors observed activities in the control room during the following evolutions:

  • January 31, 2017, Unit 1 shutdown to investigate 1B2 RCP seal leakage
  • February 19-20, 2017, Unit 2 shutdown and cooldown to support a planned refueling outage
  • March 23, 2017, Unit 2 startup from SL2-23 refueling outage The inspectors focused on the following conduct of operations attributes as appropriate:
  • Operator compliance and use of procedures
  • Control board manipulations
  • Communication between crew members
  • Use and interpretation of plant instruments, indications, and alarms
  • Use of human error prevention techniques
  • Documentation of activities, including initials and sign-offs in procedures
  • Supervision of activities, including risk and reactivity management This inspection constitutes three inspection samples.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness (IP 71111.12)

a. Inspection Scope

The inspectors reviewed the performance data and associated ARs for the equipment issues as listed below to verify that the licensees maintenance efforts met the requirements of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants and licensee administrative procedure ADM-17-08, Implementation of 10 CFR 50.65, The Maintenance Rule (MR). The inspectors focused on MR scoping, characterization of maintenance problems and failed components, risk significance, determination of MR a(1) and a(2) classification, corrective actions, and the appropriateness of established performance goals and monitoring criteria. The inspectors also interviewed responsible engineers and observed some of the corrective maintenance activities. The inspectors attended applicable expert panel meetings and reviewed associated system health reports. The inspectors verified that equipment problems were being identified and entered into the licensees CAP. Documents reviewed are listed in the Attachment. This inspection constitutes three samples.

  • ARs 2169311 and 2145642, Unit 1 failures of B and D trains of wide range nuclear instrumentation,
  • AR 2180859, Unit 1 control room air conditioning unit HVA/ACC-3A condenser fans running when unit was secured

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (IP 71111.13)

a. Inspection Scope

The inspectors completed in-office reviews, plant walkdowns, and control room inspections of the licensees online risk assessment of the emergent or planned maintenance activities listed below. The inspectors verified the licensees risk assessment and risk management activities using the requirements of 10 CFR 50.65(a)(4); the recommendations of Nuclear Management and Resource Council (NUMARC) 93-01, Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants; and licensee procedure ADM-17.16, Implementation of the Configuration Risk Management Program. The inspectors also reviewed the effectiveness of the licensees contingency actions to mitigate increased risk resulting from the degraded equipment or plant conditions necessary to support maintenance.

The inspectors interviewed responsible senior reactor operators on-shift, verified actual system configurations, and specifically evaluated results from the online risk monitor (OLRM) or shutdown safety assessment (SSA) for the combinations of OOS risk significant systems, structures and components (SSCs) or plant conditions as listed below. Documents reviewed are listed in the Attachment. This inspection constitutes seven samples.

  • Unit 2, OLRM assessment with the 2B EDG OOS for planned testing and 2B CCW pump OOS for planned maintenance
  • Unit 1, Yellow SSA with the unit in Mode 5 and the RCS depressurized and drained to a lowered inventory condition to support repair of the 1B2 RCP lower seal heat exchanger
  • Unit 2, ORLM assessment with the 2A HPSI and 2A LPSI OOS for planned maintenance and the 2A CS pump OOS for a fitting leak repair
  • Unit 2, Yellow SSA with the unit in Mode 5 and the RCS depressurized and drained to a lowered inventory condition to support removal of the reactor vessel head
  • Unit 2, Yellow SSA with the unit in Mode 5 and 6 with the RCS depressurized and drained to a mid-loop inventory condition to support installation of the reactor vessel head and the removal of the steam generator nozzle dams/installation of the steam generator manways
  • Unit 1, OLRM assessment while repairing the 1B start-up transformer (SUT) breaker to the 1B1 6.9kV switchgear

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments (IP 71111.15)

a. Inspection Scope

The inspectors reviewed the interim dispositions and operability determinations or functionality assessments of the following ARs to ensure that they were properly supported and the affected SSCs remained available to perform their safety function with no increase in risk. The inspectors verified the operability determinations or functionality assessments were performed in accordance with licensee procedure EN-AA-203-1001, Operability Determinations and Functionality Assessments. The inspectors reviewed the applicable UFSAR sections, associated supporting documents and procedures, and interviewed plant personnel to assess the adequacy of the interim dispositions. This inspection constitutes six samples.

  • AR 2187298, Incorrect lubrication oil added to 1B CS pump inboard motor bearing

b. Findings

Introduction:

An NRC-identified Green, non-cited violation (NCV) of TS 6.8.1, Procedures and Programs, was identified for the licensees failure to establish, implement, and maintain written procedures covering activities referenced in NRC Regulatory Guide (RG) 1.33, Revision 2, dated February 1978. Specifically, the licensee failed to maintain a plant lubrication manual with the correct lubrication oil specifications for the 1B CS pump motor.

Description:

On February 21, 2017, the licensee identified that the lubrication oil sample taken from the inboard motor bearing of the 1B CS had a viscosity of 61.2 centistokes (cSt) which was the lower limit for Rust & Oxidation (R&O) 68 lubrication oil required for the bearing. The issue was documented in the CAP as AR 2187298. The 1B CS pump motor had been replaced in October 2016 with a new type of motor in accordance with engineering change (EC) 285611, CS Pump 1B Motor Replacement. The EC specified the use of R&O 68 lubrication oil for this bearing versus R&O 32 oil that had been used for the replaced motor. The licensee determined that general maintenance procedure (GMP)-22, Plant Lubrication Manual, had not been properly updated to reflect this change in lubrication oil requirements, as required by TS 6.8.1 and RG 1.33.

RG 1.33, Section 9.a, Procedures for Performing Maintenance, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. GMP-22, Plant Lubrication Manual, Appendix B, St. Lucie Plant Unit 1 Equipment Lubrication Manual, Revision 63, is a maintenance procedure that can affect the performance of safety-related equipment and must be maintained in accordance with the requirements of TS 6.8.1 and Regulatory Guide 1.33.

Because the licensee failed to update GMP-22, R&O 32 lubrication oil had been added to the inboard bearing reservoir for the new motor after each sampling evolution. The oils are compatible; however, the addition of the lower viscosity R&O 32 oil resulted in a lower viscosity of the combined oils in the bearing. The immediate operability determination (IOD) found that the 1B CS pump was operable but nonconforming since the bearing oil viscosity was in band but at its lower limit of its required viscosity (61.2 cSt). Corrective actions included revising GMP-22 to specify the use of R&O 68 lubrication oil and draining/refilling the bearing reservoir with R&O 68 at the next quarterly run of the pump.

The inspectors reviewed the IOD (AR 2187298) and questioned the licensee whether the viscosity of the lubrication oil in the inboard bearing was within specification for R&O 68 lubrication oil. The viscosity of the sample was at its lower limit; however, the licensee overlooked the fact that additional lower viscosity R&O 32 had been added to make up for the oil drained for sampling. The licensee agreed with the inspector that adding lower viscosity oil after sampling would result in the oil viscosity being low and out of specification. On February 23, 2017 at 1215 hours0.0141 days <br />0.338 hours <br />0.00201 weeks <br />4.623075e-4 months <br />, the licensee declared the 1B CS pump inoperable and drained the inboard bearing reservoir. A sample of the drained oil was determined to have a viscosity of 47 cSt. The licensee refilled the inboard bearing reservoir with R&O 68 lubrication oil and the CS pump was declared operable at 2021 hours0.0234 days <br />0.561 hours <br />0.00334 weeks <br />7.689905e-4 months <br /> that same day. The inspectors determined that the 1B CS pump had been declared inoperable for approximately 56.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The inspectors concerns and the licensees failure to recognize the bearing oil viscosity was outside the allowed viscosity range for R&O 68 lubrication oil was placed in the licensees CAP as AR 2188073.

Although this issue was initially identified by the licensee, the inspectors identified inadequacies in the licensees evaluation of this issue. Specifically, the licensee failed to recognize that the 1B CS pump motor inboard bearing lubrication oil viscosity was lower than that specified by the motor vendor and could result in the inoperability of the pump; therefore, this issue is being treated as NRC-identified.

Analysis:

The licensees failure to correctly specify the 1B CS pump motor inboard bearing lubrication requirements in licensee general maintenance procedure GMP-22 was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the inadequate procedure resulted in adding the incorrect lubrication oil to the 1B CS pump motor bearing, causing the pump to be declared inoperable for approximately 56.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

Using Inspection Manual Chapter (IMC) 0609, Attachment 4, Significance Determination Process, Initial Characterization of Findings, dated October 7, 2016, the finding was determined to affect the Mitigating Systems Cornerstone. Inspectors used IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 - Mitigating Systems Screening Questions dated June 19, 2012, to further evaluate this finding. The finding screened as Green because the inspectors answered NO to the four questions in Section A of Exhibit 2. This finding did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time or two separate safety systems out-of-service for greater than its TS allowed outage time.

The finding involved the cross-cutting area of human performance, in the aspect of avoid complacency (H.12), in that the individuals involved with the procedure revision did not implement appropriate error reduction tools to ensure the procedure was appropriately changed to reflect the new lubrication oil requirement.

Enforcement:

TS 6.8.1, Procedures and Programs, requires, in part, that written procedures be maintained covering activities referenced in RG 1.33. Contrary to TS 6.8.1 and RG 1.33, Section 9.a, from October 2016 until February 21, 2017 the 1B CS pump motor inboard bearing lubricant type was incorrectly specified as required by EC 285611. As a result, incorrect lube oil was added to the inboard bearing of the 1B CS pump motor on several occasions, which eventually exceeded the oil viscosity lower limit on February 21, 2017, and resulted in the 1B CS pump being declared inoperable.

Since the licensee has returned the 1B CS pump to an operable status with the correct lubrication oil and has entered this issue into its CAP as AR 2188073, and because the finding is of very low safety significance (Green), this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRCs Enforcement Policy. (NCV 05000335/2017001-01, Inadequate Procedure Results in Adding an Incorrect Lubrication Oil to the 1B CS Motor Inboard Bearing)

1R18 Plant Modifications (IP 71111.18)

a. Inspection Scope

The inspectors reviewed the procedural change listed below. The documents reviewed included EC 283744 RCP 1B2 Replacement Motor Installation referenced to support Procedure Change Request (PCR) 2180029 for 1-AOP-01.09B2, allowing the operation of 1B2 RCP stator temperature above the original 340F. The inspectors reviewed 10 CFR 50.59 screenings and evaluations and verified that the modification had not affected system operability and availability, associated plant drawings, and discussed the changes with licensee personnel to verify the procedural modification would not adversely affect interfacing systems and that the modification was consistent with the vendors recommendations. This inspection constitutes one sample.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing (IP 71111.19)

a. Inspection Scope

For the maintenance WOs listed below, the inspectors reviewed the test procedures and either witnessed the testing or reviewed test records to determine whether the scope of testing adequately verified that the work performed was correctly completed and demonstrated that the affected equipment was functional and operable. The inspectors verified that the requirements of licensee procedure ADM-78.01, Post Maintenance Testing, were incorporated into test requirements. This inspection constitutes six samples.

  • WO 40358558 - Unit 2 AFW actuation system (AFAS) channel C power supply failure
  • WO 40520631 - Unit 1 control element assembly (CEA) 60 power supply replacement

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities (IP 71111.20)

.1 Unit 1 Maintenance Outage: Repair RCP 1B2 Seal Cooler Heat Exchanger

a. Inspection Scope

On January 30, 2017, Unit 1 was shutdown to investigate and repair the cause of elevated 1B2 RCP stator temperatures along with a rise of RCS unidentified leakage.

After the unit was shut down, the licensee identified a through-wall leak on the return tubing from the 1B2 RCP seal cooler heat exchanger. The leakage was determine to be RCS boundary leakage and the unit was cooled down to Mode 5 (<200oF) as required by TS. The RCS was then depressurized and drained to a lowered inventory condition in order to implement repairs. The defect was removed and the heat exchanger was weld was repaired. The unit was restarted on February 7, 2017 and reached 100 percent RTP on February 8, 2017. Documents reviewed are listed in the Attachment.

Outage Planning, Control and Risk Assessment The inspectors reviewed the licensees outage risk control plan and schedule to verify that the licensee had appropriately considered risk, industry experience, and previous site-specific problems.

Monitoring of Shutdown Activities The inspectors observed portions of the cooldown process to verify that TS cooldown restrictions were followed. The inspectors conducted a containment walkdown after the shutdown to assess the condition of the systems within containment that were inaccessible with the unit at power. The inspectors performed walkdowns of important systems and components used for decay heat removal from the reactor core during the shutdown period including the ICW and the CCW systems.

Outage Activities The inspectors examined outage activities to verify that they were conducted in accordance with TSs, licensee procedures, and the licensees outage risk control plan.

Some of the more significant inspection activities accomplished by the inspectors were as follows:

  • Verified operability of RCS pressure, level, flow, and temperature instruments during various modes of operation
  • Verified electrical systems availability and alignment
  • Evaluated implementation of reactivity controls
  • Examined containment foreign material exclusion controls put in place for the limited work inside containment Heat-up, Mode Transition, and Reactor Startup Activities The inspectors examined selected TSs, license conditions, license commitments and verified administrative prerequisites were being met prior to mode changes. The inspectors also verified containment integrity was properly established. The inspectors performed a containment closeout inspection prior to reactor plant startup. The inspectors witnessed portions of the RCS heat up, reactor startup, and power ascension.

On February 7, 2017, the inspectors verified that startup activities were performed in accordance with licensee general operating procedure 1-GOP-201, Reactor Plant Startup - Mode 2 to Mode 1.

This inspection constitutes one outage sample.

b. Findings

No findings were identified.

.2 Unit 2 Refueling Outage SL2-23

a. Inspection Scope

Outage Planning, Control and Risk Assessment Unit 2 was shut down for a planned refueling outage on February 20, 2017. The inspectors reviewed the licensees outage risk control plan and verified that the licensee had appropriately considered risk, industry experience, and previous site-specific problems. The inspectors also reviewed the outage work schedule for Operations, Maintenance, and the Fire Brigade to confirm the licensee had scheduled covered workers such that the minimum days off for individuals working on outage activities was in compliance with 10 CFR 26.205(d)(4) and (5).

The inspectors reviewed the risk reduction methodology employed by the licensee during various daily refueling outage (RFO) SL2-23 meetings including the outage command center (OCC) morning meetings, operations team meetings, and schedule performance update meetings. The inspectors examined the licensee implementation of SSA during SL2-23 in accordance with licensee procedure OM-AA-101-1000, Shutdown Risk Management, to verify whether a defense in depth concept was in place to ensure safe operations and avoid unnecessary risk. In addition, the inspectors regularly monitored OCC activities, and interviewed responsible OCC management, to ensure system, structure, and component configurations and work scope were consistent with TS requirements, site procedures, and outage risk controls. Documents reviewed are listed in the Attachment.

Monitoring of Shutdown Activities The inspectors monitored RCS cooldown rates to verify they met TS requirements. The inspectors walked down the RCB after the unit was shut down to determine whether any components were impacted by unidentified RCS leakage during the operating cycle.

The RCB, including the RCB sump, was inspected for any debris or degradation experienced during the operating cycle.

Outage Activities The inspectors examined outage activities to verify that they were conducted in accordance with TS, licensee procedures, and the licensees outage risk control plan.

Some of the more significant inspection activities accomplished by the inspectors were as follows:

  • Walked down selected safety-related equipment clearance orders
  • Verified operability of RCS pressure, level, flow, and temperature instruments during various modes of operation
  • Verified electrical systems availability and alignment
  • Evaluated implementation of reactivity controls

around the refueling cavity, near sensitive equipment and RCS breaches)

  • Verified worker fatigue was properly managed Lowered Inventory and mid-loop Conditions The inspectors reviewed the planned activities associated with one period of lowered RCS inventory established in order to remove the reactor vessel head and one period of RCS mid-loop established to re-install the reactor vessel head and remove the SG nozzle dams. The inspectors verified the licensee had controls in place to govern the lowered inventory and mid-loop conditions. The inspectors verified that the necessary instrumentation and means of adding inventory to the RCS were available.

Fatigue Management Activities The inspectors verified the licensee had scheduled covered personnel such that the minimum days off for individuals working on outage activities were in compliance with 10 CFR 26.205(d)(4) and (5). There were no waiver requests, self-declarations or fatigue assessments completed during the outage.

Refueling Activities and Containment Closure The inspectors witnessed selected fuel handling operations being performed according to TS and applicable operating procedures from the main control room, the spent fuel pool (SFP), and the refueling cavity inside containment. The inspectors also examined licensee activities to control and track the position of each fuel assembly. The inspectors evaluated the licensees ability to close the containment equipment, personnel, and emergency hatches promptly per procedure 2-GMM-68.02, Emergency Closure of Containment Penetrations, Personnel Hatch, and Equipment Hatches.

Heat-up, Mode Transition, and Reactor Startup Activities The inspectors examined selected TS, license conditions, and license commitments, and verified administrative prerequisites were being met prior to mode changes. The inspectors also reviewed measured RCS leakage rates, and verified containment integrity was properly established. The inspectors performed a containment sump closeout inspection prior to reactor plant startup and conducted a containment walkdown prior to restarting the unit. The results of low power physics testing were discussed with reactor engineering and operations personnel to ensure that the core operating limit parameters were consistent with the design. The inspectors witnessed portions of the RCS heat up, reactor startup, and power ascension in accordance with the following plant procedures:

  • 2-PTP-81, Reload Startup Physics Testing
  • 2-PTP-91, Unit 1 Initial Criticality Following Refueling
  • 2-GOP-302, Reactor Startup Mode 3 to Mode 2 Corrective Action Program The inspectors reviewed ARs generated during SL2-23 to evaluate the licensees threshold for initiating ARs.

This inspection constitutes one refueling outage sample.

b. Findings

No findings were identified.

1R22 Surveillance Testing (IP 71111.22)

a. Inspection Scope

The inspectors either reviewed or witnessed the following surveillance tests to verify that the tests met TS, UFSAR, and licensee procedural requirements. The inspectors verified the tests demonstrated operational readiness, and that systems were capable of performing their intended safety functions. In addition, the inspectors evaluated the effect of the testing activities on the plant to ensure conditions were adequately addressed by the licensee staff, and after completion of the testing activities, equipment was returned to standby alignment required for the system to perform its safety function.

The inspectors verified that surveillance issues were documented in the CAP.

Documents reviewed are listed in the Attachment. This inspection constitutes seven total samples in the categories listed below.

In-Service Tests:

  • 2-SMI-69.02, Engineered Safeguards Actuation System - Channel Functional Test
  • 1-OSP-01.03, RCS Inventory Balance Containment Isolation Valve Surveillance:
  • 2-OSP-68.02, Local Leak Rate (Penetration 42, reactor cavity sump discharge valve)

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors evaluated the adequacy of the licensees methods for testing and maintaining the alert and notification system in accordance with NRC Inspection Procedure 71114, Attachment 02, Alert and Notification System Evaluation. The applicable planning standard, 10 CFR Part 50.47 (b) (5), and its related 10 CFR Part 50, Appendix E requirements were used as reference criteria. The criteria contained in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, were also used as a reference.

The inspectors reviewed various documents, which are listed in the Attachment, and interviewed personnel responsible for system performance. This inspection activity satisfied one inspection sample for the alert and notification system on a biennial basis.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors reviewed the licensees Emergency Response Organization (ERO)augmentation staffing requirements and process for notifying the ERO to ensure the readiness of key staff for responding to an event and timely facility activation. The qualification records of key position ERO personnel were reviewed to ensure all ERO qualifications were current. A sample of problems identified from augmentation drills or system tests performed since the last inspection was reviewed to assess the effectiveness of corrective actions. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment 03, Emergency Response Organization Staffing and Augmentation System. The applicable planning standard, 10 CFR 50.47(b)(2), and its related 10 CFR 50, Appendix E requirements were used as reference criteria.

The inspectors reviewed various documents, which are listed in the Attachment. This inspection activity satisfied one inspection sample for the ERO staffing and augmentation system on a biennial basis.

b. Findings

No findings were identified.

1EP4 Emergency Action Level (EAL) and Emergency Plan Changes

a. Inspection Scope

Since the last NRC inspection of this program area, no changes were made to the Radiological Emergency Plan, no changes were made to the EALs and several changes were made to the implementing procedures. The licensee determined that, in accordance with 10 CFR 50.54(q), the Radiological Emergency Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The inspectors reviewed these changes to evaluate for potential reductions in the effectiveness of the plan; however, this review was not documented in a safety evaluation report and does not constitute formal NRC approval of the changes.

Therefore, these changes remain subject to future NRC inspection in their entirety.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 04, Emergency Action Level and Emergency Plan Changes. The applicable planning standards of 10 CFR 50.47(b), and its related requirements in 10 CFR 50, Appendix E were used as reference criteria. The inspectors reviewed various documents that are listed in the Attachment to this report. This inspection activity satisfied one inspection sample for the emergency action level and emergency plan changes on an annual basis.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed the corrective actions identified through the Emergency Preparedness program to determine the significance of the issues, the completeness and effectiveness of corrective actions, and to determine if issues were recurring. The licensees post-event action reports, self-assessments, and audits were reviewed to assess the licensees ability to be self-critical, thus avoiding complacency and degradation of their emergency preparedness program. Inspectors reviewed the licensees 10 CFR 50.54(q) change process, personnel training, and selected screenings and evaluations to assess adequacy. The inspectors toured facilities and reviewed equipment and facility maintenance records to assess the licensees adequacy in maintaining associated facilities and equipment. The inspectors evaluated the capabilities of selected radiation monitoring instrumentation to adequately support EAL declarations.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 05, Maintenance of Emergency Preparedness. The applicable planning standards, related 10 CFR 50, Appendix E requirements, and 10 CFR 50.54(q) and (t)were used as reference criteria. The inspectors reviewed various documents, which are listed in the Attachment. This inspection activity satisfied one inspection sample for the maintenance of emergency preparedness on a biennial basis.

b. Findings

No findings were identified.

1EP6 Drill Evaluation Emergency Preparedness Training Evolution

a. Inspection Scope

On January 19, 2017, the inspectors observed and assessed licensed operator crews performance during several short evaluated licensed operator continued training scenarios using the control room simulator. The simulated scenarios included assessing classification of the emergency events and completing notifications to the State. The inspectors assessed the licensees actions to verify that emergency classifications and notifications were timely and made in accordance with the licensee emergency plan implementing procedures and 10 CFR 50.72 requirements. This inspection constitutes one sample of simulator training evolution observations.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification (IP 71151)

.1 Cornerstone: Initiating Events

a. Inspection Scope

The inspectors reviewed licensee submittals for the performance indicators (PIs) listed below for the period of January 1, 2016 through December 31, 2016, to verify the accuracy of the PI data reported during that period. Performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedure ADM-25.02, NRC Performance Indicators, were used to check the reporting for each data element. The inspectors checked operator logs, plant status reports, condition reports, system health reports, and PI data sheets to verify that the licensee had identified the required data, as applicable. The inspectors interviewed licensee personnel associated with PI data collection, evaluation, and distribution.

  • Unit 1 Unplanned Scrams per 7000 Critical Hours
  • Unit 2 Unplanned Scrams per 7000 Critical Hours
  • Unit 1 Unplanned Scrams With Complications
  • Unit 2 Unplanned Scrams With Complications
  • Unit 2 Unplanned Power Changes per 7000 Critical Hours This inspection constitutes six total PI samples.

b. Findings

No findings were identified.

.2 Emergency Preparedness Cornerstone

a. Inspection Scope

The inspectors sampled licensee submittals relative to the PIs listed below for the period January 1, 2016, through December 31, 2016. To verify the accuracy of the PI data reported during that period, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, was used to confirm the reporting basis for each data element.

  • Drill/Exercise Performance (DEP)
  • Emergency Response Organization (ERO) Readiness
  • Alert and Notification System (ANS) Reliability For the specified review period, the inspectors examined data reported to the NRC, procedural guidance for reporting PI information, and records used by the licensee to identify potential PI occurrences. The inspectors verified the accuracy of the PI for ERO drill and exercise performance through review of a sample of drill and event records.

The inspectors reviewed selected training records to verify the accuracy of the PI for ERO drill participation for personnel assigned to key positions in the ERO. The inspectors verified the accuracy of the PI for alert and notification system reliability through review of a sample of the licensees records of periodic system tests. The inspectors also interviewed the licensee personnel who were responsible for collecting and evaluating the PI data. Licensee procedures, records, and other documents reviewed within this inspection area are listed in the Attachment. This inspection satisfied three inspection samples for PI verification on an annual basis.

b. Findings

No findings were identified

4OA2 Identification and Resolution of Problems (IP 71152)

.1 Routine Review

a. Inspection Scope

As required by Inspection Procedure 71152, Identification and Resolution of Problems, and to help identify repetitive equipment failures or specific human performance issues for followup, the inspectors performed a screening of items entered daily into the licensees CAP. This review was accomplished by reviewing daily printed summaries of ARs and by reviewing the licensees electronic AR database. Additionally, RCS unidentified leakage was checked on a daily basis to verify no substantive or unexplained changes.

b. Findings

No findings were identified.

.2 Annual Sample: 2B Charging pump failed to start

a. Inspection Scope

The inspectors selected AR 2188070, which documented the 2B charging pumps failure to start for a more in-depth review of the circumstances and the proposed corrective actions that followed. The inspectors reviewed the equipment apparent cause evaluation report to ensure that the licensee performed an appropriate evaluation, and specified and prioritized corrective actions in accordance with their CAP. The inspectors evaluated the AR in accordance with the requirements of the licensees CAP as specified in licensee procedure PI-AA-104-1000, Condition Reporting. This inspection constitutes one sample.

b. Findings and Observations

No findings were identified. The inspectors found that the apparent cause evaluation for this issue was comprehensive and thorough. The inspectors determined that the corrective actions completed were appropriate to address the identified cause. During the investigation, the licensee identified another potential cause that could lead to the same event. Appropriate corrective actions were also completed to address this vulnerability.

4OA5 Other Activities

(CLOSED) Temporary Instruction (TI) 2515/192, Inspection of the Licensees Interim Compensatory Measures Associated with the Open Phase Condition Design Vulnerabilities in Electric Power Systems.

a. Inspection Scope

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

  • The licensee identified and discussed with plant staff the lessons-learned from the open phase condition events at U.S. operating plants including the Byron Station open phase condition and its consequences. This included conducting operator training for promptly diagnosing, recognizing consequences, and responding to an open phase condition.
  • The licensee updated plant operating procedures to help operators promptly diagnose and respond to open phase conditions on off-site power sources credited for safe shutdown of the plant.
  • The licensee established and implemented periodic walkdown activities to inspect switchyard equipment such as insulators, disconnect switches, transmission lines, and transformer connections associated with the offsite power circuits to detect a visible open phase condition.
  • The licensee ensured that routine maintenance and testing activities on switchyard components have been implemented and maintained. As part of the maintenance and testing activities, the licensee assessed and managed plant risk in accordance with 10 CFR 50.65(a)(4) requirements.

b. Findings

No findings were identified.

4OA6 Meetings

Exit Meeting Summary

On January 27, 2016, the Emergency Preparedness inspectors presented their inspection results to Mr. DeBoer, Site Director, and other members of the staff.

Inspectors also performed a final re-exit on February 6, 2017 with Mr. DeBoer. The inspectors confirmed that proprietary information was not provided or reviewed during the inspection.

On March 9, 2017, the regional specialists inspectors presented their inspection results to Mr. DeBoer, Site Director, and other members of the licensee staff. The inspectors confirmed that all proprietary information reviewed during the inspection was returned and that none of the potential report input discussed was considered proprietary.

On April, 13 2017, the resident inspectors presented their inspection results to Mr.

DeBoer and other members of the licensee staff. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary information. The licensee did not identify any proprietary information.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Bailey, Performance Analyst
R. Baird, Training Manager
G. Bowen, Emergency Preparedness Manager
D. Cecchett, Licensing Engineer
J. Couture, Sr. Emergency Preparedness Coordinator
D. DeBoer, Site Director
J. Francis, Health Physics Manager
K. Frehafer, Licensing Engineer
S. Gebo, Communications Supervisor
M. Haskin, Projects Site Manager
M. Jones, Engineering Director
W. Parks, Operations Director
R. Pitts, Maintenance Director
P. Polfleit, Corporate Emergency Preparedness Manager

F. Pollack Assistant Operations Manager - Line

R. Sciscente, Licensing Engineer
M. Snyder, Licensing Manager
K. Stone, Chemistry Manager
T. Spillman, Assistant Operations Manager - Training
T. Summers, Southern Region Vice President
A. Wier, Emergency Preparedness Coordinator

NRC Personnel

LaDonna

B. Suggs, Chief, Branch 3, Division of Reactor Projects

LIST OF ITEMS

OPENED AND CLOSED

Opened and Closed

05000335/2017001-01 NCV Inadequate Procedure Results in Adding an Incorrect Lubrication Oil to the 1B CS Motor Inboard Bearing (Section 1R15)

Closed

2515/192 TI Inspection of the Licensees Interim Compensatory Measures Associated with the Open Phase Condition Design Vulnerabilities in Electric Power Systems.

(Section 4OA5)

LIST OF DOCUMENTS REVIEWED

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