IR 05000282/2016001

NRC Integrated Inspection Report 05000282/2016001; 05000306/2016001

ML16111B037
Person / Time
Site:	Prairie Island
Issue date:	04/20/2016
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Northard S Northern States Power Co
References
IR 2016001
Download: ML16111B037 (30)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION III 2443 WARRENVILLE RD. SUITE 210 LISLE, IL 60532-4352 April 20, 2016

Mr. Scott Northard Acting Site Vice President Prairie Island Nuclear Generating Plant Northern States Power Company, Minnesota 1717 Wakonade Drive East

Welch, MN 55089 SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000282/2016001; 05000306/2016001

Dear Mr. Northard:

On March 31, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on April 7, 2016, with you and other members of your staff.

The NRC inspectors did not identify any findings or violations of more than minor significance.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, "Public Inspections, Exemptions, Requests for Withholding," of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC's Public Document Room or from the Publicly Available Records System (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA Nick Shah Acting for/

K. Riemer, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-282; 50-306;72-010 License Nos. DPR-42; DPR-60; SNM-2506

Enclosure:

IR 05000282/2016001; 05000306/2016001

REGION III Docket Nos: 50-282, 50-306,72-010 License Nos: DPR-42, DPR-60, SNM-2506

Report No: 05000282/2016001; 05000306/2016001 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: January 1, through March 31, 2016 Inspectors: L. Haeg, Senior Resident Inspector P. LaFlamme, Resident Inspector M. Smith, Resident Inspector, Acting J. Mancuso, Reactor Engineer S. Bell, Health Physicist J. Bozga, Reactor Inspector V. Meghani, Reactor Inspector

Approved by: K. Riemer, Chief Branch 2 Division of Reactor Projects

SUMMARY

Inspection Report 05000282/2016001; 05000306/2016001; 01/01/2016 - 03/31/2016; Prairie Island Nuclear Generating Plant, Units 1 and 2. This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. The NRC inspectors did not identify any findings or violations of more than minor significance. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," dated April 29, 2015. Cross-cutting aspects are determined using IMC 0310, "Aspects Within the

Cross-Cutting Areas," dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy, dated February 4, 2015. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Ov ersight Process," dated February 2014.

NRC-Identified

and Self-Revealed Findings No findings were identified.

Licensee Identified Findings

None

3

REPORT DETAILS

Summary of Plant Status Unit 1 operated at full power for the entirety of the inspection period, with the exception of brief down-power maneuvers to accomplish planned surveillance testing activities. Unit 2 remained within Forced Outage 2F2901HS, shutdown in Mode 3, Hot Shutdown at the beginning of the inspection period following a Unit 2 reactor trip on December 17, 2015. The reactor trip was caused by a main generator-turbine trip due to foreign material later identified within the main generator that resulted in a ground fault. The main generator had been recently replaced during the fall of 2015 Refueling Outage 2R29 that ended on December 3, 2015. On January 26, 2016, Unit 2 was taken to Mode 5, Cold Shutdown, to replace the 21 reactor coolant pump (RCP) seal which was showing preliminary indications of degraded performance.

Following restoration of the 21 RCP and main generator, Unit 2 was returned to full power on February 23, 2016, and remained at full power for the remainder of the inspection period with the exception of brief down-power maneuvers to accomplish planned surveillance testing

activities.

REACTOR SAFETY

===Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition-Heavy Snowfall Conditions

a. Inspection Scope

On February 2, 2016, a winter weather advisory was issued for expected snow squalls. The inspectors observed the licensee's preparations and planning for the significant===

winter weather potential. The inspectors reviewed licensee procedures and discussed potential compensatory measures with control room personnel. The inspectors focused on plant management's actions for implementing the station's procedures for ensuring adequate personnel for safe plant operation and emergency response would be available. The inspectors also reviewed co rrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report. This inspection constituted one readiness for impending adverse weather condition sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• 22 diesel driven cooling water pump (DDCLP);

• D2 emergency diesel generator (EDG); and

• Bus 15 with D2 out-of-service for planned maintenance (PM).

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report (USAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions.

The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report. These inspections constituted three quarterly partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

During the week of March 28, 2016, the inspectors performed a complete system alignment inspection of the Unit 1 component cooling (CC) system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensee's probabilistic risk assessment.

The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and, to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a 5 sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment to this report. This inspection constituted one semi-annual complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Quarterly Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• F5 Appendix A; Fire Detection Zone 11; Fire Areas 20 & 81; Bus 15 & 16 Switchgear Rooms, El. 715'; Revision 17;

• F5 Appendix A; Fire Detection Zone 82; Fire Area 25; D1 Diesel Generator Room; Revision 31;

• F5 Appendix A; Fire Detection Zones 74 & 75; Fire Area 41; Plant Screen House Elevations 670' & 695' Revisions 32 & 30, respectively; and

• F5 Appendix A; Fire Detection Zones 8 & 108; Fire Area 58; Unit 1 695' Elevation Auxiliary Building & Auxiliary Building; Revisions 32 & 28, respectively. The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensee's fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's Individual Plant Examination of External Events (IPEEE) with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plant's ability to respond to a security event. Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensee's CAP. Documents reviewed are listed in the Attachment to this report.

6 These inspections constituted four routine quarterly resident inspector tours samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

.1 Underground Cables

a. Inspection Scope

The inspectors selected inaccessible cables subject to flooding whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions. The inspectors also reviewed the licensee's corrective action documents with respect to past submerged cable issues identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors reviewed the following cables subject to potential submergence:

• Inaccessible cables associated with cooling tower (CT) 11 and 12 buses (portions of TS-required offsite power sources). Documents reviewed are listed in the Attachment to this report. This inspection constituted one underground cables sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On February 24, 2016, the inspectors observed a crew of licensed operators in the plant's simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• the crew's clarity and formality of communications;

• the ability to take timely actions in the conservative direction; 7

• prioritization, interpretation, and verification of annunciator alarms;

• the correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• the ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications. The crew's performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report. This inspection constituted one resident inspector quarterly review of licensed operator requalification sample as defined in IP 71111.11-05

.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On February 22, 2016, the inspectors observed Unit 2 reactor startup activities in the control room. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crew's clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms (if applicable);

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable). The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report. This inspection constituted one resident inspector quarterly observation during periods of heightened activity or risk sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• D5 and D6 EDGs; and

• Safeguards chilled water systems. The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1). The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report. These inspections constituted two routine quarterly evaluations samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Work Week 1611 risk assessment;

• Bus 15 load sequencer testing failure; 9

• Loss of thermal efficiency due to emergent steam supply control valve closure for the 1A moisture separator re-heater; and

• Work Week risk during cooling water strainer planned maintenance. These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)

(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents reviewed are listed in the Attachment to this report. These inspections constituted four maintenance risk assessments and emergent work control samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Unit 2 containment air sample supply isolation valve (control valve (CV)-31642) failure to close;

• Potential single point vulnerabilities associated with CL strainers;

• Inaccessible CT switchgear cables not tested; and

• 11 CC heat exchanger CL outlet valve CV-31381 stroke time outside of reference range. The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and the USAR to the licensee's evaluations to determine

whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment to this report.

10 These inspections constituted four operability evaluation samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification:

• Unit 2 turbine building overhead crane capacity uprate. The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the USAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the Attachment to this report. This inspection constituted one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• 12 DDCLP testing following PM;

• D6 EDG testing following PM;

• 121 safeguards chilled water system testing following PM; and

• 22 containment spray system testing following PM. These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

11 The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test

documentation was properly evaluated. The inspectors evaluated the activities against TSs, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report. These inspections constituted four post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for an unscheduled Unit 2 outage that was ongoing on January 1, 2016, and continued through February 23, 2016. The inspectors reviewed licensee conduct of work to ensure that the licensee considered risk in developing, planning, and implementing outage activities. The inspectors observed or reviewed reactor shutdown operation, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, personnel fatigue management, startup and heatup activities, and identification and resolution of problems associated with the outage. The inspectors evaluated and reviewed Unit 2 main generator recovery efforts and replacement of the 21 RCP seal. Documents reviewed are listed in the Attachment to this report. This inspection constituted one other outage sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety 12 function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• Surveillance Procedure (SP) 1090A; 11 Containment Spray Pump Quarterly Test (Inservice Test (IST));

• SP 2856; 4KV Bus 26 Under-Voltage Relay Test (Routine);

• SP 1035B; Unit 1 Reactor Protection Logic Train "B" (Routine);

• SP 1295; D1 Diesel Generator 6 Month Fast Start Test (Routine); and

• SP 2001AA; Reactor Coolant System Leakage Test [Unit 2] (Reactor Coolant System (RCS) leak detection). The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored

where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP. Documents reviewed are listed in the Attachment to this report.

13 These inspections constituted three routine surveillance testing samples, one IST sample, and one RCS leak detection sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Training Observation

a. Inspection Scope

The inspectors observed a simulator training evolution for licensed operators on January 13, 2016, which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors' activities was to note any weaknesses and deficiencies in the crew's performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report. This inspection constituted one training observation sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours performance indicator (PI), Units 1 and 2, for the period from the first quarter of 2015 through the fourth quarter of 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, "Regul atory Assessment Performance Indicator Guideline," Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of January 1, 2015 through December 31, 2015 to 14 validate the accuracy of the submittals. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report. These inspections constituted two unplanned scrams per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Power Changes per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Power Changes per 7000 Critical Hours performance indicator, Units 1 and 2, for the period from the first quarter of 2015 through the fourth quarter of 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, maintenance rule records, event reports and NRC Integrated Inspection Reports for the period of January 1, 2015 through December 31, 2015 to validate the accuracy of the submittals. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report. These inspections constituted two unplanned power changes per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications performance indicator, Units 1 and 2, for the period from the first quarter of 2015 through the fourth quarter of 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline,"

Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of January 1, 2015 through December 31, 2015, to validate the accuracy of the submittals. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

15 These inspections constituted two unplanned scrams with complications sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the Safety System Functional Failures performance indicator, Units 1 and 2, for the period from the first quarter of 2015 through the fourth quarter of 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 7, dated August 31, 2013, and NUREG-1022, "Event Reporting Guidelines 10 CFR 50.72 and 50.73" definitions and guidance, were used. The inspectors reviewed the licensee's operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, issue reports, event reports and NRC Integrated Inspection Reports for the period of January 1, 2015 through December 31, 2015, to validate the accuracy of the submittals. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report. These inspections constituted two safety system functional failures samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensee's CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was

commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensee's CAP as a result of the inspectors' observations are included in the Attachment to this report.

16 These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's CAP. This review was accomplished through inspection of the station's daily condition report packages. These daily reviews were performed by procedure as part of the inspectors' daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues: Operability Process/IST Program Interface

a. Inspection Scope

During a review of items entered in the licensee's CAP, the inspectors selected CAP 01513072, "CV-31381 IST Stroke Time for OPEN Position Outside Reference Range," to perform an annual follow-up review. The CAP documented that during quarterly stroke time testing of CV-31381 (11 CC heat exchanger cooling water outlet control valve), the valve stroked open in 14.06 seconds. The IST reference range for the open stroke time of this valve was 27.9 to 46.3 seconds, with a limiting open stroke time of 55.6 seconds. The inspectors noted that the safety function of CV-31381 was to fully open, and would do so under spring force upon a loss of non-essential instrument air pressure. Although the valve was opening "faster" than the reference range, licensee procedure H10.1, "ASME Inservice Testing Program," Revision 37 required, in part, a CAP be written and an evaluation be performed within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> to determine whether valve operation was acceptable (i.e. whether t he valve is operable) or whether the valve was inoperable. The inspectors reviewed the February 20, 2016, immediate operability determination (IOD) that requested the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> evaluation and noted that the valve was considered "operable" at that time. On February 23, 2016, the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> evaluation was completed and provided to the duty shift manager. The evaluation concluded that the "reliability/margin [of CV-31381] to perform its safety function in support of system mission time was not impacted," and "the valve is operationally ready to perform its associated open safety function." The shift manager acknowledged an air leak that

existed on the CV-31381 actuator diaphragm that was the likely cause for the faster 17 stroke time, but again considered and documented CV-31381 as operable within CAP 01513072. The inspectors questioned whether the 11 CC system should be considered operable and fully qualified with CV-31381 not meeting its IST reference range stroke criteria.

The shift manager revisited the operability declaration and noted that the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> evaluation did state that a degradation mechanism was present (diaphragm air leak). The shift manager then changed the operability status to operable-but-degraded (OBD), and created an OBD assignment within the parent CAP to track final corrective actions. The inspectors reviewed the IST history for CV-31381 and noted that the valve had been stroking open outside of the reference range (more quickly) during quarterly stroke time tests since October of 2014. Each test required a 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> evaluation and all resulted in declaration of the valve as operable following receipt and review by the shift manager. The inspectors questioned operations management regarding the operability and IST procedural requirements/guidance for the station when IST-components tested outside of their reference ranges, and also questioned the bases for not implementing repairs in a timely manner. Regarding the February 20, 2016, test results for CV-31381 which resulted in an OBD assignment, the inspectors were concerned with prior similar test results that did not have an OBD declaration nor an OBD assignment. The licensee documented the apparent lack of consistency for IST results within CAP 01514995 and performed a review of FP-OP-OL-01, "Operability/Functionality Determinations," and H10.1 to determine the appropriate course of action (training or procedural changes). With respect to the untimely resolution for the CV-31381 air diaphragm leak, the licensee added the issue to the station's "operational challenges" list in an effort to resolve in a timelier manner. The licensee had been unable to repair the valve while online and a lack of spare parts was, in part, the basis for not being able to make timely repairs. The inspectors determined that although the issue had existed for an extended period of time, the issue did not impact operability of the CC or CL systems and was not a safety issue. The inspectors reviewed other CAPs during the last 2 years associated with 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> IST evaluations and identified additional examples where inconsistent CAP assignments were apparent. However, the inspectors did not identify any instances where failure to make an OBD/operable-but-nonconforming assignment resulted in premature failure of a

component. This inspection constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report 05000306/2015-001-00, -01:

21 Fan Coil Unit Leak - Containment Declared Inoperable This condition, which was discovered by the licensee on March 7, 2015, involved ~1 drop/minute CL leak associated with the 21 containment fan coil unit (CFCU).

18 Following discovery, the licensee declared the Unit 2 containment inoperable due to the 21 CFCU CL containment boundary breach inside containment and the 21 CFCU CL supply was then isolated to exit the applicable TS action statement (at the time of discovery, Unit 2 was in Mode 4, Hot Shutdown). The station submitted an 8-hour 10 CFR 50.72 event notification for the condition that, at the time of discovery, could have prevented the fulfillment of the safety function of structures (Unit 2 containment) needed to control the release of radioactive material. The station documented the issue in CAP 01469164, and repaired/replaced the leaking 21 CFCU components on March 14, 2015 to restore the CFCU to an operable status.

The licensee removed tube samples from the 21 CFCU for laboratory failure analyses but did not receive the results prior to the required LER submittal. Therefore, the licensee completed an equipment cause evaluation (ECE) with the best available information. The apparent cause of the leak was determined to be due to excessive CFCU tube stresses incurred during the fall of 2013 refueling outage (2R28). During 2R28 steam generator replacement activities, Unit 2 containment was exposed to intermittent freezing outside ambient temperatures and could have resulted in eventual leakage of the 21 CFCU tubes. The licensee determined that the 21 CFCU leak would not have exceeded the allowable Unit 2 containment leakage limit, but due to the boundary breach of Unit 2 containment, the licensee submitted LER 05000306/2015-001-00 on May 4, 2015. On May 5, 2015, the licensee received laboratory results for the 21 CFCU tube samples indicating that under-deposit corrosion was responsible for the leaks. The licensee captured this information within CAP 01477721 and re-assessed the information under a new ECE. The licensee supplemented LER 05000306/2015-001-00 as -01 with the new causal information and corrective actions to the NRC on September 24, 2015. Interim corrective actions included periodic inspections of the CFCUs for the remainder of the Unit 2 operating cycle and inspections of the Unit 1 CFCUs. Final corrective actions included replacement of all Unit 2 CFCU subject components during the fall of 2015 refueling outage and planned replacements of the Unit 1 CFCU components during the fall of 2016 refueling outage. Long-term corrective actions included periodic replacements of CFCU components at a more appropriate frequency (i.e. every 8-10 years of service). The inspectors reviewed the causal evaluations and circumstances associated with the 21 CFCU leak and did not identify any issues of concern that were associated with performance deficiencies of a more-than-minor nature. Documents reviewed are listed in the Attachment to this report. This LER is closed. This event follow-up review constituted one sample as defined in IP 71153-05.

.2 (Closed) Licensee Event Report 05000306/2016-001-00:

Unit 2 Reactor Trip Due to a Ground Fault Resulting in a Generator Trip This event, which occurred on December 17, 2015, involved an expected auxiliary feedwater system actuation following a Unit 2 main generator trip and resultant turbine and automatic reactor trip. Following the event, the reactor remained safely shutdown in Mode 3, Hot Standby. The cause of the Unit 2 main generator trip was determined to be an internal ground fault within the generator that was newly installed during the fall of 2015 refueling outage. The licensee identified that the ground fault was caused by 19 foreign material introduced during the vendor's manufacturing process. Corrective actions included removal of the foreign material, repairs, and restoration of the Unit 2 main generator.

The inspectors observed portions of the forced shutdown, reviewed the reactor trip report, the licensee's causal evaluation, and circumstances associated with the event and did not identify any issues of regulatory concern. Documents reviewed are listed in the Attachment to this report. This LER is closed. This event follow-up review constituted one sample as defined in IP 71153-05.

4OA6 Management Meetings

.1 Exit Meeting Summary On April 7, 2016, the inspectors presented the inspection results to Mr. S. Northard, Acting Site Vice President, and other members of the licensee staff.

The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary. ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Northard, Site Vice President, Acting

T. Conboy, Director, Site Operations

W. Paulhardt, Plant Manager

J. Bjorseth, Engineering Director

T. Borgen, Operations Manager

J. Crlenjak, Regulatory Affairs Manager, Acting

S. Sharp, Performance Improvement Director

J. Boesch, Maintenance Manager

B. Boyer, Radiation Protection Manager

H. Butterworth, Business Support Director

F. Calia, Human Performance and Organizational Effectiveness Manager

B. Carberry, Emergency Preparedness Manager

J. Corwin, Security Manager

D. Gauger, Chemistry/Environmental Manager

S. Martin, Performance Improvement Manager

A. Chladil, Nuclear Oversight Manager

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

R. Kuntz, Project Manager, Office of Nuclear Reactor Regulation

LIST OF ITEMS

Opened

None

Closed

05000306/2015-001-00 LER 21 Fan Coil Unit Leak - Containment Declared Inoperable (Section 4OA3.1)

05000306/2015-001-01 LER 21 Fan Coil Unit Leak - Containment Declared Inoperable (Section 4OA3.1)

05000306/2016-001-00 LER Unit 2 Reactor Trip Due to a Ground Fault Resulting in a Generator Trip (Section 4OA3.2)

Discussed

None

LIST OF DOCUMENTS REVIEWED

The following is a partial list of documents reviewed during the inspection.

Inclusion on this list does not imply that the NRC inspector reviewed the documents in their entirety, but rather that