IR 05000282/2016004

NRC Integrated Inspection Report 05000282/2016004; 05000306/2016004; 05000282/2016501; and 05000306/2016501

ML17045A350
Person / Time
Site:	Prairie Island
Issue date:	02/14/2017
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Northard S Northern States Power Company, Minnesota
References
IR 2016004, IR 2016501
Download: ML17045A350 (64)

Text

UNITED STATES ary 14, 2017

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000282/2016004; 05000306/2016004; 05000282/2016501; AND 05000306/2016501

Dear Mr. Northard:

On December 31, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at Prairie Island Nuclear Generating Plant, Units 1 and 2. On January 12, 2017, the NRC inspectors discussed the results of this inspection with you and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report. The NRC also completed its annual inspection of the Emergency Preparedness Program. This inspection began on January 1, 2016, and issuance of this letter closes Inspection Report Number 2016501.

Based on the results of this inspection, the NRC has identified two issues that were evaluated under the risk significance determination process as having very low safety significance (Green). The NRC has also determined that two violations are associated with these issues.

Because the licensee entered the issues into the corrective action program, these violations are being treated as Non-Cited Violations (NCVs), consistent with Section 2.3.2 of the Enforcement Policy. These NCVs are described in the subject inspection report. Further, the inspectors documented two licensee-identified violations that were determined to be of very low safety significance in this report. The NRC is also treating these violations as NCVs consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to: (1) the Regional Administrator, Region III; (2) the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and (3) the NRC Resident Inspector Office at the Prairie Island Nuclear Generating Plant.

In addition, if you disagree with the cross-cutting aspect assignment to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector Office at the Prairie Island Nuclear Generating Plant. In accordance with 10 CFR 2.390, of the NRC's "Rules of Practice," a copy of this letter, its enclosure(s), and your response, (if any), will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's Agencywide Documents Access and Management System (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not include any personal privacy or proprietary, information so that it can be made available to the Public without redaction.

Sincerely,

/RA/

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

Enclosure:

IR 05000282/2016004; 05000306/2016004; 05000282/2016501; 05000306/2016501

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report Nos: 05000282/2016004; 05000306/2016004; 05000282/2016501; 05000306/2016501 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: October 1 through December 31, 2016 Inspectors: L. Haeg, Senior Resident Inspector, Prairie Island P. LaFlamme, Resident Inspector, Prairie Island N. Féliz Adorno, Senior Reactor Inspector G. Hausman, Senior Reactor Inspector P. Zurawski, Senior Resident Inspector, Monticello J. Bozga, Reactor Inspector G. ODwyer, Reactor Inspector M. Jones, Reactor Inspector S. Bell, Health Physicist M. Garza, Emergency Preparedness Inspector R. Baker, Operations Engineer Approved by: K. Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report 05000282/2016004; 05000306/2016004; 05000282/2016501; and 05000306/2016501; Prairie Island Generating Plant, Units 1 and 2. Maintenance Risk Assessments and Emergent Work Control; Radiation Monitoring Instrumentation.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One NRC-identified finding and one self-revealed finding was identified during this inspection. 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 NRCs Enforcement Policy, dated November 1, 2016.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, dated July 201

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

A finding of very low safety significance was self-revealed, and an associated NCV of Technical Specification (TS) 5.4.1.a, Procedures, was identified for the licensees failure to properly implement surveillance procedure (SP) 1088B, Train B Safety Injection Quarterly Test, Revision 24, while performing a post-maintenance valve stroke test. Specifically, on November 14, 2016, while cycling a safety injection (SI) system pump suction valve, operators exposed the SI suction header to reactor coolant system (RCS) pressure, causing a relief valve to lift as designed, a subsequent unexpected RCS pressure drop below 240 pounds per square inch (psig), and requiring operators to trip both reactor coolant pumps (RCPs). The licensee entered the issue into the Corrective Action Program (CAP) as CAP 1541821.

The inspectors determined that the licensees failure to properly implement procedure SP 1088B as required by TS 5.4.1.a was a performance deficiency (PD). The PD was determined to be more than minor and a finding in accordance with IMC 0612,

Appendix B, Issue Screening, because it was associated with the Initiating Events Cornerstone attribute of Configuration Control and affected the associated Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors applied IMC 0609, Attachment 4, Initial Characterization of Findings, to this finding. Since the finding pertained to an event while the plant was shut down, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings.

Since the inspectors answered No to all questions within IMC 0609, Appendix G,

Attachment 1, Exhibit 2, Initiating Events Screening Questions, the finding screened as very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the PD was associated with the cross-cutting aspect of Teamwork in the Human Performance cross-cutting area, and involved individuals and work groups not communicating and coordinating their activities within and across organizational boundaries to ensure nuclear safety was maintained. [H.4] (Section 1R13)

Cornerstone: Occupational Radiation Safety

Green.

A finding of very low safety significance, and an associated NCV of Title 10 of the Code of Federal Regulations (10 CFR) 20.1501(c) was identified by the inspectors for the failure to adequately calibrate the electrometer utilized in the validation of a JL Shepherd Calibrator. Specifically on November 30, 2015, the licensee performed a validation of a JL Shepherd Calibrator to ensure its correct operation. The electrometer used was incorrectly calibrated. The electronics and the detectors were required to be calibrated as a set, and this was not performed. The licensee entered this issue into their CAP as CAP 1543432.

The inspectors determined that the licensees failure to properly calibrate the electrometer was a PD. The PD was more than minor and a finding in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process and affected the Cornerstone objective to ensure the adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The inspectors applied IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, to this finding. Since the finding was not associated with as-low-as-reasonably-achievable (ALARA) planning or work controls, nor was there an overexposure or a substantial potential for an over exposure and the ability to assess dose was not compromised, the finding screened as very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the PD was associated with the cross-cutting aspect of Challenge the Unknown in the Human Performance cross-cutting area, and involved the licensee not challenging an unauthorized substitution for part of the electrometer that was damaged during shipment. [H.11] (Section 2RS5.2)

Licensee Identified Violations

Violations of very low safety or security significance or Severity Level IV that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees CAP. The violations and CAP tracking numbers are documented in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at full power at the beginning of the inspection period. On October 15, 2016, Unit 1 was taken offline to begin refueling outage (RFO) 30 (1R30). On November 20, 2016, Unit 1 was placed on line 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 or troubleshooting activities.

Unit 2 operated at full power for the entirety of the inspection period, with the exception of brief down-power maneuvers to accomplish planned surveillance testing or troubleshooting activities.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Safety Analysis Report (USAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed 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. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• Cooling water (CL) system during replacement of 121 motor-driven cooling water pump (MDCLP) motor, and D5/D6 emergency diesel generators (EDGs).

This inspection constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (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:

• Bus 112M 480 volt (V) electrical distribution system;

• Spent fuel pool inventory makeup system; and

• 21 motor driven auxiliary feed water (AFW) subsystem.

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 systems and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Safety Analysis Report (USAR), TS requirements, outstanding work orders (WOs), CAP documents, 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.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Fire Zone 30; Unit 1 fuel handling, spent fuel areas;

• Fire Zone 2; Unit 1 and 2 AFW pump rooms;

• Fire Area 5 (Zones 19 & 108) Unit 1 auxiliary building mezzanine area; and

• Fire Area 79 & 80 (Zones 26 & 43) buses 112 & 111 areas.

The inspectors reviewed these 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 licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants 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 licensees CAP.

Documents reviewed are listed in the Attachment to this report.

These inspections constituted four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On December 7, 2016, the inspectors observed an announced fire drill and fire brigade activation for a simulated fire near the Unit 1 hydrogen seal oil skid. Based on this observation, the inspectors evaluated the readiness of the plant fire brigade to fight fires.

The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions.

Specific attributes evaluated were:

• proper wearing of turnout gear and self-contained breathing apparatus;

• proper use and layout of fire hoses;

• employment of appropriate firefighting techniques;

• sufficient firefighting equipment brought to the scene;

• effectiveness of fire brigade leader communications, command, and control;

• search for victims and propagation of the fire into other plant areas;

• smoke removal operations;

• utilization of pre-planned strategies;

• adherence to the pre-planned drill scenario; and

• drill objectives.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one annual fire protection drill observation sample as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 Annual Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the D1 and D2 EDG jacket water (JW)heat exchangers to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk.

The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. The inspectors also verified that test acceptance criteria considered differences between testing and design conditions.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one annual heat sink performance sample as defined in IP 71111.07-05.

b. Findings

No findings were identified.

.2 Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed operability determinations, completed surveillances, vendor manual information, associated calculations, performance test results and cooler inspection results associated with the 21 component cooling (CC) heat exchanger and the D1 EDG JW heat exchanger. These heat exchangers were chosen based on their risk significance in the licensees Probabilistic Safety Analysis, their important safety-related mitigating system support functions, their operating history, and their relatively low margin.

For the 21 CC heat exchanger, the inspectors reviewed the testing, inspection, maintenance, and monitoring of biotic fouling and macrofouling programs to assess the heat transfer capability of the heat exchanger. This was accomplished by reviewing whether:

(1) the test methods used were consistent with accepted industry practices;

(2) the test conditions were consistent with the selected methodology;

(3) the test acceptance criteria were consistent with the design basis values; and

(4) the results of the heat exchanger performance tests met established acceptance criteria. The inspectors also reviewed whether:

(1) the test results considered differences between testing conditions and design conditions;

(2) the frequency for testing considered previous test result trends; and

(3) test results considered test instrument inaccuracies and differences.

For the 21 CC heat exchanger heat exchanger and the D1 EDG JW heat exchanger, the inspectors reviewed the testing, inspection, maintenance, and monitoring of biotic fouling and macrofouling programs to assess the heat transfer capability of the heat exchanger.

The inspectors reviewed whether:

(1) the methods used to inspect and clean the heat exchanger(s) were consistent with as-found conditions identified, expected degradation trends, and industry standards;

(2) the licensees inspection and cleaning activities had established acceptance criteria consistent with industry standards; and

(3) the as-found results were recorded, evaluated, and dispositioned such that the as-left condition was consistent with the established criteria.

In addition, the inspectors verified the condition and operation of the 21 CC heat exchanger and the D1 EDG JW heat exchanger were consistent with design assumptions in heat transfer calculations and as described in the USAR. This included verification that the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions. In addition, eddy current test reports and visual inspection records were reviewed to determine the structural integrity of the heat exchangers.

The inspectors reviewed the performance of ultimate heat sink (UHS), CL system and its subcomponents such as piping, intake screens, pumps, valves, etc., by tests or other equivalent methods to ensure availability and accessibility to the inplant cooling water systems. Specifically, the inspectors reviewed the UHS in accordance with IP 71111.07, Heat Sink Performance, Section 02.02, Sub-Sections d.2 and d.7.

The inspectors evaluated whether the licensees inspection of the UHS was thorough and of significant depth to identify degradation of the shoreline protection or loss of structural integrity or volume. This included a review to determine whether vegetation present along the slopes was trimmed, maintained, and was not adversely impacting the embankment. In addition, the inspectors assessed the licensees trending and removal of debris or sediment buildup in the UHS to ensure sufficient reservoir capacity.

The inspectors reviewed the results of the licensees inspection of the UHS intake canal and approach canals. The inspectors also reviewed whether identified settlement or movement indicating loss of structural integrity and/or capacity was appropriately evaluated and dispositioned by the licensee.

The inspectors performed a walkdown of the service water intake structure to assess its structural integrity and component functionality. This included observations of the structural integrity of component mounts and an assessment of the functionality of the traveling screens and strainers. The inspectors reviewed licensee activities which monitored, trended, and maintained service water pump bay silt accumulation at acceptable levels, and those which monitored and ensured proper function of pump bay water level instruments. The inspectors also reviewed the licensees ability to ensure functionality of the intake structure during adverse weather conditions. The inspectors assessed whether an adequate amount of water would still flow past sand-limiting underwater weir walls during periods of low river level. The inspectors also evaluated the licensees strategy for protecting against silt intrusion during periods of low flow or low level.

In addition, the inspectors reviewed CAP documents related to heat exchangers/coolers and UHS performance issues to verify that the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of the corrective actions. Documents reviewed are listed in the Attachment to this report.

These inspections constituted three triennial heat sink performance inspection samples as defined in IP 71111.07-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From October 17-November 28, 2016, the inspectors conducted a review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS), risk-significant piping and components and containment systems.

This inspection constituted one ISI sample (see Sections 1R08.1, 1R08.3 and 1R08.5 below), as defined in IP 71111.08-05.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors either observed or reviewed records of the following Non-Destructive Examinations (NDEs) mandated by the American Society of Mechanical Engineers (ASME),Section XI Code, to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Ultrasonic examination of tubesheet to shell for steam generator (SG) 11;

• Magnetic particle examination of an integral attachment support rod for SG 11;

• Visual examination of reactor vessel nuts and washers (1 through 16); and

• Unit 1 metallic containment liner visual examination in 2012.

During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee had not identified any recordable indications.

Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors either observed or reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last refueling outage to determine if the licensee applied the preservice NDEs, and acceptance criteria required by the Construction Code and ASME Code,Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of Construction Code and ASME Code Section IX.

• Unit 1 reactor coolant pump (RCP) seal replacements.

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage for Unit 1. Therefore, no NRC review was completed for this inspection procedure attribute.

For the Unit 1 vessel head, no examination was required pursuant to Title 10 of the Code of Federal Regulations (10 CFR), Part 50.55a(g)(6)(ii)(D) for the current refueling outage. Therefore, no NRC review was completed for this inspection attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed an independent walkdown of the RCS and related lines in the containment, which had received a recent licensee boric acid walkdown, and verified whether the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components.

The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to determine if degraded components were documented in the CAP.

The inspectors also evaluated corrective actions for any degraded RCS components to determine if they met the ASME Section XI Code.

• 11 RCP seal bowl.

The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

• CAP 1465567; 12 RCP Seal Leakage.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute.

For the Unit 1 SGs, no examination was required pursuant to the TSs during the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI/SG-related problems entered into the licensees CAP, and conducted interviews with licensee staff to determine if:

• the licensee had established an appropriate threshold for identifying ISI/SG-related problems;

• the licensee had performed a root cause evaluation (if applicable) and taken appropriate corrective actions; and

• the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI requirements. Documents reviewed are listed in the to this report.

b. Findings

(1) Baffle Former Bolting Analysis Acceptance Criteria

Introduction:

The inspectors identified an Unresolved Item (URI) concerning the analysis that demonstrated the design adequacy of the baffle former bolting under design and licensing basis loading conditions.

Description:

The inspectors reviewed WCAP 17586-P, Determination of Acceptable Baffle-Barrel Bolting for Prairie Island Units 1 and 2, Revision 0; WCAP-15030-NP-A, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions under Faulted Load Conditions, dated March 2, 1999; and Safety Evaluation by the Office of Nuclear Reactor Regulation of WCAP-15029, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted Load Conditions, dated November 10, 1998.

The inspectors were concerned that the licensee had evaluated the baffle former bolting using acceptance criteria different than what was reviewed and approved by the Office of Nuclear Reactor Regulation. In WCAP-15030-NP-A, Section 4.3.2 stated that the stress allowable for primary membrane and bending of irradiated bolt material is taken to 0.9 times Sy (yield stress of baffle bolt material) for the faulted load condition.

The stress allowable used in WCAP 17586-P was based on ASME,Section III, Appendix F, specifically: (minimum of (0.9 times Su) ultimate stress of baffle bolt material), maximum of (0.67 times Su, Sy + 1/3 (Su - Sy)).

The inspectors also reviewed 10 CFR 50.59 Screening No. 4443, Determination of Acceptable Baffle-Barrel Bolting, dated January 24, 2013, to determine whether the licensee performed a 50.59 evaluation for the use of ASME,Section III, Appendix F acceptance criteria. However, the inspectors identified that the change for the use of ASME,Section III, Appendix F acceptance criteria in lieu of the acceptance criteria contained in Section 4.3.2 of WCAP-15030-NP-A was not explicitly reviewed in 50.59 Screening No. 4443.

In response to the inspectors concern, the licensee initiated CAP 1539487, Documentation Missing in 50.59 Screening 4443, dated October 26, 2016.

This issue is an URI pending evaluation of these concerns by the licensee, subsequent inspector review, and discussion with the licensee and Office of Nuclear Reactor Regulation (URI 05000282/2016004-01; 05000306/2016004-01; Baffle Former Bolting Analysis Acceptance Criteria).

1R11 Licensed Operator Requalification Program

.1 Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Test, administered by the licensee from August 18, 2016, through September 29, 2016, required by Title 10 CFR, Part 55.59(a). The results were compared to the thresholds established in Inspection Manual Chapter (IMC) 0609, Appendix I, Licensed Operator Requalification Significance Determination Process," to assess the overall adequacy of the licensees Licensed Operator Requalification Training Program to meet the requirements of 10 CFR 55.59. (Section 02.02).

This inspection constituted one annual operating test results sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On December 5, 2016, the inspectors observed a crew of licensed operators in the plants 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;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews 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 quarterly resident inspector quarterly review of licensed operator requalification sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.3 Resident Inspector Quarterly Observation during Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On October 14 and 15, 2016, the inspectors observed portions of the Unit 1 planned shutdown for the refueling outage from the control room. Activities included power reduction, removing the main generator from service, main turbine over-speed testing and entry into Mode 3. Additionally, on November 19 and 20, 2016, the inspectors observed portions of the Unit 1 startup activities following completion of the refueling outage. These activities required heightened awareness and were related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews 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.

These inspections constituted two resident inspector quarterly observations during periods of heightened activity or risk samples 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:

• Unit 1 RCS; and

• 12 safety injection (SI) system.

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 evaluation samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 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:

• 11 battery discharge test emergent issues;

• Unit 1 shutdown risk following core offload to the spent fuel pool;

• Licensee analysis and walkdown of the Unit 1 SI system following over-pressurization and suction relief valve actuation due to a configuration control event;

• Troubleshooting and repairs of 12 and 22 SG feedwater regulating valves due to flow oscillations;

• Bus 15 ventilation ductwork inspection door latch failure and subsequent repairs; and

• Substation breaker 8H8 failure.

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 six maintenance risk assessments and emergent work control activities samples as defined in IP 71111.13-05.

b. Findings

(1) Failure to Properly Implement a Post-Maintenance Test Procedure during Safety Injection System Valve Testing

Introduction:

A finding of very low safety significance (Green) was self-revealed, and an associated Non-Cited Violation (NCV) of TS 5.4.1.a, Procedures, was identified for the licensees failure to properly implement Surveillance Procedure (SP) 1088B, Train B Safety Injection Quarterly Test, Revision 24, while performing a post-maintenance valve stroke test. Specifically, on November 14, 2016, while cycling an SI system pump suction valve, operators exposed the SI suction header to RCS pressure, causing a relief valve to lift as designed, a subsequent unexpected RCS pressure drop below 240 pounds per square inch (psig), and requiring operators to trip both RCPs.

Description:

On November 14, 2016, Unit 1 was in Mode 5 with both RCPs in service and RCS pressure being maintained at approximately 345 psig. As part of planned ascension to Mode 4, the pressurizer was being maintained solid with the residual heat removal (RHR) system in service controlling pressure in combination with normal letdown. As part of completing required Mode 5 to 4 work activities, control room operators were provided a marked-up copy of SP 1088B to be completed as a post-maintenance test (PMT) prior to transitioning to Mode 4. The PMT required stroking motor valve (MV) 32207, 12 RHR supply to 12 SI pump suction. When the operators proceeded to open MV 32207 per Step 7.1.10 of the marked-up SP 1088B, the 12 SI pump suction header relief valve, SI-4-2, lifted and resulted in an unanticipated drop in RCS pressure. Because the RCS system was being maintained solid in Mode 5, the associated loss of water through the relief valve resulted in a sudden decrease in RCS pressure below 240 psig, requiring operators to trip both RCPs per procedural requirements. To mitigate the loss of RCS inventory, the operators quickly closed MV 32207; isolating the relief valve and stabilizing RCS pressure at approximately 350 psig. In response, the licensee generated CAP 1541821, completed a human performance evaluation, and performed a stress analysis to evaluate the impact of momentarily exposing the 12 SI suction header to RCS pressure.

As part of the inspectors initial review, they noted that cycling MV 32207 under the plant conditions at the time would expose the 12 SI pump suction header to full RCS pressure which was approximately 345 psig during the test. In addition, the inspectors noted that SI-4-2, located on the 12 SI suction header, had a lift set point of 210 psig. The inspectors reviewed the associated CAP, human performance evaluation, SP 1088B, the stress analysis results, and interviewed the associated operations personnel involved in the transient. In their review, the inspectors noted the following contributing performance weaknesses:

• The senior reactor operator (SRO) from the previous night shift who had marked-up SP 1088B had marked prerequisite Step 6.6 not-applicable (N/A).

This step required verification of current plant conditions and was therefore not verified prior to the test;

• The SRO on duty at the time of the test did not adequately review the marked-up SP 1088B prior to cycling MV 32207;

• The pre-job brief and panel walk-downs did not adequately address current plant conditions;

• System flow diagrams were not utilized to verify the lineup or identify that SI-4-2 would lift; and

• The operators involved did not recognize that SI-4-2 would lift above 210 psig upon opening MV 32207.

Based on the above information and subsequent conversations with operations management, the inspectors concluded that the operators failed as a team to implement SP 1088B, Step 6.6 as written and required. Specifically, Step 6.6 directed operators to verify that the RCS was depressurized prior to opening MV 32207. Consequently, the initial mark-up, pre-job brief and execution of SP 1088B were all performed without verifying initial plant conditions prior to opening MV 32207.

Analysis:

The inspectors determined that the licensees failure to properly implement procedure SP 1088B as required by TS 5.4.1.a. was a performance deficiency (PD).

The PD was determined to be more than minor and a finding in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Initiating Events Cornerstone attribute of Configuration Control and affected the associated Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, the licensee failed to properly verify initial plant conditions prior to opening MV 32207, resulting in over-pressurization of the 12 SI system, subsequent lifting of an SI relief valve, loss of RCS inventory, and consequential depressurization of the RCS requiring operators to manually trip both RCPs.

The inspectors applied IMC 0609, Attachment 4, Initial Characterization of Findings, to this finding. Since the finding pertained to an event while the plant was shut down, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings. Per Exhibit 2, Initiating Events Screening Questions, the PD did not require a detailed Phase 2 analysis because it was self-limiting. Specifically, the SI relief valve reseated as designed without operator assistance and therefore would not have resulted in a loss of the RHR system. Since the inspectors answered No to all of the other questions within IMC 0609, Appendix G, Attachment 1, Exhibit 2, the finding screened as very low safety significance (Green).

The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the PD was associated with the cross-cutting aspect of Teamwork in the Human Performance cross-cutting area, and involved individuals and work groups not communicating and coordinating their activities within and across organizational boundaries to ensure nuclear safety was maintained. Specifically, the night shift SRO, day shift SRO, and operators performing the PMT for MV 32207 failed to communicate, coordinate and verify that initial plant conditions were adequate to perform the associated PMT. [H.4]

Enforcement:

Technical Specification 5.4.1.a, Procedures, required, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Rev. 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 9.a. 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 appropriate to the circumstance.

Contrary to the above, on November 14, 2016, the licensee failed to properly implement SP 1088B, Train B Safety Injection Quarterly Test, Revision 24, that required verification of appropriate plant conditions prior to performing the PMT.

Immediate corrective actions included closure of MV 32207, verification that SI-4-2 had re-seated, stabilization of RCS pressure, and initiation of a causal evaluation.

Because this violation was of very low safety significance and was entered into the licensees corrective action program as CAP 1541821, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2016004-02, Failure to Properly Implement a Post-Maintenance Test Procedure during Safety Injection System Valve Testing).

1R15 Operability Determinations and Functionality Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• CAP 1536176, 121 Motor-Driven Cooling Water Pump Loss of Bearing Water Pressure, September 30, 2016;

• CAP 1544831, Through Wall Leak on 4-CL-28 Piping, December 13, 2016;

• CAP 1540462, MV-32266, 11/12 Reactor Coolant Pump Component Cooling Water Inlet Valve Prompt Operability Determination, November 8, 2016; and

• CAP 1540467, CV-31411, 12 Component Cooling Heat Exchanger Return Valve Failed IST Evaluation, November 3, 2016.

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 TS and Updated Safety Analysis Report (USAR) to the licensees 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.

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

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• D2 emergency diesel generator (EDG) air cooler heat exchanger testing following replacement;

• D1 EDG JW heat exchanger testing following repair;

• 21 containment spray (CS) pump testing following supply breaker replacement;

• D1 slow and fast speed start testing following exciter circuitry replacement;

• Integrated safety injection testing following various outage maintenance work on the D2 EDG and B train emergency core cooling system components;

• Testing of 11 CS pump following outage activities; and

• Steam exclusion boundary testing following repairs to inspection door latch.

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):

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 seven post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for 1R30, conducted October 15 through November 20, 2016, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth.

During the refueling outage (RFO), the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below:

• licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TSs when taking equipment out of service;

• implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing;

• installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error;

• controls over the status and configuration of electrical systems to ensure that TSs and OSP requirements were met, and controls over switchyard activities;

• monitoring of decay heat removal processes, systems, and components;

• controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system;

• reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss;

• controls over activities that could affect reactivity;

• maintenance of secondary containment as required by TS;

• licensee fatigue management, as required by 10 CFR 26, Subpart I;

• refueling activities, including fuel handling and sipping to detect fuel assembly leakage;

• startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing; and

• licensee identification and resolution of problems related to RFO activities.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one refueling outage activities sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 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 function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• SP 1853; 4kV Bus 15 Undervoltage Relay Calibration (OMICRON); Revision 2 (Routine);

• SP 1169; Reactor Coolant System Flow Verification; Revision 21 (Routine);

• SP 1305; D2 Diesel Generator Monthly Slow Start Test; Revision 56 (Routine);and

• SP 1072.35; Local Leakage Rate Test of Penetration 35 SI Test Line; Revision 2 (ISO Valve).

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 American Society of Mechanical Engineers (ASME) Code,Section XI, 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.

These inspections constituted three routine surveillance testing samples and one containment isolation valve surveillance testing sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

A region-based inspector performed an in-office review of the latest revisions to the licensees Emergency Plan, Emergency Action Levels (EALs), and EAL Bases document to determine if any changes decreased the effectiveness of the Emergency Plan.

The inspector also performed a review of the licensees Title 10 CFR Part 50.54(q)change process, and Emergency Plan change documentation to ensure proper implementation for maintaining Emergency Plan integrity.

The U.S. NRC review was not documented in a safety evaluation report, and did not constitute approval of licensee-generated changes; therefore, this revision may be subject to future inspection. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one EAL and Emergency Plan Changes sample as defined in IP 71114.04-06.

b. Findings

No findings were identified

2RS1 Radiological Hazard Assessment and Exposure Controls

.1 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors assessed the licensees current and historic isotopic mix, including alpha emitters and other hard-to-detect radionuclides. The inspectors evaluated whether survey protocols were reasonable to identify the magnitude and extent of the radiological hazards.

The inspectors determined if there had been changes to plant operations since the last inspection that may have resulted in any significant new radiological hazard for onsite individuals. The inspectors evaluated whether the licensee assessed the potential impact of these changes and implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard. The inspectors reviewed the last two radiological surveys from selected plant areas and evaluated whether the thoroughness and frequency of the surveys were appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility, including radioactive waste processing, storage, and handling areas to evaluate material conditions and performed independent radiation measurements as needed to verify conditions were consistent with documented radiation surveys.

The inspectors assessed the adequacy of pre-work surveys for select radiologically risk-significant work activities.

The inspectors evaluated the radiological survey program to determine if hazards were properly identified. The inspectors discussed procedures, equipment, and performance of surveys with radiation protection staff and assessed whether technicians were knowledgeable about when and how to survey areas for various types of radiological hazards.

The inspectors reviewed work in potential airborne areas to assess whether air samples were being taken appropriately for their intended purpose and reviewed various survey records to assess whether the samples were collected and analyzed appropriately. The inspectors also reviewed the licensees program for monitoring contamination which has the potential to become airborne.

This inspection constituted one radiological hazard assessment and exposure controls sample as defined in IP 71124.0-05.

b. Findings

No findings were identified.

.2 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors reviewed select radiation work permits (RWPs) used to access high radiation areas and evaluated the specified work control instructions or control barriers.

The inspectors also assessed whether workers where made aware of the work instructions and area dose rates.

The inspectors reviewed electronic alarming dosimeter dose and dose rate alarm setpoint methodologies. For selected electronic alarming dosimeter occurrences, the inspectors assessed the workers response to the alarm, the licensees evaluation of the alarm, and any followup investigations.

The inspectors reviewed the licensees methods for informing workers of changes in plant operations or radiological conditions that could have significantly impacted their occupational dose.

The inspectors reviewed the labeling of select containers of licensed radioactive material that could have caused unplanned or inadvertent exposure to workers.

This inspection constituted one radiological hazard assessment and exposure controls sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.3 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitored material leaving the radiologically controlled area and assessed the methods used for control, survey, and release of material from these areas. As available, the inspectors observed health physics personnel surveying and releasing material for unrestricted use.

The inspectors observed workers leaving the radiologically controlled area and assessed their use of tool and personal contamination monitors and reviewed the licensees criteria for use of the monitors.

The inspectors assessed whether instrumentation was used at its typical sensitivity levels based on appropriate counting parameters or whether the licensee had established a de facto release limit.

The inspectors selected several sealed sources from the licensees inventory records and assessed whether the sources were accounted for and verified to be intact. The inspectors also evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with Title 10 CFR, Part 20.2207.

This inspection constituted one radiological hazard assessment and exposure controls sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.4 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions during tours of the facility.

The inspectors assessed whether the conditions were consistent with applicable posted surveys, RWPs, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination controls. The inspectors evaluated the licensees use of electronic alarming dosimeters in high noise areas as high radiation area monitoring devices.

The inspectors assessed whether radiation monitoring devices were placed on the individuals body consistent with licensee procedures. The inspectors assessed whether the dosimeter was placed in the location of highest expected dose or that the licensee properly employed an U.S. NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in work areas with significant dose rate gradients.

For select airborne area RWPs, the inspectors reviewed airborne radioactivity controls and monitoring, the potential for significant airborne levels, containment barrier integrity, and temporary filtered ventilation system operation.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials stored within pools and assessed whether appropriate controls were in place to preclude inadvertent removal of these materials from the pool.

This inspection constituted one radiological hazard assessment and exposure controls sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.5 High Radiation Area and Very High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors observed posting and physical controls for high radiation areas and very high radiation areas to assess adequacy.

The inspectors conducted a selective inspection of posting and physical controls for high radiation areas and very high radiation areas to assess conformance with performance indicators.

The inspectors reviewed procedural changes to assess the adequacy of access controls for high and very high radiation areas to determine whether procedural changes substantially reduced the effectiveness and level of worker protection.

The inspectors assessed the controls the high radiation areas greater than 1 rem/hour and areas with the potential to become high radiation areas greater than 1 rem/hour for compliance with TSs and procedures.

The inspectors assessed the controls for very high radiation areas and areas with the potential to become very high radiation areas. The inspectors also assessed whether individuals were unable to gain unauthorized access to these areas.

This inspection constituted one radiological hazard assessment and exposure controls sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.6 Radiation Worker Performance and Radiation Protection Technician Proficiency (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance and assessed their performance with respect to radiation protection work requirements, the level of radiological hazards present, and RWP controls.

The inspectors assessed worker awareness of electronic alarming dosimeter set points, stay times, or permissible dose for radiologically significant work as well as expected response to alarms.

The inspectors observed radiation protection technician performance and assessed whether the technicians were aware of the radiological conditions and RWP controls and whether their performance was consistent with training and qualifications for the given radiological hazards.

The inspectors observed radiation protection technician performance of radiation surveys and assessed the appropriateness of the instruments being used, including calibration and source checks.

This inspection constituted one radiological hazard assessment and exposure controls sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.7 Problem Identification and Resolution (02.08)

a. Inspection Scope

The inspectors assessed whether problems associated with radiological hazard assessment and exposure controls were being identified at an appropriate threshold and were properly addressed for resolution. For select problems, the inspectors assessed the appropriateness of the corrective actions. The inspectors also assessed the licensees program for reviewing and incorporating operating experience.

The inspectors reviewed select problems related to human performance errors and assessed whether there was a similar cause and whether corrective actions taken resolve the problems.

The inspectors reviewed select problems related to radiation protection technician error and assessed whether there was a similar cause and whether corrective actions taken resolve the problems.

This inspection constituted one radiological hazard assessment and exposure controls sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

.1 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors assessed select portable survey instruments that were available for use for current calibration and source check stickers, and instrument material condition and operability.

The inspectors observed licensee staff demonstrate performance checks of various types of portable survey instruments. The inspectors assessed whether high-range instruments responded to radiation on all appropriate scales.

The inspectors walked down area radiation monitors and continuous air monitors to determine whether they were appropriately positioned relative to the radiation sources or areas they were intended to monitor. The inspectors compared monitor response with actual area conditions for selected monitors.

The inspectors assessed the functional checks for select personnel contamination monitors, portal monitors, and small article monitors to verify they were performed in accordance with the manufacturers recommendations and licensee procedures.

This inspection constituted one radiation monitoring instrumentation sample as defined in IP 71124.05-05.

b. Findings

No findings were identified.

.2 Calibration and Testing Program (02.03)

a. Inspection Scope

The inspectors assessed laboratory analytical instruments used for radiological analyses to determine whether daily performance checks and calibration data indicated that the frequency of the calibrations was adequate and there were no indications of degraded instrument performance. The inspectors assessed whether appropriate corrective actions were implemented in response to indications of degraded instrument performance.

The inspectors reviewed the methods and sources used to perform whole body count functional checks before daily use and assessed whether check sources were appropriate and aligned with the plants isotopic mix. The inspectors reviewed whole body count calibration records since the last inspection and evaluated whether calibration sources were representative of the plant source term and that appropriate calibration phantoms were used. The inspectors looked for anomalous results or other indications of instrument performance problems.

Inspectors reviewed select containment high-range monitor calibration and assessed whether an electronic calibration was completed for all range decades, with at least one decade at or below 10 rem/hour calibrated using an appropriate radiation source, and calibration acceptance criteria was reasonable.

The inspectors reviewed select monitors used to survey personnel and equipment for unrestricted release to assess whether the alarm setpoints were reasonable under the circumstances to ensure that licensed material was not released from the site. The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine consistency with the manufacturers recommendations.

The inspectors reviewed calibration documentation for select portable survey instruments, area radiation monitors, and air samplers. The inspectors reviewed detector measurement geometry and calibration methods for portable survey instruments and area radiation monitors calibrated onsite and observed the licensee demonstrate use of the instrument calibrator. The inspectors assessed whether appropriate corrective actions were taken for instruments that failed performance checks or were found significantly out of calibration, and that the licensee had evaluated the possible consequences of instrument use since the last successful calibration or performance check.

The inspectors reviewed the current output values for instrument calibrators.

The inspectors assessed whether the licensee periodically measured calibrator output over the range of the instruments used with measuring devices that have been calibrated by a facility using National Institute of Standards and Technology (NIST)traceable sources and corrective factors for these measuring devices were properly applied in its output verification.

The inspectors reviewed the licensees Title 10 CFR, Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, source term to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

This inspection constituted one radiation monitoring instrumentation sample as defined in IP 71124.05-05.

b. Findings

(1) Failure to Adequately Calibrate an Electrometer

Introduction:

A finding of very-low safety significance (Green), and an associated Non-Cited Violation (NCV) of 10 CFR 20.1501(c) was identified by the inspectors for the failure to adequately calibrate the electrometer utilized in the validation of a JL Shepherd Calibrator. Specifically, on November 30, 2015, the licensee performed a validation of a JL Shepherd Calibrator to ensure its correct operation. The electronics and the detectors were required to be calibrated as a set, and this was not performed.

Description:

Most of the radiation protection radiological survey instrumentation at Prairie Island are calibrated onsite by licensee personnel using a radiation source that was characterized annually using a sensitive instrument called an electrometer. The electrometer is comprised of multiple pieces that act as a unit to measure the amount of radiation emitted from a source. The electrometer and associated radiation sensitive detectors are tested and if the units response meets the precision and reproducibility standards specified by NIST, then the electrometer can act as a transfer standard.

This transfer standard is then used to characterize the radiation source(s) at the facility to identify the amount of radiation emitted over a known period of time at a measured distance from the radiation source. This characterization is repeated at different distances and plotted to develop calibration curves. These calibration curves are then used to adjust the plants radiation protection radiological survey instrumentation to a known dose rate emitted from the radiation source in a process called instrumentation calibration.

On June 30, 2015, a licensee vendor off-site tested the Prairie Island electrometer and its associated detectors as a set and determined that the performance satisfied the requirements established by NIST. During transit back to the licensee, the electrometer was found to be damaged. Rather than fixing the electrometer for the set, the licensee obtained a different electrometer from a different facility. On November 30, 2015, the licensee used this combination to perform the annual characterization of the radiation sources in their JL Shepherd Calibrator. The JL Shepherd Calibrator is then used to calibrate numerous radiation detecting devices such as ion chambers and telescoping dose rate GM devices.

The inspectors questioned the adequacy of calibration curves generated for the JL Shepherd Calibrator radiation sources using the combination of an electrometer and detectors which were not tested as a set. The licensee contacted the vendor that subsequently determined that the components must be tested as a set to ensure correct operation.

The licensee then entered this issue into its corrective action program (CAP) on November 29, 2016, as CAP 1543432. Licensee procedure RPIP 1530, Victoreen R Meter, Revision 6, did not specify that the calibration was required to be performed as a set.

Analysis:

The inspectors determined that the failure to properly calibrate the electrometer as specified by the manufacturer was within the licensees ability to foresee and correct and should have been prevented; therefore a performance deficiency (PD)existed. The PD was more than minor and a finding in accordance with Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process and affected the Cornerstone objective to ensure the adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, the correct usage of the electrometer and its associated detectors was used to verify that the JL Shepherd Calibrators radioactive sources and shields along with its other components correctly operate. This was necessary because the JL Shepherd Calibrator was then used to calibrate numerous radiation detecting instruments.

The inspectors applied IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, to this finding. Since the finding was not associated with as-low-as-reasonably-achievable (ALARA) planning or work controls, nor was there an overexposure or a substantial potential for an overexposure and the ability to assess dose was not compromised, the finding screened as very low safety significance (Green).

The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the PD was associated with the cross-cutting aspect of Challenge the Unknown in the Human Performance cross-cutting area, and involved the licensee not challenging an unauthorized substitution for part of the electrometer that was damaged during shipment. [H.11]

Enforcement:

Title 10 CFR 20.1501(c) requires, the licensee shall ensure that instruments and equipment used for quantitative radiation measurements (e.g., dose rate and effluent monitoring) are calibrated periodically for the radiation measured.

Contrary to this requirement, on November 30, 2015, the licensee used an electrometer which was not correctly calibrated. The licensee performed an evaluation using an alternative method to ensure the JL Shepherd Calibrator was operating satisfactorily.

Because this violation was of very-low safety significance and was entered into the licensees CAP as CAP 1543432, this violation is being treated as a NCV consistent with Section 2.3.2 of NRC Enforcement Policy (NCV 05000282/2016004-03; 05000306/2016004-03; Failure to Adequately Calibrate an Electrometer).

.3 Problem Identification and Resolution (02.04)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by the licensee at an appropriate threshold and were properly addressed for resolution. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring instrumentation.

This inspection activity constituted one complete sample as defined in IP 71124.05-05.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

.1 Sampling and Analyses (02.04)

a. Inspection Scope

The inspectors reviewed select effluent sampling activities and assessed whether adequate controls had been implemented to ensure representative samples were obtained.

This inspection activity supplemented those documented in Inspection Report (IR) 05000282/2016003; 05000306/2016003 and constituted one sample as defined in IP 71124.06-05.

b. Findings

No findings were identified.

.2 Instrumentation and Equipment (02.05)

a. Inspection Scope

The inspectors assessed whether surveillance test results for TS required ventilation effluent discharge systems met TS acceptance criteria.

This inspection activity supplemented those documented in IR 05000282/2016003; 05000306/2016003 and constituted one sample as defined in IP 71124.06-05.

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 Mitigating Systems Performance IndexEmergency Alternating Current Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI)Emergency Alternating Current (AC) Power System performance indicator (PI), Units 1 and 2, for the period from the fourth quarter of 2015 through the third quarter of 2016. To determine the accuracy of the PI data reported during these periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, CAP documents, event reports and NRC Integrated IRs for the period of October 1, 2015, through September 30, 2016, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP 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 MSPIEmergency AC Power System samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance IndexResidual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI-RHR System PI, Units 1 and 2, for the period from the fourth quarter of 2015 through the third quarter of 2016. To determine the accuracy of the PI data reported during these periods, PI definitions and guidance contained in the NEI Document 99-2, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, CAP documents, MSPI derivation reports, event reports and NRC Integrated IRs for the period of October 1, 2015, through September 30, 2016, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees CAP 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 MSPI-RHR system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance IndexCooling Water System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPICooling Water System PI, Units 1 and 2, for the period from the fourth quarter of 2015 through the third quarter of 2016. To determine the accuracy of the PI data reported during these 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 licensees operator narrative logs, CAP documents, MSPI derivation reports, event reports and NRC Integrated IRs for the period of October 1, 2015, through September 30, 2016, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP 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 MSPICooling Water System samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Exposure Control Effectiveness PI for the period from the fourth quarter of 2015 through the third quarter of 2016. To determine the accuracy of the PI data reported during these 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 licensees assessment of the PI for occupational radiation safety to determine if the indicator related data was adequately assessed and reported. To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry dose rate and accumulated dose alarms and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one occupational exposure control effectiveness sample 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 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 licensees CAP at an appropriate threshold, adequate attention was being given to timely corrective actions, and adverse trends were identified and addressed. Some minor issues were entered into the licensees corrective action program as a result of the inspectors observations; however, they not discussed in this report.

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.

b. Findings

No findings were identified.

.2 Semiannual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 1, 2016, through December 31, 2016, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the licensees corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This inspection constituted one semiannual trend review sample as defined in IP 71152.

b. Findings

No findings were identified.

.3 Annual Followup of Selected Issues: 21 Safeguards Exhaust Fan Past Operability

Review Revision

a. Inspection Scope

The inspectors selected the following CAP for in-depth review:

• Revision to past operability review (POR) 1517613, 21 Safeguards Exhaust Fan Failure to Start, following inspector review of CAP 1517613 during the 2016 Biennial Problem Identification and Resolution Inspection at Prairie Island IR 05000282/2016007; 05000306/2016007 and documentation of NCV 05000282/2016007; 05000306/2016007.

As appropriate, the inspectors verified the following attributes during their review of the licensee's corrective actions for the above condition reports and other related condition reports:

• complete and accurate identification of the problem in a timely manner commensurate with its safety significance and ease of discovery;

• consideration of the extent of condition, generic implications, common cause, and previous occurrences;

• evaluation and disposition of operability/functionality/reportability issues;

• classification and prioritization of the resolution of the problem commensurate with safety significance;

• identification of the root and contributing causes of the problem;

• identification of corrective actions, which were appropriately focused to correct the problem;

• completion of corrective actions in a timely manner commensurate with the safety significance of the issue;

• effectiveness of corrective actions taken to preclude repetition; and

• evaluate applicability for operating experience and communicate applicable lessons learned to appropriate organizations.

The inspectors discussed the corrective actions and associated evaluations with licensee personnel.

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

b. Findings

No findings were identified.

.4 Annual Followup of Selected Issues: Reactor Vessel Head and Upper Internals Lift Rig

Examination Methods

a. Inspection Scope

The inspectors selected the following for in-depth review:

• The licensees 50.59 evaluation which established the basis to change the type of non-destructive examination method used to inspect the reactor vessel head lift rig and reactor internals lift rig.

As appropriate, the inspectors verified the following attributes during their review of the licensee's corrective actions for the above condition reports and other related condition reports:

• complete and accurate identification of the problem in a timely manner commensurate with its safety significance and ease of discovery;

• consideration of the extent of condition, generic implications, common cause, and previous occurrences;

• evaluation and disposition of operability/functionality/reportability issues;

• classification and prioritization of the resolution of the problem commensurate with safety significance;

• identification of the root and contributing causes of the problem;

• identification of corrective actions, which were appropriately focused to correct the problem;

• completion of corrective actions in a timely manner commensurate with the safety significance of the issue;

• effectiveness of corrective actions taken to preclude repetition; and

• evaluate applicability for operating experience and communicate applicable lessons learned to appropriate organizations.

The inspectors discussed the corrective actions and associated evaluations with licensee personnel.

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

b. Findings

No findings were identified.

.5 Annual Followup of Selected Issues: Review of Enforcement Discretion Non-Cited

Violations Identified During the Prairie Island 2014 Cyber Security Inspection and Associated Corrective Action Program Documents

a. Inspection Scope

The inspector performed a review of the licensees CAP and associated documents:

• CAP 1432550, Media Retained In Chart Recorders Not Documented In Program;

• CAP 1432729, NRC Asked If SD Cards/Dongles Are In Portable Media Program;

• CAP 1433064, Consider Proceduralizing Cyber Comp. Device Scanning Process;

• CAP 1433246, NRC Cybersecurity - Target Set CDA [Critical Digital Asset]

Protection Issue;

• CAP 1433432, Cyber Milestone 2 - Digital Equipment Not Identified; and

• CAP 1433467, CDAs Not Identified As Target Set CDAs.

The inspector interviewed personnel, verified the completion of and assessed the adequacy of the corrective actions taken in response to four NRC-identified NCVs given enforcement discretion.

The inspectors review and evaluation was focused on the NRC identified NCVs to ensure corrective actions were: complete, accurate, and timely; considered extent of condition; provided appropriate classification and prioritization; provided identification of root and contributing causes; appropriately focused; action taken resulted in the correction of the identified problem; identified negative trends; operating experience was adequately evaluated for applicability; and applicable lessons learned were communicated to appropriate organizations.

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

b. Background In accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 73, Section 54, Protection of Digital Computer and Communication Systems and Networks (i.e., the Cyber-Security Rule), each nuclear power plant (NPP) licensee was required to submit to the NRC for review and approval a cyber-security plan and an associated implementation schedule by November 23, 2009. A Temporary Instruction (TI) 2201/004, Inspection of Implementation of Interim Cyber Security Milestones 1 - 7 was developed to evaluate and verify each NPP licensees ability to meet the interim milestone requirements of the Cyber Security Rule. On June 6, 2014, the NRC completed an inspection at the Prairie Island Nuclear Generating Plant, Units 1 and 2, which evaluated the interim cyber security Milestones 1 - 7. During performance of the TI, four NRC identified NCVs were identified and incorporated into the licensees CAP. The four NCVs were subsequently given enforcement discretion following the Security Issues Forum Meeting conducted on June 18, 2014. During the week of November 14, 2016, the inspector reviewed the Cyber Security Milestones 1 - 7 Inspection NCVs as a PI&R sample. The CAP documents were evaluated to determine the effectiveness of the licensees corrective actions.

c. Observations As discussed in the Inspection Scope section above, the inspectors review was focused on the licensees actions to ensure the corrective actions for the NCVs were appropriately focused to correct the identified problems. During the inspectors review of the cyber-security inspections CAP documents, the following observation was made:

• Due to the number of cross-referencing within CAPs, verification of all corrective actions by the inspector was cumbersome. The inspector also made this observation during the licensees Monticello PI&R Inspection, where CAP 1531267, NRC INSP: OBS - Use of Cross-References, dated August 11, 2016, was issued to evaluate the utilization of cross references.

This CAP remained open at the end of the inspection period for the licensees Fleet Performance Assessment Group to determine the appropriate use of cross-references in the Performance Assessment procedures.

d. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000282/2015005-00: Possible

Misapplication of C18.1, Engineered Safeguards Equipment Support Systems and LER 05000282/2015005-01: Condition Prohibited by Technical Specifications

a. Inspection Scope

The inspectors reviewed information regarding the September 11, 2015, identification by the licensee of several instances where technical specification (TS) 3.8.9, Distribution SystemsOperating, Condition A, was not entered as required per procedure C18.1, Engineered Safeguards Equipment Support Systems. Specifically, on seven separate occasions over the prior three years from the date of discovery, when a train of the safeguards chilled water system (SCWS) was removed from service, TS 3.8.9 required actions to declare safeguards buses 15 or 16 inoperable, were not performed within the required completion time. The licensee documented the issue in CAP 1488482 and performed an apparent cause evaluation that determined that C18.1 was not accurate nor properly usable - leading to the conditions prohibited by TS. The licensee also determined that validation reviews were not properly conducted as required by FP-G-DOC-04, Procedure Processing, during two prior changes to C18.1. Corrective actions included changes to C18.1 to implement the Safety Function Determination Program (SFDP) for future SCWS removals from service, and revisions to the FP-G-DOC-04 job familiarization guide to ensure validation reviews are properly performed.

The inspectors reviewed Revision-00 to this Licensee Event Report (LER) (submitted November 9, 2015), as well as the apparent cause evaluation and identified several concerns. This led to the licensee supplementing the LER (same reportable issue, different LER titles) on October 10, 2016. The concerns and resolutions of the concerns via the supplement were:

• The event date of the LER appeared incorrect based on questions being raised in the CAP on September 4, 2016. This was resolved in Revision-01 to the LER to state that the latest removal from service of a SCWS train occurred on September 4, 2016, but that the C18.1 misapplication issue (reportable condition)was recognized on September 11, 2016;

• A discussion regarding the extent of conditions prohibited by TS appeared to be lacking considering a Note within Condition A of TS 3.8.9 that required Limiting Condition for Operation (LCO) 3.8.4, DC SourcesOperating, to also be entered during the SCWS removals from service. Title 10 CFR 50.73(b)(2)(ii)(G)required, in part, for failures of components with multiple functions, include a list of systems or secondary functions that were also affected. Since Revision-00 only discussed AC subsystems, there appeared to be a lack of detail and an inadequate POR to ensure that safety function was not impacted for direct current (DC) sources. The licensee re-performed the POR, did not identify any past losses of safety function for DC sources, and discussed this in the LER supplement; and

• Title 10 CFR 50.73(b)(2)(ii)(J) required, in part, for each human performance related root cause, the licensee shall discuss the cause(s) and circumstances.

The inspectors noted that the cause was unclear and the circumstances were not discussed in Revision-00 of the LER. The licensee revised the apparent cause evaluation to specify that although the cause human performance related, the individual involved no longer worked at the station and therefore, the circumstances could not be determined.

The inspectors determined that the clarifications contained within Revision-01 to this LER were, in the end, minor in nature and did not represent a failure to report as required by 10 CFR 50.73. Documents reviewed are listed in the Attachment to this report. These LERs are closed.

This inspection constituted one event followup sample as defined in IP 71153-05.

b. Findings

The inspectors determined that a licensee-identified NCV of Prairie Island TS 5.4.1.a, Procedures, had occurred associated with the circumstances surrounding these LERs.

Refer to Section 4OA7 of this inspection report for details regarding the licensee-identified NCV.

.2 (Closed) Licensee Event Report 05000282/2016005-00: 121 Motor Driven Cooling

Water Pump Auto Start

a. Inspection Scope

The inspectors reviewed information provided by the licensee regarding the August 21, 2016, loss of power and automatic actuation on low discharge pressure of the 121 motor-driven cooling water pump (MDCLP). Following an unexpected lockout of the 2RY transformer with the 121 MDCLP in service, the 121 MDCLP stopped as designed, but then restarted automatically based on low discharge pressure. Since low pressure actually existed in the cooling water (CL) header (valid actuation signal) the licensee submitted an LER for this event/condition based on 10 CFR 50.73(a)(2)(iv)(A)as an event or condition that resulted in automatic actuation of an emergency service water system that does not normally run and serves as an ultimate heat sink.

The inspectors reviewed licensee CAP 1532318 that was generated as a result of the 2RY lockout, the causal evaluation, and corrective actions. No issues were identified.

Documents reviewed are listed in the Attachment to this report. This LER is closed.

This inspection constituted one event followup sample as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 (Closed) Notice of Violation 05000306/2015008-01: Failure to Correct a Non-Cited

Violation Associated with Inadequate Gas Monitoring of Inaccessible Residual Heat Removal Gas Susceptible Locations On April 11, 2011, the inspectors identified that the licensee had not developed alternative methods to monitor the potential for gas accumulation at five inaccessible gas susceptible locations that required periodic monitoring. This issue was captured by the licensee in their CAP as CAP 1271826, and was documented by the inspectors as NCV 05000282/2011003-09; 05000306/2011003-09, Alternative Methods Were Not Developed for Monitoring Inaccessible Susceptible Locations, in Prairie Island IR 05000282/2011003; 05000306/2011003, dated August 1, 2011.

On October 22, 2015, the inspectors identified that the licensee had not corrected this NCV for two of the five locations. This issue was captured by the licensee in the CAP as CAP 1498169, and was documented by the inspectors as Notice of Violation (VIO)05000306/2015008-01, Failure to Correct an NCV Associated with Inadequate Gas Monitoring of Inaccessible RHR Gas Susceptible Locations, in IR 05000282/2015008; IR 05000306/2015008, dated January 5, 2016. This violation was cited consistent with the NRC Enforcement Policy, Section 2.3.2.a.2, because the licensee had not restored compliance and did not have objective plans to restore compliance in a reasonable time period following the identification of the NCV. On February 4, 2016, the licensee replied to the VIO in a letter titled Reply to Notice of Violation; VIO 5000306/2015008-01.

The letter included:

(1) the reason for the violation;

(2) the corrective steps taken and the results achieved;

(3) the corrective steps that would be taken; and

(4) the date that full compliance would be achieved.

On October 14, 2016, the licensee documented in their CAP that the corrective actions associated with this VIO were verified to be complete. Subsequently, the inspectors reviewed the licensees letter of reply to the VIO, the corrective action documentation, and supporting reference information to assess the causal evaluation and corrective actions. The inspectors also reviewed recent inspection results for the affected gas susceptible locations to assess the implementation of the corrective actions. No new issues were identified. This review did not constitute an inspection sample. This violation is closed.

.2 (Closed) Unresolved Item 05000282/2014003-04; 05000306/2014003-04: Failure to

Meet Alternate Source Term Amendment Implementing Requirement

a. Inspection Scope

The inspectors documented Unresolved Item (URI)05000282/2014003-04; 05000306/2014003-04 in Prairie Island IR 05000282/2014003; 05000306/2014003 associated with the failure to meet an implementing requirement associated with an alternate source term (AST) license amendment issued in January of 2013.

Specifically, the licensee notified the NRC on March 26, 2014, that they would not be able to revise the plant design and licensing bases to indicate that the steam generator water level narrow range instrumentation meet Regulatory Guide 1.97, Revision 2, requirements within 90 days from implementation of the AST amendment that occurred on December 27, 2013. Because the licensees course of action and NRC acceptance of the actions were unclear at the end of the IR 2014003 inspection period, the URI was opened at that time.

Following the licensees identification of the above compliance issue, the licensee generated CAP 1424460, performed a root cause evaluation, and submitted a new license amendment request on December 11, 2014, to separate steam generator narrow range (SGNR) water level instrumentation compliance with Regulatory Guide 1.97 from AST implementation. On November 30, 2015, NRC issued license amendments that revised, in part, TS Table 3.3.3-1, Event Monitoring Instrumentation, adding Function 17 for SGNR instrumentation, and notes that required instrumentation compliance with Regulatory Guide 1.97 no later than Cycle 30 for both Units 1 and 2 (fall of 2016 and fall of 2017, respectively). The NRC staff also determined, as part of issuance of the amendment, that existing instrumentation was adequately qualified to remain capable of providing indication during a postulated steam generator tube rupture event until modifications were accomplished. The licensee successfully replaced instrumentation with Regulatory Guide 1.97 compliant equipment, during the fall of 2015 refueling outage for Unit 2 and fall of 2016 refueling outage for Unit 1.

The inspectors reviewed the root cause evaluation for the above issues and determined that the licensee properly identified root and contributing causes, and corrective actions.

This review did not constitute an inspection sample. This URI is closed.

b. Findings

The inspectors determined that a licensee-identified NCV of the Prairie Island Operating License had occurred. Refer to Section 4OA7 of this inspection report for details regarding the licensee-identified NCV.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 12, 2017, the inspectors presented the overall inspection results to Mr. S. Northard, 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.

.2 Interim Exit Meetings

Interim exits were conducted for the following:

• On October 31, 2016, the inspectors presented the inspection results of the Annual Operating Test Results inspection to Mr. F. Collins, Senior Operations Instructor. The licensee acknowledged the issues presented;

• On November 4, 2016, the inspectors presented the inspection results of the Radiological Hazard Assessment and Exposure Controls inspection to Mr. H. Butterworth, Director, Business Support, and other members of the licensee staff. The licensee acknowledged the issues presented;

• On November 4, 2016, the inspectors presented the inspection results of the Radiological Hazard Assessment and Exposure Controls inspection to Mr. H. Butterworth, Director, Business Support, and other members of the licensee staff. The licensee acknowledged the issues presented;

• On November 17, 2016, the inspectors presented the inspection results of the Triennial Heat Sink Performance inspection to Mr. S. Northard, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented;

• On November 17, 2016, the inspectors presented the inspection results of the review of cyber security inspection enforcement discretion NCVs to Mr. S. Northard, Site Vice President, and other members of the licensee staff.

The licensee acknowledged the issues presented;

• On November 28, 2016, the inspectors presented the results of the inservice inspection (ISI) to Mr. S. Northard, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented;

• On December 2, 2016, the inspectors presented, by telephone, the inspection results of the Emergency Action Level and Emergency Plan Changes inspection to Mr. B. Carberry, Emergency Preparedness Manager. The licensee acknowledged the issues presented; and

• On December 2, 2016, the inspectors presented the results of the Radiation Monitoring Instrumentation and Radioactive Gaseous and Liquid Effluent Treatment inspection with Mr. J. Boesch, Maintenance Manager, 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. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as NCVs.

• Prairie Island Technical Specification 5.4.1, Procedures, required, in part, that written procedures shall be implemented covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Revision 2, Appendix A contains, in part under Section 1, Administrative Procedures, Subsection e., Procedure Review and Approval.

Contrary to the above, on December 12, 2013, and June 11, 2013, the licensee failed to properly implement FP-G-DOC-04, Procedure Processing, Revision 19, to ensure that validation reviews were performed to ensure usability of C18.1, Engineered Safeguards Equipment Support Systems, following revisions to the procedure. Specifically, validation reviews were not performed during procedure revisions of C18.1 which lead to inadequate instructions to ensure that SCWS-supported system operability was properly addressed when SCWS functions were affected. This led to seven instances of conditions prohibited by TS for safeguards buses 15 and 16 between January of 2013 and May of 2015. The licensee later determined that although conditions prohibited by TS did occur based on the inadequate C18.1 instructions, an equally correct application of TS would have been to enter a 30-day action statement for one SCWS inoperable per TS 3.7.11 and apply Surveillance Requirement 3.0.6 by performing a SFDP evaluation. This would not have resulted in conditions prohibited by TS for the supported AC or DC systems.

Because the inspectors answered No to all questions under Exhibit 2 of Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding screened as very low safety significance (Green). The above issue was documented in the licensees CAP as CAP 1488482. Corrective actions included changes to C18.1 to implement the SFDP for future SCWS removals from service, and revisions to the FP-G-DOC-04 job familiarization guide to ensure validation reviews are properly performed.

• Northern States Power CompanyMinnesota (NSPM), Prairie Island Nuclear Generating Plant Renewed Facility Operating License, Appendix B, Additional Conditions, Facility Operating License No. DPR-42 and DPR-60 (Amendment Nos. 206 and 193, respectively), required, in part, that The Alternate Source Term (AST) License Amendments 206/193 will be implemented after installation of the Unit 2 Replacement Steam Generators (RSGs) within 90 days after the completion of the outage in which the Unit 2 RSGs are installed. Further, implementation requirements incorporated within License Amendment 206/193 stated, in part, that prior to implementation of the AST license amendment, NSPM will revise the Prairie Island Nuclear Generating Plant design and licensing bases to indicate that the Steam Generator Water LevelNarrow Range Instruments are required to meet Regulatory Guide 1.97, Revision 2 requirements.

Contrary to the above, on March 27, 2014, the licensee failed to revise the Prairie Island Nuclear Generating Plant design and licensing bases to indicate that the SGNR instruments were required to meet Regulatory Guide 1.97, Revision 2 requirements.

Because the inspectors answered Yes to Question 1 under Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding screened as very low safety significance (Green).

The above issue was documented in the licensees CAP as CAP 1424460.

Corrective actions included replacement of the SGNR instrumentation with Regulatory Guide 1.97 compliant equipment.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Prairie Island Nuclear Generating Plant

S. Northard, Site Vice President

T. Conboy, Director of Site Operations

W. Paulhardt, Plant Manager

S. Sharp, Director of Performance Improvement

J. Bjorseth, Engineering Director

H. Butterworth, Business Support Manager

J. Boesch, Maintenance Manager

J. Kivi, Regulatory Affairs Manager

T. Borgen, Operations Manager

A. Chladil, Nuclear Oversight Manager

B. Boyer, Radiation Protection Manager

B. Carberry, Emergency Preparedness Manager

B. Truckenmiller, Chemistry & Environmental Manager

D. Lapcinski, Assistant Operations Manager

D. Feitl, Cyber Security Manager

P. Clay, Engineering Programs Manager

S. Martin, Human and Organizational Performance Manager

S. Lappegaard, Production Planning Manager

P. Johnson, Regulatory Affairs Analyst

E. Baker, Chemist

E. Boyer, Cyber Security

F. Collins, Senior Operations Instructor

F. Sienczak, Senior Licensing Engineer

G. Sherwood, Program Engineering CFAM

H. Sturgeon, Program Engineering Supervisor

J. Koenig, Component Cooling and Containment Vent System Engineer

B. Alkhas, Circulating Water, Condensers and Heat Removal System Engineer

J. Bergquist, Cyber Security

J. Hamilton, Cyber Change Manager

J. Hill, Manager Site Information Technology

J. Verbout, Information Technology Director, Xcel Corporate

L. Drenth, Principle Engineer

L. Jenson, Performance Improvement

M. Minard, GL 89-13 Program Engineer

P. Wildenborg, Health Physicist

R. Bader, Cooling Water System Engineer

S. Greenslit, Cyber Security

T. Downing, ISI Principle Engineer

U.S. Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

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

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000282/2016004-01; URI Baffle Former Bolting Acceptance Criteria

05000306/2016004-01 (Section 1R08.5)

05000282/2016004-02 NCV Failure to Properly Implement a Post-Maintenance Test Procedure during Safety Injection System Valve Testing (Section 1R13)

05000282/2016004-03; NCV Failure to Adequately Calibrate an Electrometer

05000306/2016004-03 (Section 2RS5.2)

Closed

05000282/2015005-00 LER Possible Misapplication of C18.1, Engineered Safeguards Equipment Support Systems (Section 4OA3.1)

05000282/2015005-01 LER Condition Prohibited by Technical Specifications (Section 4OA3.1)

05000282/2014003-04; URI Failure to Meet Alternate Source Term Amendment

05000306/2014003-04 Implementing Requirement (Section 4OA5.2)

05000282/2016005-00 LER 121 Motor Driven Cooling Water Pump Auto Start (Section 4OA3.2)

05000306/2015008-01 VIO Failure to Correct an NCV Associated with Inadequate Gas Monitoring of Inaccessible RHR Gas Susceptible Locations (Section 4OA5.1)

05000282/2016004-02 NCV Failure to Properly Implement a Post-Maintenance Test Procedure during Safety Injection System Valve Testing (Section 1R13)

05000282/2016004-03; NCV Failure to Adequately Calibrate an Electrometer

05000306/2016004-03 (Section 2RS5.2)

Discussed

None.