IR 05000282/2013005

IR 05000282-13-005, 05000306-13-005; 10/01/2013 - 12/31/2013; Prairie Island Nuclear Generating Plant, Units 1 and 2; Inservice Inspection, Operability Evaluations and Surveillance Testing

ML14043A247
Person / Time
Site:	Prairie Island
Issue date:	02/12/2014
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Davison K Northern States Power Co
References
IR-13-005
Download: ML14043A247 (51)

Text

February 12, 2014

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000282/2013005; 05000306/2013005

Dear Mr. Davison:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on January 16, 2014, with you and other members of your staff.

Two NRC-identified findings and one self-revealed finding of very low safety significance (Green) were identified during this inspection. Two of the findings were determined to involve violations of NRC requirements. A licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) in accordance with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the subject or severity of any NCV, 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 a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant.

In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant.

As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's Agencywide Documents Access and Management System (ADAMS),

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

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 05000282/2013005; 05000306/2013005 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report Nos: 05000282/2013005; 05000306/2013005 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, 2013 Inspectors: K. Stoedter, Senior Resident Inspector P. LaFlamme, Resident Inspector E. Sanchez-Santiago, Acting Resident Inspector J. Bozga, Reactor Engineer M. Jones, Reactor Engineer J. Laughlin, Emergency Preparedness Inspector D. Oliver, Reactor Engineer M. Phalen, Senior Health Physicist A. Shaikh, Reactor Engineer C. Tilton, Senior Reactor Engineer P. Voss, Resident Inspector - Monticello Approved by: K. Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000282/2013005, 05000306/2013005; 10/01/2013 - 12/31/2013;

Prairie Island Nuclear Generating Plant, Units 1 and 2; Inservice Inspection, Operability Evaluations and Surveillance Testing.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Three Green findings were identified by the inspectors. Two findings were considered non-cited violations (NCVs) of NRC regulations.

The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using IMC 0609, Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310,

Components Within the Cross Cutting Areas dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance on October 7, 2013, due to the failure to perform an adequate boric acid evaluation in accordance with Procedure H2, Boric Acid Corrosion Control Program. Specifically, the licensee failed to properly evaluate the impact of a boric acid leak following the leak coming into contact with carbon steel components on the 22 residual heat removal pump casing.

Corrective actions included moving a carbon steel bolt for visual inspection and completing a technically adequate boric acid corrosion evaluation.

The inspectors determined that this issue was more than minor because if left uncorrected the failure to complete technically adequate boric acid corrosion evaluations could result in components with questionable structural integrity being left in service. The inspectors determined that this issue was of very low safety significance because each of the questions provided in IMC 0609, Attachment 0609.04, Appendix A, Exhibit 2, were answered no. The inspectors concluded that this issue was cross-cutting in the Human Performance, Decision Making area because the licensee failed to use conservative assumptions while determining the applicability of a previously completed boric acid evaluation to a current plant condition. No violation was identified since all NRC requirements were met (H.1(b)). (Section 1R08)

Green.

The inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, on October 8, 2013, due to the failure to establish measures for the selection of parts that are essential to the safety-related functions of structures, systems, or components (SSCs). Specifically, the licensee failed to properly evaluate the specifications and quality of replacement parts such as gaskets, o-rings, packing materials, and diaphragms to ensure that these parts were suitable for installation in safety-related systems. As a result, multiple systems were required to be declared operable but non-conforming. Corrective actions for this issue included ensuring personnel understood the requirements regarding parts selection, determining the correct parts to be used and initiating work orders to ensure that parts were replaced in the future if required.

The inspectors determined that this issue was more than minor because if left uncorrected, the installation of parts/materials which failed to meet requirements could lead to subsequent part failure. This failure would adversely impact the ability of safety-related equipment to perform its safety function. The inspectors determined that this issue was of very low safety significance because Question 1 in IMC 0609, Attachment 0609.04,

Attachment A, Exhibit 2, was answered yes. The inspectors concluded that this issue was cross-cutting in the Human Performance, Resources area because the licensees parts specification and quality level documentation was not complete, accurate and/or up to date (H.2(c)). (Section 1R15.1)

Green.

A self-revealing finding of very low safety significance (Green) and an NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified on October 15, 2013, due to the failure to correct a condition adverse to quality. Specifically, the licensee failed to correct a D1 emergency diesel generator (EDG) lube oil cooler leak prior to the EDG being rendered inoperable. Corrective actions for this issue included reviewing the engineering departments equipment monitoring program, ensuring the lube oil cooler end bell was adequately torqued and repairing the lube oil cooler.

The inspectors determined that this issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The failure to correct the lube oil cooler leak resulted in the licensee accruing unplanned unavailability on the D1 EDG during this emergent repair. The inspectors determined that this issue was of very low safety significance because each of the questions provided in IMC 0609,

Attachment 0609.04, Appendix A, Exhibit 2, were answered no. The inspectors concluded that this issue was cross-cutting in the Problem Identification and Resolution,

Corrective Action Program (CAP) area because the licensee failed to thoroughly evaluate the condition of the leaking lube oil cooler to ensure that repairs were properly prioritized (P.1(c)). (Section 1R22.1)

Licensee-Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by the inspection. Corrective actions planned or taken by the licensee have been entered into the licensees CAP. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at full power for the entire inspection period. Small power reductions were performed as needed to allow the completion of routine testing.

Unit 2 remained shut down during the quarter to complete activities associated with Refueling Outage 2R28.

REACTOR SAFETY

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

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• D2 Emergency Diesel Generator (EDG);

• Cooling Water System; and

• 11 Turbine Driven Auxiliary Feedwater Pump.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report (USAR), Technical Specification (TS)requirements, outstanding work orders (WOs), corrective action 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 activities constituted three partial system walkdown samples as defined in Inspection Procedure (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 which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Fire Zone 6 - D2 EDG Room;

• Fire Zones 11, 43 and 50 - 4.16 kV and 480 V Bus Rooms on Unit 1;

• Fire Zone 82 - D1 EDG Room; and

• Fire Zone 88 - U2 Switchgear Room and Unit 2 Rod Drive Room.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the 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 licensees ability to respond to a security event.

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

b. Findings

No findings were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the USAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant area(s) to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• Safety-related cooling water pump rooms including 121 motor driven cooling water pump and the safeguards traveling screens.

Documents reviewed are listed in the Attachment to this report. This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees opening and inspecting of the Unit 2 residual heat removal heat exchangers to verify that the material condition was adequate to support its decay heat removal functions. The inspectors also observed the performance of eddy current testing to ensure the testing was appropriately performed.

If heat exchanger tube plugging was required, the inspectors reviewed the licensees heat exchanger performance analysis to ensure the actual number of plugged tubes was less than assumed in the analysis. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From October 1 through November 26, 2013, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the Unit 2 reactor coolant system (RCS), steam generator tubes, emergency feedwater systems, risk-significant piping and components, and containment systems.

The inservice inspections described in Sections 1R08.1 through 1R08.5 below constituted one inspection sample as defined in IP 71111.08.

.1 Piping Systems Inservice Inspections

a. Inspection Scope

The inspectors observed or reviewed records of the following non-destructive examinations (NDE) 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. If any indications and defects were detected, the inspectors observed activities and reviewed documentation to verify these indications and defects were dispositioned in accordance with the ASME Code or an NRC approved alternative requirement:

• Ultrasonic Examination on Residual Heat Removal (RHR) Head-to-Shell Weld W-1, Report No. 2013U009;

• Liquid Penetrant Examination on RHR Outlet Nozzle Weld N-2, Report No.

2013P002;

• Liquid Penetrant Examination on 22 RHR Suction Line 10-2SI-8, Report No.

BOP-PT-13-030;

• Visual Examination (VT-3) on Main Steam (MS) Double Snubber/Support, Component ID H-8, Report No. 2013V058;

• Visual Examination (VT-3) on MS Support, Component ID H-4, Report No.

2013V059;

• Radiographic Examination of Replacement Steam Generator (RSG) 21 Girth Weld, Report No. RT-NP8-024;

• Radiographic Examination of RSG 22 Girth Weld, Report No. RT-NP8-023;

• Magnetic Particle Examination of RSG 21 Girth Weld, Report No. MT-NP8-426;

• Magnetic Particle Examination of RSG 21 Girth Weld, Report No. MT-NP8-419;

• Radiographic Examination of RCS 21 Hot Leg Nozzle Safe End-to-Elbow Weld, Report RT-NP8-019;

• Radiographic Examination of RCS 21 Cold Leg Nozzle Safe End-to-Elbow Weld, Report RT-NP8-018;

• Radiographic Examination of RCS 22 Hot Leg Nozzle Safe End-to-Elbow Weld, Report No. RT-NP8-027;

• Radiographic Examination of RCS 22 Cold Leg Nozzle Safe End-to-Elbow Weld, Report No. RT-NP8-028;

• Liquid Penetrant Examination of RSG 22 Cold Leg inner diameter (ID), Report PT-NP8-093;

• Liquid Penetrant Examination of RSG 22 Hot Leg ID, Report PT-NP8-094;

• Liquid Penetrant Examination of RSG 22 Cold Leg outer diameter (OD), Report PT-NP8-099;

• Liquid Penetrant Examination of RSG 22 Hot Leg OD, Report PT-NP8-098;

• Liquid Penetrant Examination of RSG 21 Cold Leg ID, Report PT-NP8-089;

• Liquid Penetrant Examination of RSG 21 Hot Leg ID, Report PT-NP8-090;

• Liquid Penetrant Examination of RSG 21 Cold Leg OD, Report PT-NP8-103; and

• Liquid Penetrant Examination of RSG 21 Hot Leg OD, Report PT-NP8-104.

During the prior outage non-destructive surface and volumetric examinations, the licensee did not identify any relevant/recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors observed and/or reviewed records of the following pressure boundary welds completed for a risk significant systems during the Unit 2 refuelling outage to determine if the welding activities and any applicable NDE performed were completed in accordance with the ASME Code or NRC approved alternative.

• RSG 21 and 22 Girth Welds and RCS Hot and Cold Leg Safe End-to-Cast Austenitic Piping Elbow Welds; Document No.020781-02-PISGR-40IM-0001; Metrology, Machining, and Welding Plan; Revision 03; WOs 455954 and 455953.

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the Unit 2 reactor pressure vessel head, a bare metal visual (BMV) examination was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors observed the BMV examination conducted on the reactor vessel head and penetration nozzles to determine if the activities were conducted in accordance with the requirements of ASME Code Case (CC) N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D).

Specifically, the inspectors determined:

• If the required visual examination scope/coverage was achieved and limitations (if applicable) were recorded in accordance with licensee procedures;

• If the licensee criteria for visual examination quality and instructions for resolving interference and masking issues were adequate; and

• For indications of potential through-wall leakage, whether the licensee entered the condition into the CAP and implemented appropriate corrective actions.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control (BACC)

a. Inspection Scope

On September 20, 2013, the inspectors observed the licensee staff performing visual examinations of the RCS within containment to determine if these examinations focused on locations where boric acid leaks could cause degradation of safety significant components. Additionally, the inspectors conducted an independent Mode 3 containment as-found walkdown focusing on the identification of boric acid residue on plant structure, system, and component (SSCs).

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 component Construction Code, ASME Section XI Code, and/or an NRC approved alternative:

• BACC Evaluation No. 1110540; PINGP Form 1507 BACC Evaluation for Boric Acid Leak on 22 Residual Heat Removal Pump;

• BACC Evaluation No. 1364809; PINGP Form 1507 BACC Evaluation for Boric Acid Leak on SI-12-1;

• BACC Evaluation No. 1360095; PINGP Form 1507 BACC Evaluation for Boric Acid Seal Leak on 21 Containment Spray Pump;

• BACC Evaluation No. 1360091; PINGP Form 1507 BACC Evaluation for Boric Acid Seal Leak on 22 Containment Spray Pump;

• BACC Evaluation No. 1360100; PINGP Form 1507 BACC Evaluation for Boric Acid Leak at Flange Below 2CS-33-6; and

• BACC Evaluation No. 1359448; PINGP Form 1507 BACC Evaluation for Boric Acid Packing Leak on 2SI-14-2.

The inspectors reviewed the following corrective actions related to evidence of BA 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 1110540; 22 Residual Heat Removal Pump Boric Acid Leak;

• CAP 1364809; SI-12-1, 11 Accumulator Outlet Test Line Relief, Dripping Once per Six Seconds;

• CAP 1360095; Boric Acid Seal Leak on 21 Containment Spray Pump;

• CAP 1360091; Boric Acid Seal Leak on 22 Containment Spray Pump;

• CAP 1360100; Boric Acid Leak at Flange Below 2CS-33-6;

• CAP 1359448; Boric Acid Packing Leak on 2SI-14-2; and

• CAP 135607; Minor Packing Leak from 2VC-5-3, CHG Pump Discharge to Seal Injection.

b. Findings

Introduction:

An inspector-identified a finding of very low safety significance (Green)was identified on October 7, 2013, due to the failure to perform an adequate boric acid evaluation, in accordance with Procedure H2, Boric Acid Corrosion Control Program.

Specifically, the licensee failed to properly evaluate the impact of a boric acid leak in contact with the 22 RHR pump casing carbon steel components.

Description:

The licensees boric acid program was put in place to identify boric acid leaks within the plant. Often times, the licensee identified boric acid leaks while performing visual examinations of plant equipment. When leaks were identified, engineering personnel evaluated each one to make sure the leakage was not compromising the structural integrity of risk significant equipment. Some of the factors considered during the evaluation were component/equipment material, boric acid temperature, total time the component/equipment was in contact with the acid, component design, as well as others. Apart from performing an evaluation, the licensee could inspect the affected components for degradation. These inspections included items such as removing a bolt to visually verify the structural integrity and potential material loss due to corrosion.

During a walk down of the 22 RHR pump on October 7, 2013, the inspectors identified boric acid residue on the 22 RHR pump casing. Slight discoloration was also noted on the casing and associated bolts. The inspector reviewed the 22 RHR pump boric acid evaluation (completed in 2007 as CAP 1110540) and found that amount of boric acid considered in the evaluation was greater than the amount observed by the inspectors during their inspection. The inspectors also noted that the evaluation considered the carbon steel components present in the area. However, the inspectors were concerned that the evaluation failed to contain information regarding the specific corrosion rates or the potential material loss the carbon steel components were subjected to while they were in contact with the boric acid.

The inspectors reviewed Procedure H2, Boric Acid Corrosion Control Program, Revision 12. This procedure stated in part, that a corrosion evaluation shall be documented when the boric acid residue is wet or moist and/or the indication is in contact with an ASME Section XI bolted connection. The procedure also stated that if the boric acid affected ASME XI pressure boundary bolting, the leak would be considered relevant regardless of whether it was identified during an ASME Section XI pressure test. For relevant leaks affecting a bolted connection, the procedure stated that the bolts should be examined via a VT-3 visual examination or an evaluation should be performed. The evaluation was required to consider corrosion rates and mechanisms taking into account material susceptibility, surface temperature, leakage rates, boric acid concentration and potential for further concentration by evaporation or boiling.

The inspectors determined that the boric acid evaluation for the 22 RHR pump casing and bolted connections performed in 2007 failed to address the potential material wastage and corrosion rates the components were subject to. In addition, a VT-3 examination had not been performed. The boric acid leak identified in 2007 was described as wet with a concentration of 2000 parts per million and a temperature of 350 degrees Fahrenheit. Lastly, the leakage occurred over a two year timeframe. Taking these parameters into consideration, the potential corrosion rates could have exceeded 6 inches per year. Therefore, these corrosion rates should have been addressed in the evaluation. The evaluation also stated that there was no apparent discoloration on the components. However, the pictures provided as part of the evaluation showed evidence of discoloration. Based on the inspectors questions regarding this evaluation, the licensee determined that the evaluation performed in 2007 was inadequate and also noted that there were carbon steel components affected by this leak that were not identified. As a result, a valid and technically adequate boric acid evaluation for the 22 RHR pump did not exist. The licensee entered this issue into their corrective action program as CAP 1401850. The licensee also removed a bolt and performed a visual inspection to assess the boltings structural integrity. The results of this inspection concluded the boltings structural integrity was not impacted.

Analysis:

The inspectors determined that the failure to perform an evaluation of the corrosive effects of a boric acid leak on the carbon steel components of the 22 RHR pump, in accordance with Procedure H2, Boric Acid Corrosion Control Program, was a performance deficiency associated with the Mitigating Systems cornerstone. The inspectors determined that this issue was more than minor because if left uncorrected it had the potential to lead to a more significant safety concern. Specifically, by failing to perform a boric acid evaluation, the condition of the carbon steel components was unknown. Therefore, the structural integrity of these components could not be ascertained and further evaluations were necessary to ensure the 22 RHR pump was operable.

The inspectors used IMC 0609, Significance Determination Process, 0609.04, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. The inspectors determined that this finding was of very low safety significance (Green) because each of the screening questions was answered no. The inspectors concluded that this issue was cross-cutting in the Human Performance, Decision Making area because the licensee failed to use conservative assumptions while determining the applicability of a previously completed boric acid evaluation to a current plant condition (H.1(b)).

Enforcement:

This finding does not involve enforcement action because no violation of regulatory requirements was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as a finding (FIN 05000306/2013005-01: Failure to Evaluate Corrosive Effects of Boric Acid on the 22 RHR Pump).

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

During this refueling outage, both of the Unit 2 steam generators (SGs) were replaced.

As it is typically a part of this IP 71111.08 to perform a review of SG tube inspection activities, the pre-service eddy current examinations performed on these replacement steam generators were reviewed during this inspection.

The NRC inspectors observed the following activities and/or reviewed the following documentation and evaluated them against the licensees technical specifications, commitments made to the NRC, ASME Section XI, and Nuclear Energy Institute (NEI) 97-06 (Steam Generator Program Guidelines):

• Reviewed eddy current (ET) data summary report and samples of ET data;

• Reviewed the SG tube ET examination scope;

• Evaluated if the ET equipment and techniques used by the licensee to acquire data from the SG tubes were qualified or validated to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7; and

• Reviewed ET personnel qualifications.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI 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 related problems;

• the licensee had performed a root cause (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, Corrective Action requirements. Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On November 23, 2013, the inspectors observed a crew of licensed operators in the simulator during licensed operator training to verify 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

• the 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 licensed operator requalification program simulator sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On November 2, 2013, the inspectors observed the operators monitoring plant conditions and indications due to the 2RS transformer being out of service for planned maintenance. This was an activity that required heightened awareness or was related to increased risk because both safety-related 4.16 kV electrical buses were being powered from the same offsite electrical source. If this offsite electrical source malfunctioned during the planned maintenance activity, Unit 1 would have likely tripped due to the loss of electrical power and the EDGs would have started to supply electricity to risk significant equipment. 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.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

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:

• 2RS Transformer;

• 2RY Transformer;

• D1 EDG and D5 EDG; and

• Impairment of all onsite fire pumps.

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Operability Recommendation (OPR) 1266815, Revision 6 - Predicted Auxiliary Feedwater Pump Room Temperature Post-Accident;

• Various CAPs - Use of Non-Dedicated Consumable Parts in Safety-Related Equipment;

• Potential Unit 1 Main Steam Line Stress Analysis Issues due to Incomplete Calculations; and

• Incorrect Gasket Material Installed on Unit 1 Containment Fan Coils.

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 the 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 to this report.

This operability inspection constituted four samples as defined in IP 71111.15-05.

b. Findings

Introduction:

The inspectors identified finding of very low safety significance (Green)and an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, on October 8, 2013, for the failure to establish measures for the selection and review for suitability of application for parts that are essential to the safety-related functions of SSCs. Specifically, the licensee failed to evaluate the specifications and quality of replacement parts such as gaskets, o-rings, packing material, and diaphragms to ensure that these parts were suitable for installation in safety-related systems. As a result, multiple systems were required to be declared operable but non-conforming.

Description:

During the Unit 2 refueling outage the inspectors attended multiple meetings where the licensee discussed concerns regarding the reservation of non-safety related parts for installation in safety-related systems such as the auxiliary feedwater system and the EDGs. The inspectors were concerned about the issues discussed in the meetings because they appeared similar to information provided in CAP 1366595.

Specifically, on January 15, 2013, the licensee initiated CAP 1366595 to document that non-safety related gaskets could be installed throughout the plant based upon the discovery of non-safety related gaskets within the 12 diesel-driven cooling water pump (a safety-related pump).

The inspectors reviewed the information provided in CAP 1366595 and found that maintenance personnel frequently made gaskets for use in safety-related SSCs out of non-safety related shop stock material. This practice was based upon an evaluation written in 1989 which stated that gaskets used in safety-related SSCs could be non-safety related as long as they were not credited to perform a safety-related function.

Corrective actions for CAP 1366595 included reviewing the configuration of multiple safety-related SSCs to determine whether the failure of the non-safety related materials would result in the system being unable to perform its safety function(s). The inspectors noted that the system reviews were completed by May 29, 2013, and that multiple potential issues were identified. However, as of October 8, 2013, no actions had been taken to confirm if non-safety related parts/materials had been installed in safety-related SSCs. Due to the lack of action, the impact of having incorrect quality parts installed on safety-related SSCs was unknown.

The licensee initiated CAP 1400672 to document the lack of action discussed above.

Over the next two months the licensee reviewed approximately 3,000 WOs completed over the last three years on the safety systems listed below to determine whether these systems contained non-safety related materials/parts:

• Safety Injection;

• Residual Heat Removal;

• Cooling Water;

• Component Cooling Water;

• Containment Spray;

• EDGs;

• Auxiliary Feedwater; and

• Safeguards Chilled Water.

The inspectors reviewed procedures covering the selection of materials/parts and found that Procedure FP-WM-PLA-01, Work Order Planning Process, stated the following:

Replacement materials shall meet the specifications and codes equivalent to those specified for the original equipment and the quality level of the materials shall be equal to or higher than the quality level required unless otherwise evaluated by engineering.

Based upon the results of the review, the licensee identified 312 examples where incorrect information was used when selecting the required quality level of replacement materials/parts (non-safety related versus safety-related) prior to installation.

Additionally, the licensee identified 368 examples where the engineering evaluation provided within the WO either lacked appropriate detail to support installing the replacement material or was non-existent. Each example was documented in a CAP.

Operations personnel evaluated each example to determine whether the installation of the incorrect replacement material/part impacted the ability of the SSC to perform its safety function(s). In each case, operations personnel concluded that the specific SSC was able to perform its safety function(s) but the SSCs design no longer conformed to the original specifications. The inspectors reviewed a subset of the evaluations and had no concerns with the conclusions.

Analysis:

The inspectors determined that the failure to establish measures to ensure that the selection of and the review for suitability of parts that are essential to the safety-related functions of SSCs was appropriately performed was a performance deficiency. This issue was more than minor because if left uncorrected, the issue had the potential to lead to a more safety significant concern. Specifically, the installation of replacement parts/materials which failed to meet specifications and requirements could lead to subsequent replacement part failure and adversely impact the ability of safety-related equipment to perform its function.

The inspectors determined that the finding was associated with the Mitigating Systems cornerstone and could be evaluated using the SDP. The inspectors used IMC 0609, 0609.04, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, and concluded that this issue was of very low safety significance (Green) because the finding was associated with a deficiency that only affected the design or qualification of the specific SSCs. The inspectors determined that this issue was cross-cutting in the Human Performance, Resources area because the documentation regarding the required specifications and quality level for multiple replacement parts was not complete, accurate and/or up-to-date (H.2(c)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures be established for the selection and review for suitability of application of parts that are essential to the safety-related functions of SSCs. The licensee used Procedure FP-WM-PLA-01, Work Order Planning Process, to ensure that the selection and the review for suitability of application of parts that are essential to the safety-related functions of SSCs were performed prior to installing the part in a safety-related SSC.

Contrary to the above, as of October 8, 2013, measures had not been established for the selection and review for suitability of application for parts that are essential to the safety-related functions of SSCs. Specifically, the selection and review for suitability for parts essential to the safety-related functions of SSC failed to ensure that replacement materials/parts met the specifications equivalent to those specified for the original equipment, the quality level of the materials was equal to or higher than the quality level required, or that the replacement part was evaluated for suitability by engineering prior to installation as required by Procedure FP-WM-PLA-01.

Because this violation was of very low safety significance and it was entered into the corrective action program as CAP 1400672, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/

2013005-02; 05000306/2013005-02: Failure to Establish Appropriate Design Control Measures for Selection of Replacement Parts). Corrective actions for this issue included ensuring personnel understood parts selection requirements, determining the correct parts required to be installed in each case, and initiating WOs for those parts that needed replacement.

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 of the SSCs listed below:

• 21 Motor Driven Auxiliary Feedwater Pump following planned maintenance;

• D5 EDG following refueling outage maintenance;

• D1 EDG following repair of the lube oil cooler;

• Safety Injection Train B Pump Suction Motor Valve 32191;

• 21 Steam Generator hydrostatic test following replacement; and

• D6 EDG following refueling outage maintenance.

These activities were selected based upon the SSCs 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 PM 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.

This inspection constituted six post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors continued to review outage activities associated with Refueling Outage

2R28 which began on September 20, 2013. The inspectors observed portions of the

following processes and monitored the licensees controls over the following outage activities:

• configuration management, including maintenance of defense-in-depth for key safety functions and compliance with the applicable TS 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 TS 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;

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

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

• walkdown of the containment to verify that debris had not been left which could block emergency core cooling system suction strainers; and

• identification and resolution of problems related to refueling outage activities.

Documents reviewed are listed in the Attachment to this report.

This inspection was not counted as an inspection sample as the refueling outage was not complete at the conclusion of the inspection period.

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 1089A - Train A Residual Heat Removal Pump and Suction Valve From the Refueling Water Storage Tank Quarterly Test (Inservice Test);

• SP 1093 - D1 Diesel Generator Monthly Slow Start Test (Routine);

• SP 1112 - Steam Exclusion Monthly Damper Test (Routine);

• SP 2083 A and B - Unit 2 Integrated Safety Injection Test with a Simulated Loss of Offsite Power (Routine); and

• SP 2088B - Train B Safety Injection Quarterly Test (Routine).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

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

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

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

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

• measuring and test equipment calibration was current;

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

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

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

• test equipment was removed after testing;

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

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

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

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

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

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

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted four routine surveillance testing sample(s), one inservice testing sample, as defined in IP 71111.22, Sections -02 and -05.

b. Findings

Introduction:

A self-revealing finding of very low safety significance (Green) and an NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified on October 15, 2013, for the failure to correct a condition adverse to quality.

Specifically, the licensee failed to correct a lube oil cooler leak on the D1 EDG prior to declaring the EDG inoperable.

Description:

On October 15, 2013, the licensee performed a scheduled monthly surveillance on the D1 EDG. Immediately after the EDG was started, several streams of EDG lube oil mixed with water began leaking from the end bell of the lube oil cooler.

The inspectors observed the actual leak while the EDG was running. In addition, the inspectors observed operations personnel attempt to capture the leakage by using a container filled with absorbent material and various rags. The shift manager present in the D1 EDG room directed that the EDG be shut down and declared inoperable due to the excessive leakage from the lube oil cooler. Subsequent troubleshooting determined that the leakage was caused by improper installation of the lube oil cooler flange and incorrect torqueing of the lube oil cooler flange fasteners.

The inspectors questioned operations personnel present in the D1 EDG room and determined that the lube oil cooler leakage had been identified on February 12, 2013.

The inspectors noted that the licensee had initiated CAP 1369867 to document the leak.

Information provided within the CAP included that the cooler was leaking approximately one drop every 15 minutes. The CAP was subsequently closed to Work Request (WR) 88344.

On August 12, 2013, operations personnel initiated CAP 1393216 to document that the D1 EDG lube oil cooler had leaked during a scheduled surveillance test. The CAP initiator stated that the leak started as a small steady pencil stream of oil and then decreased to a rate of one drop per minute as temperatures increased and stabilized.

This CAP was closed to WR 88344. Four days later, the Nuclear Oversight Department (NOS) initiated CAP 1393717 to document that the operability determination provided in CAP 1393216 was inadequate. Specifically NOS found that information had not been provided to ensure that the onsite EDG lube oil inventory was adequate to support the EDGs operability for the required mission time. In response to this issue, engineering was requested to determine the D1 EDG lube oil coolers rate of degradation. This action was assigned a due date of September 10, 2013. The due date was subsequently changed to November 29, 2013, due to the belief that the risk associated with moving the date was low.

Based upon the information discussed above, the inspectors determined that the licensee had identified a condition adverse to quality associated with the leaking D1 EDG lube oil cooler on February 12, 2013. However, no actions were taken to correct the condition prior to the D1 EDG being declared inoperable and unavailable following surveillance testing performed on October 15, 2013.

Analysis:

The inspectors determined that the failure to correct a condition adverse to quality on the D1 EDG was a performance deficiency that could be evaluated using the SDP. The inspectors determined that this issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone. In addition, the finding impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct the D1 EDG lube oil leak resulted in the licensee accruing unplanned unavailability on the D1 EDG due having to repair the lube oil cooler on an emergent basis.

The inspectors determined that this issue impacted the Mitigating Systems cornerstone.

The inspectors utilized IMC 0609, Significance Determination Process, 0609.04, Appendix A, Exhibit 2, dated June 19, 2012, and concluded that this finding was of very low safety significance (Green) because each of the screening questions was answered no. The inspectors determined that this issue was cross cutting in the Problem Identification and Resolution, CAP area because the licensee failed to thoroughly evaluate the condition of the leaking lube oil cooler to ensure the repairs were properly prioritized (P.1(c)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, requires, in part, that conditions adverse to quality, such as deficiencies and non-conformances, are promptly identified and corrected.

Contrary to the above, between February 12 and October 15, 2013, the licensee failed to promptly correct a condition adverse to quality. Specifically, during a February 12, 2013, D1 EDG surveillance test operations personnel identified that the lube oil cooler was leaking. However, the licensee did not promptly correct the leak until the shift manager ordered an immediate shut down of the D1 EDG due to excessive lube oil cooler leakage on October 15, 2013.

Because this violation was of very low safety significance, and it was entered into the licensees corrective action program as CAP 1401848, it is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/

2013005-03: Failure to Promptly Correct Condition Adverse to Quality on D1 EDG). Corrective actions for this issue included a review of the equipment monitoring program, ensuring lube oil cooler end bell torque values were appropriately reflected in plant documents, and repairing the lube oil cooler.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The Office of Nuclear Security and Incident Response headquarters staff performed an in-office review of the latest revisions to the Emergency Plan and various Emergency Plan Implementing Procedures (EPIP) located under ADAMS Accession Numbers ML13017A071, ML123630278, and ML13214A373.

The licensee transmitted the EPIP revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection.

Documents reviewed are listed in the Attachment to this report.

This emergency action level and emergency plan changes inspection constituted one sample as defined in IP 71114.04-05.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

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

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators (PIs) for the Occupational Exposure Cornerstone for follow-up. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors determined if there had been changes to plant operations since the last inspection that may have resulted in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee assessed the potential impact of these changes and had 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 was 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 to verify conditions.

The inspectors selected the following radiologically risk-significant work activities that involved exposure to radiation:

• Eddy Current Testing 21 and 22 RHR Heat Exchangers;

• Spent Fuel Pool Transfer Canal Repairs and Inspections;

• Cutting and Welding Activities Outside of RCS Piping; and

• Replace 21 and 22 Reactor Coolant Pump (RCP) Seal with FLOWSERVE N-9000 Seal.

For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

• identification of hot particles;

• the presence of alpha emitters;

• the potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials (This evaluation may include licensee planned entry into non-routinely entered areas subject to previous contamination from failed fuel);

• the hazards associated with work activities that could suddenly and severely increase radiological conditions and that the licensee has established a means to inform workers of changes that could significantly impact their occupational dose; and

• severe radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors observed work in potential airborne areas and evaluated whether the air samples were representative of the breathing air zone. The inspectors evaluated whether continuous air monitors were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspectors evaluated the licensees program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected various containers holding non-exempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether the containers were labeled and controlled in accordance with 10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g), Exemptions To Labeling Requirements.

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

• Eddy Current Testing 21 and 22 RHR Heat Exchangers;

• Spent Fuel Pool Transfer Canal Repairs and Inspections;

• Cutting and Welding Activities Outside of RCS Piping; and

• Replace 21 and 22 RCP Seal with FLOWSERVE N-9000 Seal.

For these RWPs, the inspectors assessed whether allowable stay times or permissible dose (including from the intake of radioactive material) for radiologically significant work under each RWP were clearly identified. The inspectors evaluated whether electronic personal dosimeter (EPD) alarm set-points were in conformance with survey indications and plant policy.

The inspectors reviewed selected occurrences where a workers EPD noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the CAP and dose evaluations were conducted as appropriate.

For work activities that could suddenly and severely increase radiological conditions, the inspectors assessed the licensees means to inform workers of changes that could significantly impact their occupational dose.

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated material leaving the radiological control area (RCA) and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use and evaluated whether the work was performed in accordance with plant procedures and whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.

The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was guidance on how to respond to an alarm that indicates the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters. The inspectors assessed whether or not the licensee has established a de facto release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high-radiation background area.

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 evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) 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 (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of EPDs 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 is properly employed an NRC-approved method of determining effective dose equivalent.

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

The inspectors reviewed the following RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures:

• RWP 407277; Eddy Current Testing 21 and 22 RHR Heat Exchangers;

• RWP 455878; Spent Fuel Pool Transfer Canal Repairs and Inspections;

• RWP 455953; Cutting and Welding Activities Outside of RCS Piping; and

• RWP 476259; Replace 21 and 22 RCP Seal with FLOWSERVE N-9000 Seal.

For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high-efficiency particulate air ventilation system operation.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools. The inspectors assessed whether appropriate controls (i.e., administrative and physical controls) were in place to preclude inadvertent removal of these materials from the pool.

The inspectors examined the posting and physical controls for selected HRAs and very high radiation areas (VHRAs) to verify conformance with the occupational PI.

b. Findings

No findings were identified.

.6 Risk Significant High Radiation Area and Very-High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors discussed the controls and procedures for high-risk HRAs and VHRAs with the radiation protection manager. The inspectors discussed methods employed by the licensee to provide stricter control of VHRA access as specified in 10 CFR 20.1602, Control of Access to Very-High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and Very-High Radiation Areas of Nuclear Plants. The inspectors assessed whether any changes to licensee procedures substantially reduced the effectiveness and level of worker protection.

The inspectors discussed the controls in place for special areas that have the potential to become VHRAs during certain plant operations with first-line health physics (HP)supervisors (or equivalent positions having backshift HP oversight authority). The inspectors assessed whether these plant operations require communication beforehand with the HP group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including re-access authorization.

The inspectors evaluated licensee controls for VHRAs and areas with the potential to become VHRAs to ensure that an individual was not able to gain unauthorized access to the VHRA.

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors assessed whether workers were aware of the significant radiological conditions in their workplace and the RWP controls/limits in place and whether their performance reflects the level of radiological hazards present.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed with the RPM any problems with the corrective actions planned or taken.

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all radiation protection work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the RWP controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be radiation protection technician error. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

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

The inspectors assessed the licensees process for applying operating experience to their plant.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Leakage performance indicator for Units 1 and 2 for the period from the fourth quarter of 2012 through the third quarter of 2013. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator logs, RCS leakage tracking data, CAPs, event reports and NRC Integrated Inspection Reports for the period discussed above to validate the accuracy of the submittals. The inspectors also reviewed the licensees corrective action 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.

This inspection constituted two reactor coolant system leakage samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

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

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to 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 and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Semi-Annual 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 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July through December 2013 although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal 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 CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection: Review of Licensees Response to Operating

Experience Regarding Adequacy of Reactor Vessel Head Laydown Area

a. Inspection Scope

The inspectors performed a review to assess the adequacy of the concrete structure inside containment that was used to support the placement of the reactor vessel head during refueling outages. The inspectors reviewed the USAR Section 12 to determine the structural code of record (American Concrete Institute 318-63) for the concrete structure inside containment at Elevation 711'-6". The inspectors also reviewed the licensees classification for the load due to the placement of the reactor pressure vessel head during the refueling outage being considered a live load. The inspectors reviewed the design calculations for the concrete structure inside containment at Elevation 711'-6" which used the weight of the reactor vessel during initial construction of the plant for the design of the structural members. Based upon this, the inspectors concluded that the supports were adequate to support the weight of the reactor vessel head. The inspectors reviewed the location of decay heat removal systems and their location with respect to the location of the reactor pressure vessel head during the refueling outage to ensure that the integrity of the heat removal systems would not be challenged if a seismic event were to occur while the reactor vessel head was within the laydown area.

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

b. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report (LER) 05000282/2013-001-00: Control Room Envelope

Inoperable On August 9, 2013, the licensee identified that the control room envelope was inoperable due to unacceptable preconditioning during a previously performed surveillance test. The inspectors validated that the licensee immediately implemented mitigating actions as required by TS, and that the actions were appropriate to protect personnel. The inspectors reviewed the actions taken to restore the control room envelope to an operable status including the installation of temporary modification to reduce control room in-leakage and all subsequent system testing. The inspectors verified that the as-left control room in-leakage test results met the specified acceptance criteria and that the criteria were based upon USAR requirements. The enforcement actions associated with the control room envelope being inoperable for a time longer than allowed by TS is discussed in Section 4OA7 of this inspection report. Documents reviewed are listed in the Attachment to this report. This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

.2 Unanticipated RCS Level Indications during Unit 2 Refueling Outage

a. Inspection Scope

The inspectors observed activities in the control room following operations personnel identifying an unexpected change in RCS level during the refueling outage. The inspectors verified that the operators performed activities as directed by procedures, that the need for an emergency action level classification was considered and appropriately dispositioned, and that all reactor parameters were stabilized immediately following the abnormal indications. The inspectors also reviewed information contained in the corrective action system since a similar event had occurred during previous refueling outages. The inspectors reviewed this information to determine whether the licensees previous corrective actions were effective in addressing past problems. The inspectors determined that the small unexpected RCS level decrease was due to actual reactor head vent piping configuration rather than personnel error. Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Unit 2 Steam Generator Replacement Project

a. Inspection Scope

The inspectors assessed steam generator replacement radiological hazard assessment, radiological exposure controls, and radiological work planning and work execution by performing selective inspections, consistent with the safety significance and inspection resources, utilizing applicable portions of the baseline IP 71124.01 and 71124.02 as guidance. Specifically, the inspectors reviewed on-site steam generator work for:

• Radiological hazard assessment and exposure controls;

• Instructions to radiation workers;

• Contamination and radioactive material control;

• Radiological hazards control and work coverage;

• Risk-Significant High Radiation Area and Very High Radiation Area Controls;

• Radiation worker performance;

• Radiation protection technician proficiency;

• ALARA planning;

• Dose estimates and dose tracking;

• Exposure controls including temporary shielding;

• Contamination controls;

• Radioactive material management;

• Radiological work plans and controls; and

• Airborne radioactivity effluent controls.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 16, 2014, the inspectors presented the inspection results to Mr. K. Davison 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 inspection results for the area of Refueling Outage Containment Integrity Control Program and radiological hazard assessment and exposure controls with Mr. K. Davison, Site Vice President, on November 22, 2013.

• The results of the inservice inspection with Mr. R. Calia on November 26, 2013.

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 or destroyed.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) or Severity Level IV was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

• Technical Specification 3.7.10 requires that two trains of the control room special ventilation system (CRSVS) must be operable when the reactor is operating in Modes 1 through 4 or during the movement of irradiated fuel assemblies.

Contrary to the above, the licensee identified on August 9, 2013, that one or more CRSVS trains had been inoperable since December 10, 2010, due to the failure to properly perform control room envelope unfiltered air in-leakage testing as required by TS Surveillance Requirement 3.7.10.5.

The inspectors determined that this issue was more than minor because it was associated with the Barrier Integrity cornerstones attribute of barrier performance and affected the cornerstones objective of maintaining the barrier functional integrity of the Control Room. Specifically, the licensee failed to ensure that the measured control room envelope unfiltered air in-leakage remained less than or equal to the in-leakage rate assumed in the accident analysis. As a result, the licensee was not able to demonstrate that operations personnel located within the control room would have been adequately protected from the radiological consequences of a design basis accident.

In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Table 2, the inspectors determined the finding affected the Barrier Integrity cornerstone. As a result, the inspectors determined the finding could be evaluated using Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 3 for the Barrier Integrity cornerstone. For the control room envelope (CRE) finding, Section C of Exhibit 3 was applicable. The inspectors answered no to the first screening question and yes to the second screening question. As a result, a detailed risk evaluation was required to be performed by a Senior Reactor Analyst (SRA). The exposure time of the finding was assumed to be the maximum of one year.

To evaluate the effects of the degradation of the CRE against a toxic atmosphere, the SRA determined that there was no delta risk from toxic gas events. The outside air damper which was identified to be leakage during subsequent testing did not auto-close and was not intended to preclude toxic gas from entering the Control Room from a design basis perspective.

To evaluate the effects of the degradation of the CRE against smoke, the SRA identified that the Electric Power Research Institute (EPRI) Fire Probabilistic Risk Assessment Implementation Guide (report number EPRI TR-105928), Appendix B, stated that while actions performed from the control room should generally be unaffected by a fire outside the control room, a January 1989 event at an eastern nuclear plant indicated that fires outside the control room may increase the stress on the operators if smoke reaches the control room. In addition, NUREG/CR-6883, The SPAR-H Human Reliability Method, indicated that physical stress (such as that imposed by difficult environmental factors)may increase the stress and impede the operator from easily completing a task. Based on this, the SRA conservatively assumed that with the degradation of the CRE, any fire in the plant would result in smoke entering the control room and represent a risk increase due to the performance deficiency with the following exceptions:

• A fire initiated in the control room (since a fire in the control room would not represent additional risk given the performance deficiency); and

• A fire in containment (since smoke from a fire in containment would not reach the control room).

This evaluation was considered bounding because of the tortuous path that would be required for smoke from a fire in the plant to enter the CRE through the leaking outside air damper.

The delta risk due for the finding was attributed to high stress on the control room operators (e.g., the control room operators may need to wear self-contained breathing apparatus (SCBAs)). Using SPAR-H, a Performance Shaping Factor (PSF) with a multiplier of "2" was used due to High Stress while performing the affected control room actions.

From the Prairie Island IPEEE, Appendix B, Revision 2, Internal Fires Analysis, the core damage frequency (CDF) for fires was spread across five accident classes:

• (TEH) - early core melt with the reactor at high pressure;

• (TLH) - late core melt with the reactor at high pressure;

• (SEH) - early core melt with the reactor at high pressure in conjunction with a small loss-of-coolant-accident (SLOCA);

• (SLH) - late core melt with the reactor at high pressure in conjunction with a SLOCA; and

• (BEH) - early core melt with the reactor at high pressure in conjunction with a station blackout.

In the Prairie Island IPEEE, Appendix B, Attachment 8, Fire PRA Dominant Cutsets, the dominant cutsets for each of the five accident classes is given. The SRA's evaluation of the CDF associated with the finding for each of the five accident classes is provided below:

Accident class TEH - of the top 100 cutsets for this accident class, cutsets 12, 58, 80, and 85 were found to contribute to a CDF associated with the finding. The CDF associated with this accident class was evaluated to be 8.8E-8/yr due to high stress.

Accident class SEH - of the top 100 cutsets for this accident class, cutset 93 was found to contribute to a CDF associated with the finding. The CDF associated with this accident class was evaluated to be 7.1E-9/yr due to high stress.

Accident class TLH - of the top 100 cutsets for this accident class, cutsets 17 and 70 were found to contribute to a CDF associated with the finding. The CDF associated with this accident class was evaluated to be 5.9E-9/yr due to high stress.

Accident class BEH - involves fires that cause a loss-of-offsite-power (LOOP). In the IPEEE, Appendix B, Revision 2, it states that only one fire was determined to lead to a LOOP and involved a large fire in the control room G control panel. Since a control room fire does not represent a CDF associated with the finding, accident class BEH was eliminated from further consideration.

Accident class SLH - of the top 100 cutsets for this accident class, 98 were associated with control room fires. The other two fires (cutsets 85 and 86 on the list of 100)involved relay room fires that did not contribute to the CDF associated with the finding because these cutsets did not contain basic events involving operator actions.

The total CDF associated with the effects of the degradation of the CRE against smoke is the sum of the CDF for each of the five accident classes or 1.0E-7/yr. Taking into account the exposure time of the finding, the CDF associated with the effects of the degradation of the CRE against smoke was 1.0E-7/yr.

Since the total estimated change in core damage frequency was greater than or equal to 1.0E-7/yr, the potential risk contribution from large early release frequency (LERF) was evaluated for risk significance. Appendix H, to IMC 0609, Containment Integrity Significance Determination Process was used to determine the potential risk contribution due to LERF. Prairie Island is a 2-loop Westinghouse Pressurized Water Reactor (PWR) with a large dry containment. Sequences important to LERF include steam generator tube rupture events and inter-system loss-of-coolant-accident events.

These were not the dominant core damage sequences for this finding.

Based on the Detailed Risk Evaluation, the Senior Reactor Analysts determined that the finding was of very low safety significance (Green).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Davison, Site Vice President

J. Hallenbeck, Site Engineering Director

S. Sharp, Plant Manager

T. Allen, Assistant Plant Manager

J. Anderson, Regulatory Affairs Manager

E. Baker, Plant Chemist

J. Boesch, Maintenance Manager

T. Borgen, Training Manager

B. Boyer, Radiation Protection Manager

H. Butterworth, Nuclear Oversight Manager

F. Calia, Business Support Manager

K. DeFusco, Emergency Preparedness Manager

T. Downing, Site ISI Program

D. Gauger, Chemistry/Environmental Manager

J. Hamilton, Security Manager

S. Lappegaard, Production Planning Manager

B. Meek, Safety and Human Performance Manager

K. Peterson, Business Support Manager

J. Ruttar, Operations Manager

D. Vincent, Regulatory Assurance

P. Wildenborg, Radiation Protection Health Physicist

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

S. Wall, Project Mananger, Office of Nuclear Reactor Regulation

Attachment

LIST OF ITEMS

Opened

05000306/2013005-01 FIN Failure to Evaluate Corrosive Effects of Boric Acid on the Residual Heat Removal Pump (1R08)

05000282/2013005-02 NCV Failure to Establish Appropriate Design Control Measures

05000306/2013005-02 for Selection of Replacement Parts (1R15)

05000282/2013005-03 NCV Failure to Promptly Correct Condition Adverse to Quality on D1 EDG (1R22)

Closed

05000306/2013005-01 FIN Failure to Evaluate Corrosive Effects of Boric Acid on the Residual Heat Removal Pump (1R08)

05000282/2013005-02 NCV Failure to Establish Appropriate Design Control Measures

05000306/2013005-02 for Selection of Replacement Parts (1R15)

05000282/2013005-03 NCV Failure to Promptly Correct Condition Adverse to Quality on D1 EDG (1R22)

05000282/2013-001-00 LER Control Room Envelope Inoperable (4OA3)

Discussed

None