IR 05000338/2011004

IR 05000338-11-004, 05000339-11-004, 05000338-11-501, 05000339-11-501, on 07/01/2011 - 09/30/2011; North Anna Power Station, Units 1 and 2; Other Activities

ML113130400
Person / Time
Site:	North Anna
Issue date:	11/09/2011
From:	Gerald Mccoy NRC/RGN-II/DRP/RPB5
To:	Heacock D Virginia Electric & Power Co (VEPCO)
References
IR-11-004, IR-11-501
Download: ML113130400 (61)

Text

November 9, 2011

SUBJECT:

NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000338/2011004, 05000339/2011004, 05000338/2011501, 05000339/2011501

Dear Mr. Heacock:

On September 30, 2011, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your North Anna Power Station Units 1 and 2. The enclosed integrated inspection report documents the inspection findings which were discussed on October 28, 2011, with Mr.

Larry Lane and other members of your staff.

The inspection examined activities conducted under your licenses as they related to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one self-revealing finding of very low safety significance (Green) which was determined to be a violation of NRC requirements. However, because of the very low safety significance of this issue and because it was entered into your corrective action program, the NRC is treating this as finding consistent with Section 2.3.2.a of the NRC Enforcement Policy. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in the report. If you wish to contest these findings, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the North Anna Power Station.

Additionally, if you disagree with the characterization of 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 II, and the NRC Resident Inspector at the North Anna Power Station.

VEPCO

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gerald J. McCoy, Chief

Reactor Projects Branch 5

Division of Reactor Projects

Docket Nos.: 50-338, 50-339 License Nos.: NPF-4, NPF-7

Enclosure:

Inspection Report 05000338/2011004, 05000339/2011004, 05000338/2011501, 05000339/2011501

w/ Attachment: Supplemental Information

REGION II==

Docket Nos.:

50-338, 50-339

License Nos.:

NPF-4, NPF-7

Report No.:

05000338/2011004, 05000339/2011004, 05000338/2011501, 05000339/2011501

Licensee:

Virginia Electric and Power Company (VEPCO)

Facility:

North Anna Power Station, Units 1 & 2

Location:

1022 Haley Drive Mineral, Virginia 23117

Dates:

July 1, 2011 through September 30, 2011

Inspectors:

G. Kolcum, Senior Resident Inspector

J. Reece, Senior Resident Inspector

R. Clagg, Resident Inspector

S. Sandal, Senior Reactor Inspector, Section 1R17

D. Mas, Reactor Inspector, Section 1R17

A. Alen, Reactor Inspector, Section 1R17

A. Sengupta, Reactor Inspector, Section 1R17

A. Nielsen, Senior Health Physicist, Section 2RS8

R. Hamilton, Senior Health Physicist, Sections 2RS1, 2RS4, 2RS6, 2RS7,

4OA1, 4OA5

M. Speck, Senior Emergency Preparedness Inspection, Sections 1EP2,

1EP3, 1EP4, 1EP5, 4OA1

R. Carrion, Senior Reactor Inspector, Section 1R08

C. Fletcher, Senior Reactor Inspector, Section 1R08

M. Cain, Senior Resident Inspector, Section 4OA5

G. MacDonald, Senior Reactor Analyst, Sections 4OA5, 4OA7

Accompanied By:

R. Kellner, Health Physicist, Section 2RS6 (Training)

W. Pursley, Health Physicist, Sections 2RS7, 4OA1 (Training)

M. Yoo, Nuclear Safety Professional Development Program (Training)

Approved by:

Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000338/2011-004, 05000339/2011-004, 05000338/2011-501, 05000339/2011-501, 07/01/2011 - 09/30/2011; North Anna Power Station, Units 1 and 2; Other Activities.

The report covered a 3-month period of inspection by resident inspectors, senior health physicists, health physicists, senior reactor inspectors, senior emergency preparedness inspectors, and reactor inspectors from the region. One self-revealing finding was identified.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified for the failure to take adequate corrective action for degradation of annunciator card resistors in accordance with the standards as established by the licensees corrective action program procedure which resulted in a fire in the respective annunciator cabinet located in the Units 1 and 2 control room complex. The licensee entered the problem into their corrective action program as condition report 412487.

The finding was more than minor because it could be reasonably viewed as a precursor to a significant event based on fire development leading to an evacuation of the control room. The finding was screened using phase 1 of the SDP and was determined to be a fire initiator contributor within the initiating events cornerstone and required a phase 3 fire SDP risk assessment in as it represented a fire within the main control room (MCR). A regional SRA performed an SDP phase 3 fire risk assessment for this finding in accordance with NRC Inspection Manual Chapter (IMC) 0609 Appendix F, NUREG/CR 6850 and NUREG/CR 6850 supplement 1..

The SDP phase 3 risk evaluation determined that the risk of the finding was an increase in core damage frequency of <1E-6/year, a Green finding of very low safety significance. The inspectors determined there were no cross-cutting aspects because the performance deficiency was not representative of current licensee performance. (Section 4OA5.4)

Licensee Identified Violations

A violation of very low safety significance was identified by the licensee and reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and its respective corrective actions are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at full Rated Thermal Power (RTP) and operated at full power until August 23, 2011, when the unit experienced a forced outage due to a seismic event.

Unit 2 began the period at full RTP and operated at full power until August 23, 2011, when the unit experienced a forced outage due to a seismic event. A planned refueling outage, initially planned for September 25, 2011, began on August 26,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

a. Inspection Scope

==

The inspectors assessed the external flood vulnerability of the Unit 1 and Unit 2 Safeguards and Quench Spray buildings, associated pump cubicles and piping tunnels at the North Anna site due to the seasonal heavy rains and hurricanes. The inspectors verified that removable ceiling-mounted equipment hatch plugs were properly sealed or covered to address possible water in-leakage and flooding of safety-related components.

Building and cubicle sump pump maintenance history were reviewed to verify that pumps were fully functional and available. The inspectors also reviewed applicable station procedures and design documents to assess proper surveillance and maintenance for external flood protection features.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

a. Inspection Scope

==

The inspectors conducted two equipment alignment partial walkdowns to evaluate the operability of selected redundant trains or backup systems, listed below, with the other train or system inoperable or out of service. The inspectors reviewed the functional systems descriptions, Updated Final Safety Analysis Report (UFSAR), system operating procedures, and Technical Specifications (TS) to determine correct system lineups for the current plant conditions. The inspectors performed walkdowns of the systems to verify that critical components were properly aligned and to identify any discrepancies which could affect operability of the redundant train or backup system. Documents reviewed are listed in the Attachment to this report.

• Unit 1 Charging Pumps 1A and 1C during 3 year preventative maintenance on 1B Charging Pump

• Unit 2 2H and 2J Emergency Diesel Generators (EDGs) during opposite EDG unavailability for maintenance

b. Findings

No findings were identified

==1R05 Fire Protection

==

.1 Fire Protection - Tours

a. Inspection Scope

The inspectors conducted focus tours of the five areas listed below that are important to reactor safety to verify the licensees implementation of fire protection requirements as described in fleet procedures CM-AA-FPA-100, Revision 4, Fire Protection/Appendix R (Fire Safe Shutdown) Program, CM-AA-FPA-101, Control of Combustible and Flammable Materials, Revision 3, and CM-AA-FPA-102, Fire Protection and Fire Safe Shutdown Review and Preparation Process and Design Change Process, Revision 2 The inspectors evaluated, as appropriate, conditions related to:

(1) licensee control of transient combustibles and ignition sources;

(2) the material condition, operational status, and operational lineup of fire protection systems, equipment, and features; and

(3) the fire barriers used to prevent fire damage or fire propagation.

• Main Control Room (fire zone 2a / CR)

• EDG 1H Unit 1 (fire zone 9A-1a / EDG-1H) and EDG 2H Unit 2 (fire zone 9A-2a /

EDG-2H)

• EDG 1J Unit 1 (fire zone 9B-1a / EDG-1J) and EDG 2J Unit 2 (fire zone 9B-2a /

EDG-2J)

• Auxiliary Building (fire zone 11a / AB)

• Emergency Switch Gear Room Unit 1 (fire zone 6-1a / ESR-1)

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

During a fire protection drill on September 7, 2011, for a vehicle fire adjacent to refueling outage work trailers in the southeast corner of the protected area, the inspectors assessed the timeliness of the fire brigade in arriving at the scene, the firefighting equipment brought to the scene, the donning of fire protection clothing, the effectiveness of communications, and the exercise of command and control by the scene leader. The inspectors also assessed the acceptance criteria for the drill objectives and reviewed the licensees corrective action program for recent fire protection issues. Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified.

==1R07 Heat Sink Performance

a. Inspection Scope

==

The inspectors selected the risk significant Unit 1 1B Component Cooling heat exchanger and reviewed inspection records, test results, maintenance work orders, and other documentation to ensure that deficiencies which could mask or degrade performance were identified and corrected. The test procedures and records were also reviewed to verify that they were consistent with Generic Letter 89-13 licensee commitments, and Electric Power Research Institute Heat Exchanger Performance Monitoring Guidelines. In addition, the inspectors reviewed inspection documentation of the related service water piping to assess general material condition and to identify any degraded conditions. Documents reviewed included Virginia Power Administrative Procedure (VPAP) -0811, Service Water Inspection and Maintenance Program, Revision 6, and Procedure ER-AA-HTX-1003, Heat Exchanger Monitoring and Assessment, Revision 5. Other documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified.

==1R08 Inservice Inspection (ISI) Activities (IP 71111.08P, Units 1 and 2)

a. Inspection Scope

==

Non-Destructive Examination Activities and Welding Activities: From September 12, 2011, through September 30, 2011, the inspectors conducted an on-site review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, emergency feedwater systems, risk-significant piping and components, and containment systems in Unit 2. The inspectors activities included a review of non-destructive examinations (NDEs) to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 2004 Edition with no Addenda), and to verify that indications and defects (if present) were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI, acceptance standards.

The inspectors directly observed the ultrasonic testing (UT) of the girth weld (Weld #6) of the A Steam Generator, an NDE mandated by the ASME Code, to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

The inspectors reviewed records of the following NDEs mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Visual Examination (VT)

VT-1, Report VT-11-021, Weld 12050-WMKS-0102FG/4-WAPD-439/33H VT-1, Report VT-11-023, Weld 12050-WMKS-0102F-1/3-WAPD-413/33H VT-3, Report VT-11-015, Restraint 1205-ECI-0101A/32-SHP-457/2-SHP-R-034 VT-3, Report VT-11-037, Restraint 11715-WMKS-0118N-3/18-CC-419/2-CC-R-418 VT-3, Report VT-11-038, Restraint 11715-WMKS-0118N-3/18-CC-420/2-CC-R-417

• Magnetic Particle Examination (MT)

MT, Report MT-11-001, Lifting Rig Reactor Vessel Cavity Seal Ring Flip Rig MT, Report MT-11-002, Lifting Rig Reactor Vessel Cavity Seal Ring Flip Rig

• Liquid Penetrant Examination (PT)

PT, Report PT-11-001, Valve-to-Elbow Weld, 12050-WMKS-0111AAJ/3-SI-423/23A PT, Report PT-11-015, Integral Attachment, 12050-WMKS-0111AAP/2-CH-421/26H

The inspectors observed the welding activities on Work Order (WO) 59102251731, Pipe Support Replacement, and reviewed associated documents in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work order, repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder performance qualification records, and NDE reports.

In addition, the inspectors reviewed the results of the licensees visual inspection of the Unit 2 containment conducted per WO 59101703615 in accordance with Subsection IWL, Requirements for Class CC Concrete Components of Light Water Cooled Power Plants, of Section XI, Division 1, of the ASME Code. The inspectors also interviewed the licensees responsible engineer for the containment surveillance program and discussed the overall program and the results of the current surveillance.

During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any relevant indications that were analytically evaluated and accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

PWR Vessel Upper Head Penetration (VUHP) Inspection Activities: For the Unit 2 vessel head, a bare metal visual examination was required this outage pursuant to 10 CFR 50.55a. The inspectors reviewed NDE reports for VUHPs No. 8, 15, 18, 23, and 41 to determine if the activities, including the disposition of indications and defects, were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors evaluated if the required visual examination scope/coverage was achieved and limitations (if applicable) were recorded in accordance with the licensee procedures. Additionally, the inspectors evaluated if the licensees criteria for visual examination quality and instructions for resolving interference and masking issues were consistent with 10 CFR 50.55a.

The licensee did not identify any relevant indications that were accepted for continued service during the bare metal visual exam. Additionally, the licensee did not perform any welding repairs to vessel head penetrations since the beginning of the last Unit 2 refueling outage. Therefore, no NRC review was completed for these inspection procedure attributes.

Boric Acid Corrosion Control (BACC) Inspection Activities: The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walkdown inspections performed during the current fall refueling outage (N2R21). The inspectors also interviewed the BACC program owner, conducted an independent walkdown of containment to evaluate compliance with licensees BACC program requirements, and verified that degraded or non-conforming conditions, such as boric acid leaks, were properly identified and corrected in accordance with the licensees BACC and corrective action programs.

The inspectors reviewed the following condition reports and associated corrective actions related to evidence of boric acid leakage to evaluate 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.

• CR440078, Minor Boric Acid Leaks Were Discovered During 2-PT-46.21.1

• CR440132, Packing Leak Discovered at 2-SI-295

• CR44-286, Boric Acid Found at Pipe Cap of 2-SI-297

• CR440319, Acid Found at the Packing of 2-SI-160

• CR440398, Minor Boric Acid Discovered During 2-PT-46.21.1

• CR440427, Boric Acid Discovered at 2-RC-HCV-2556A

The inspectors reviewed the following engineering evaluations completed for evidence of boric acid identified in systems containing borated water to determine if degraded components were documented in the corrective action program. The inspectors also evaluated corrective actions for any degraded components to determine if they met the ASME Section XI Code and/or NRC-approved alternative.

• CR393897, Boric Acid on 1-CH-MOV-1115C, Charging Pump Suction DFrom Volume Control Tank Isolation Valve

• CR444431, Boric Acid on 2-RH-30, 1B Residual Heat Removal Heat Exchanger Outlet Isolation Valve

• CR448017, Boric Acid on 1-CH-203, Seal Water Inlet Header 1-CH-PL-1134 Isolation Valve

Steam Generator (SG) Tube Inspection Activities: The inspectors reviewed the Unit 1 eddy current (EC) examination activities in SG A and the Unit 2 EC examination activities in SGs A and C, to evaluate the inspection activities against the licensees Technical Specifications, NRC commitments, ASME Section XI, and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines. The inspectors reviewed the scope of the EC examinations to verify it included the applicable potential areas of tube degradation and also verified that it met the requirements from Electric Power Research Institute (EPRI) SG Examination Guidelines for inspection requirements following the earthquake event which occurred on August 23, 2011. The inspectors also verified that appropriate inspection scope expansion criteria were planned based on inspection results. Additionally, the inspectors reviewed EC examination status reports to ensure that all tubes with relevant indications were appropriately screened for in-situ pressure testing. Based on the EC examination results, no new degradation mechanisms were identified, no EC scope expansion was required, and none of the SG tubes examined met the criteria for in-situ pressure testing.

The inspectors reviewed the last Condition Monitoring and Operational Assessment report to assess the licensees prediction capability for maximum tube degradation. The inspectors review also included the licensees repair criteria and repair process to ensure they were consistent with plant Technical Specifications and industry guidelines.

No tubes met the criteria for repair or plugging for both Unit 1 and 2. The inspectors also reviewed the primary to secondary leakage (e.g., SG tube leakage) history for the last operating cycle. The inspectors noted that primary to secondary leakage was below the detection threshold during the previous operating cycle.

In addition, the inspectors reviewed documentation to ensure that data analysts, EC probes, and equipment configurations were qualified to detect the existing and potential SG tube degradation mechanisms. The inspectors review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) to ensure that their qualification was consistent with Appendix H or I of the Electric Power Research Institute Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7. The inspectors also directly observed a sample of EC data acquisition in SG A (Cold Leg and Hot Leg sides) for Unit 1, and SG A and C (Cold Leg and Hot Leg sides) for Unit 2.

Furthermore, the inspectors reviewed a sample of EC data with a qualified data analyst for the following tubes: Unit 1, SG A (R29C22, R46C39, R40C47, and R46C60) and Unit 2, SG A (R44C43 and R20C48) and SG C (R7C53 and R13C56). Finally, the inspectors reviewed the licensees corrective actions for indications (either from EC or secondary side visual inspections) of potential loose parts on the SG primary and secondary side, including direct observation of Foreign Object Search and Retrieval (FOSAR) activities.

Identification and Resolution of Problems: The inspectors performed a review of a sample of ISI-related problems which were identified by the licensee and entered into the corrective action program as condition reports (CRs). The inspectors reviewed the CRs to confirm the licensee had appropriately described the scope of the problem, and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant. The inspectors performed this review to ensure compliance with 10CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification Program

a. Inspection Scope

==

The inspectors observed an operator requalification training session which involved an inadvertent actuation of the safety injection system. The inspectors also observed operator requalification simulator exam scenarios which involved a security event which results in a loss of all service water pumps, a loss of vital bus resulting in a loss of component cooling to the residual heat removal heat exchangers while the plant was in mode 5. The inspectors observed crew performance in terms of communications; ability to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including the alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and oversight and direction provided by the shift supervisor, including the ability to identify and implement appropriate TS actions. The inspectors observed the post training critique to determine that weaknesses or improvement areas revealed by the training were captured by the instructor and reviewed with the operators. Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

For the two equipment issues listed below, the inspectors evaluated the effectiveness of the respective licensee's preventive and corrective maintenance. The inspectors performed walkdowns of the accessible portions of the systems, performed in-office reviews of procedures and evaluations, and held discussions with licensee staff. The inspectors compared the licensees actions with the requirements of the Maintenance Rule (10 CFR 50.65), and licensee procedure ER-AA-MRL-10, Maintenance Rule Program, Revision 4. Other documents reviewed are listed in the Attachment to this report.

• CR430757, 2J EDG Frequency Out of Specifications

• CR436945, I - II Battery Charger Card

b. Findings

No findings were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

The inspectors evaluated, as appropriate, the four activities listed below for the following:

(1) effectiveness of the risk assessments performed before maintenance activities were conducted;

(2) management of risk;

(3) upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and

(4) maintenance risk assessments and emergent work problems were adequately identified and resolved. The inspectors verified that the licensee was in compliance with the requirements of 10 CFR 50.65 (a)(4) and the data output from the licensees safety monitor associated with the risk profile of Units 1 and 2. Documents reviewed included 1-OP-8.1, Chemical and Volume Control System, Revision 53.

• Emergent work on Unit 1 turbine driven AFW pump during testing week of August 22, 2011

• Emergent work on 1-CC-E-1B during maintenance on 1B Component Cooling Heat Exchanger the week of August 31, 2011

• 2J EDG inoperable for pin hole in weld on August 21, 2011

• Unit 2 Shutdown Safety Assessment entered unplanned Orange window on September 17, 2011

b. Findings

No findings were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed nine operability evaluations, listed below, affecting risk-significant mitigating systems, to assess, as appropriate:

(1) the technical adequacy of the evaluations;

(2) whether continued system operability was warranted;

(3) whether other existing degraded conditions were considered as compensating measures; (4)whether the compensatory measures, if involved, were in place, would work as intended, and were appropriately controlled; and

(5) where continued operability was considered unjustified, the impact on TS Limiting Conditions for Operation and the risk significance in accordance with the Significant Determination Process (SDP). The inspectors review included a verification that operability determinations (OD) were made as specified by procedure OP-AA-102, Operability Determination, Revision 6.

• OD 000419, "Determine Operability of Unit 2 LHSI Pipe Support"

• OD 000420, Determine Operability of Unit 2 LHSI to HHSI

• OD 000425, Determine Operability of 2-SI-P-1B

• OD 000430, 1A and 1B Component Cooling Heat Exchanger Condition

• CR438131, 1-EG-SOV-600JA SOV is leaking air on the override actuator

• OD000439, 1-RC-PCV-1455C and 1-RC-PCV-1456 are inoperable or NDE protection, TS 3.4.12

• OD000443, Attached Jacket Cooling Pump does not have Orifice at Pump Discharge

• OD000444, 2J EDG does not have Orifice on Jacket Cooling Pump Discharge

• OD000448, Unit 2 Evaluate TS and TRM Equipment for Mode 6 Operability/Functionality

b. Findings

No findings were identified.

==1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications

a.

==

Inspection Scope

The inspectors reviewed selected samples of evaluations to confirm that the licensee had appropriately considered the conditions under which changes to the facility, UFSAR, or procedures may be made, and tests conducted, without prior NRC approval. The inspectors reviewed evaluations for eight changes and additional information, such as drawings, calculations, supporting analyses, the UFSAR, and TS to confirm that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The eight evaluations reviewed are listed in the to this report.

The inspectors reviewed samples of changes for which the licensee had determined that evaluations were not required, to confirm that the licensees conclusions to screen out these changes were correct and consistent with 10CFR50.59. The 16 screened out changes reviewed are listed in the Attachment to this report.

The inspectors evaluated engineering design change packages for 13 material, component, and design based modifications to evaluate the modifications for adverse effects on system availability, reliability, and functional capability. The 13 modifications and the affected cornerstones are as follows:

• DCP-06-103: Unit 1 and Unit 2 EDG Battery Charger Replacements (Mitigating Systems)

• DCP-06-119: Replace Unit 2 Substation Transformers 2A1/ 2A2 / 2H & 2H1 (Initiating Events)

• DCP-08-014: GSI-191 Unit 2 Containment Sump Strainer Seal Modifications (Mitigating Systems)

• DCP-08-103: Alternate Power Supply to Unit 1 SFP Cooling Pumps (Barrier Integrity)

• DCP-08-131: Tornado Driven Missile Protection of Unit 1 TDAFW Pump Exhaust (Mitigating Systems)

• IEE-10000002521: Emergency Diesel Generator Starting Air (Mitigating Systems)

• IEE-10000015657: Diesel Generator Fuel Oil Pump TOL Relay (Mitigating Systems)

• IEE-10000016211: Charging/HHSI Pump Motor Shaft Material (Mitigating Systems)

• NA-09-00113: Replace 1-HV-MOD-163A/B/C with Back Draft Dampers (Barrier Integrity)

• NA-09-00150: Replacement of 2-SI-MOV-2867B (Mitigating Systems)

• NA-10-00162: Recirculation Spray MOV Motor and TOL Replacement for 1-RS-MOV-156B (Barrier Integrity)

• PTE-9000337: Use of MOV Long-Life Grease (Mitigating Systems)

• PTE-10000001941: Replacement Parts for EDG Battery Charger (Mitigating Systems)

Documents reviewed included procedures, engineering calculations, modification design and implementation packages, work orders, site drawings, corrective action documents, applicable sections of the living UFSAR, supporting analyses, TS, and design basis information. The inspectors additionally reviewed test documentation to ensure adequacy in scope and conclusion. The inspectors review was also intended to verify that all appropriate details were incorporated in licensing and design basis documents and associated plant procedures.

The inspectors also reviewed selected condition reports (CRs) and the licensees recent self-assessments associated with modifications and screening/evaluation issues to confirm that problems were identified at an appropriate threshold, were entered into the corrective action process, and appropriate corrective actions had been initiated and tracked to completion.

b. Findings

No findings were identified.

==1R19 Post Maintenance Testing

a. Inspection Scope

==

The inspectors reviewed five post maintenance test procedures and/or test activities for selected risk-significant mitigating systems listed below, to assess whether:

(1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel;

(2) testing was adequate for the maintenance performed; (3)acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents;

(4) test instrumentation had current calibrations, range, and accuracy consistent with the application;

(5) tests were performed as written with applicable prerequisites satisfied;

(6) jumpers installed or leads lifted were properly controlled;

(7) test equipment was removed following testing; and

(8) equipment was returned to the status required to perform in accordance with VPAP-2003, Post Maintenance Testing Program, Revision 14.

• WO 59101688641, Replace positioned on valve 2-FW-HCV-200B

• WO 50102316252, Replace 7300 card C3-126

• WO 59078713601, Install lube oil sample port on 2-QS-P-1A

• WO 59102035759, 1-BY-BCI - II maintenance

• 1-PT-14.2, Charging Pump 1-CH-P-1B, Revision 48, 3 year PM

b. Findings

No findings were identified.

==1R20 Refueling and Other Outage Activities

==

.1 Unit 2 Refueling Outage

a. Inspection Scope

The inspectors reviewed the Outage Safety Review and contingency plans for the Unit 2 refueling outage, which began August 26, 2011, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. The inspectors used IP 71111.20, Refueling and Outage Activities, to observe portions of the shutdown, cooldown, and maintenance activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk plan and applicable TS.

The inspectors monitored licensee controls and performed the activities listed below.

Documents reviewed are listed in the Attachment to this report.

• Review of licensees outage risk control plan and verification that risk, industry experience and previous site problems had been appropriately considered;

• Confirmed that mitigation strategies were in place for losses of key safety functions;

• Observed portions of the cooldown/shutdown process to verify TS restrictions were followed

• Conducted a containment tour, inspecting for boric acid leaks, damage or debris in sump, or items indicative of a larger problem;

• Control room operators were kept cognizant of plant configuration;

• Verified that RCS instrumentation was configured to meet TS requirements and outage risk control plan;

• Monitoring of decay heat removal;

• Verified system operations for Spent Fuel Pool Cooling were not impacted by outage work during and after core offload;

• Verified flow paths, configurations, and alternative means for inventory control;

• Reviewed licensees commitments from GL88-17 and confirmed by sampling that they were still in place and adequate; and

• Verified fuel handling operations (removal, inspection, sipping, reconstitution, and insertion) were being performed according to TS and approved procedures.

b. Findings

No findings were identified.

.2 Unit 1 Forced Outage

a. Inspection Scope

The inspectors reviewed the licensees outage risk control plan for the Unit 1 forced outage, which began August 23, 2011, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. The inspectors used IP 71111.20, Refueling and Outage Activities, to observe portions of the shutdown, cooldown, and maintenance activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk plan and applicable TS. The inspectors monitored licensee controls and verified activities listed below. Documents reviewed are listed in the Attachment to this report.

• Confirmed the licensee had mitigation strategies for losses of key safety functions;

• Confirmed the licensee had scheduled covered workers such that minimum days off for individuals working on outage activities are in compliance with 10 CFR 26.205(d)(4);

• Observed portions of the shutdown and cooldown process to verify that TS restrictions were followed;

• Conducted a containment tour walkdown to check for evidence of boric acid leaks, stains or deposited materials, damage or debris in sump or items that could be indicative of larger problems;

• Control room operators were kept cognizant of plant configuration;

• Verified RCS instrumentation configured to meet TS requirements and outage risk control plan;

• Monitoring of decay heat removal;

• Verified containment penetrations were controlled according to the TS; and

• Review licensees commitments from GL88-17 and confirmed by sampling that they were still in place and adequate.

b. Findings

No findings were identified.

==1R22 Surveillance Testing

a. Inspection Scope

==

For the five surveillance tests listed below, the inspectors examined the test procedures, witnessed testing, or reviewed test records and data packages, to determine whether the scope of testing adequately demonstrated that the affected equipment was functional and operable, and that the surveillance requirements of TS were met. The inspectors also determined whether the testing effectively demonstrated that the systems or components were operationally ready and capable of performing their intended safety functions.

In-Service Test:

• 1-PT-71.3Q, 1-FW-P-3B, B Motor-Driven AFW IST Comprehensive Pump and Valve Test, Revision 47

• 2-PT-14.3, Charging Pump 2-CH-P-1C, Revision 44

Other Surveillance Tests:

• 1-PT-57.1A, Emergency Core Cooling Subsystem - Low head Safety Injection Pump (1-SI-P-1A), Revision 57

• 1-PT-36.5.3A, Solid State Protection System Output Slave Relay Test (Train A),

Revision 36

• 1-PT-64.4A, Casing Cooling Pump (1-RS-P-3A) Test, Revision 22

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Testing

a. Inspection Scope

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

The inspector reviewed various documents that are listed in the Attachment to this report. This inspection activity satisfied one inspection sample for the ANS on a biennial basis.

b. Findings

No findings were identified 1EP3 Emergency Response Organization (ERO) Augmentation

a. Inspection Scope

The inspector reviewed the licensees Emergency Response Organization (ERO)augmentation staffing requirements and process for notifying the ERO to ensure the readiness of key staff for responding to an event and timely facility activation. The qualification records of key position ERO personnel were reviewed to ensure all ERO qualifications were current. A sample of problems identified from augmentation drills or system tests performed since the last inspection were reviewed to assess the effectiveness of corrective actions.

The inspection was conducted in accordance with NRC IP 71114, Attachment 03, Emergency Response Organization Staffing and Augmentation System. The applicable planning standard, 10 CFR 50.47(b)(2), and its related requirements, 10 CFR 50, Appendix E, were used as reference criteria.

The inspector reviewed various documents that are listed in the Attachment to this report. This inspection activity satisfied one inspection sample for the ERO staffing and augmentation system on a biennial basis.

b. Findings

No findings were identified.

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

a. Inspection Scope

Since the last NRC inspection of this program area, Revision 36 of the North Anna Power Station Emergency Plan was implemented based on the licensees determination, in accordance with 10 CFR 50.54(q), that the changes resulted in no decrease in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The inspector conducted a sampling review of the Plan changes and implementing procedure changes made between June 2010 and August 2011 to evaluate for potential decreases in effectiveness of the Plan. However, this review was not documented in a Safety Evaluation Report and does not constitute formal NRC approval of the changes.

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

The inspection was conducted in accordance with NRC IP 71114, Attachment 04, Emergency Action Level and Emergency Plan Changes. The applicable planning standard (PS), 10 CFR 50.47(b)(4) and its related 10 CFR 50, Appendix E requirements were used as reference criteria.

The inspector reviewed various documents which are listed in the Attachment to this report. This inspection activity satisfied one inspection sample for the emergency action level and emergency plan changes on an annual basis.

b. Findings

No findings were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed the corrective actions identified through the Emergency Preparedness program to determine the significance of the issues and to determine if repeat problems were occurring. The facilitys self-assessments and audits were reviewed to assess the licensees ability to be self-critical, thus avoiding complacency and degradation of their emergency preparedness program. In addition, the inspector reviewed licensee self-assessments and audits to assess the completeness and effectiveness of all emergency preparedness related corrective actions.

The inspection was conducted in accordance with NRC IP 71114, Attachment 05, Correction of Emergency Preparedness Weaknesses. The applicable planning standard, 10 CFR 50.47(b)(14) and its related 10 CFR 50, Appendix E requirements were used as reference criteria.

The inspector reviewed various documents which are listed in the Attachment to this report. This inspection activity satisfied one inspection sample for the correction of emergency preparedness weaknesses on a biennial basis.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRAs), and airborne radioactivity areas established within the radiologically controlled area (RCA) of the Unit 1 (U1) and Unit 2 (U2) auxiliary building, and radioactive waste (radwaste) processing and storage locations. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors toured the independent spent fuel storage installations reviewing posting and dosimetry placement and performed a general radiation survey of the area to identify if there were any unexpected results. The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, hot particles, airborne radioactivity, and gamma surveys with a range of dose rate gradients. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected outage jobs, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices: The inspectors evaluated access barrier effectiveness for selected U1 and U2 Locked High Radiation Area (LHRA) and Very High Radiation Area (VHRA) locations. Changes to procedural guidance for LHRA and VHRA controls were discussed with health physics (HP) supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool were reviewed and discussed in detail. Established radiological controls (including airborne controls)were evaluated for selected tasks including work in auxiliary building HRAs, and radwaste processing and storage. In addition, licensee controls for areas where dose rates could change significantly as a result of various routine operations were reviewed and discussed. The expected response by backshift personnel upon discovery of unexpected changes in dose rate or other radiation protection parameters was discussed.

Occupational workers adherence to selected RWPs and HP technician proficiency in providing job coverage were evaluated through direct observations and interviews with licensee staff. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results. ED alarm logs were reviewed and worker response to dose and dose rate alarms during selected work activities was evaluated. The inspectors reviewed the procedural provisions for using tungsten shielding vests and the licensees implementation of effective dose equivalent dosimetry and weighting factors.

Control of Radioactive Material: The inspectors observed surveys of material and personnel being released from the RCA using small article monitor, personnel contamination monitor, and portal monitor instruments. The inspectors compared recent 10 CFR Part 61 results for the Dry Active Waste (DAW) radioactive waste stream with radionuclides used in calibration sources to evaluate the appropriateness and accuracy of release survey instrumentation. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution: CRs associated with radiological hazard assessment and control were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure PI-AA-200, Corrective Action, Revision 17. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radiation protection activities were evaluated against the requirements of the UFSAR Section 12, Radiation Protection; TS Sections 5.4, Procedures and 5.7, High Radiation Areas; 10 CFR Parts 19 and 20; and approved licensee procedures. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material.

Documents reviewed are listed in Section 2RS1 of the Attachment to this report.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry: The inspectors reviewed National Voluntary Laboratory Accreditation Program certification data (including thermoluminescent dosimetry testing for neutron, gamma, and beta exposures) and discussed program guidance for storage, processing, and results for active and passive personnel dosimeters currently in use.

Licensee evaluations for shallow and deep dose assessments for workers with identified skin contaminations were discussed. The inspector discussed the number of events where individuals logged in on a RWP and subsequently found themselves unable to pass through the RCA entry turnstile due to the digital alarming dosimeter (DAD) being in PAUSE mode.

Internal Dosimetry: Program guidance (including derived air concentration-hr tracking),instrument detection capabilities, and assessment results for internally deposited radionuclides were reviewed in detail. The inspectors reviewed selected routine and investigative in vivo (Whole Body Count) analyses from January 2010 to January 2011.

In addition, capabilities for collection and analysis of special bioassay samples were evaluated and discussed with licensee staff.

Special Dosimetric Situations: The inspectors evaluated the licensees use of multi-badging, extremity dosimetry, and dosimeter relocation within non-uniform dose rate fields and discussed worker monitoring in neutron areas with licensee staff. The inspectors also reviewed records of monitoring for declared pregnant workers since January 2010 and discussed monitoring guidance with licensee staff. In addition, the adequacy of shallow dose assessments for selected Personnel Contamination Events occurring between January 2010 and January 2011 were reviewed and discussed.

Problem Identification and Resolution: The inspectors reviewed and discussed selected corrective action program (CAP) documents associated with occupational dose assessment. The inspectors evaluated the licensees ability to identify and resolve the identified issues in accordance with procedure PI-AA-200, Corrective Action, Revision 17. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

HP program occupational dose assessment activities were evaluated against the requirements of UFSAR Section 12.3.3; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Sections 2RS1and 2RS4 of the Attachment to this report.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

Event and Effluent Program Reviews: The inspectors reviewed the 2009 and 2010 Annual Radiological Effluent Release Report documents for consistency with requirements in the Offsite Dose Calculation Manual (ODCM) and TS. The inspectors reviewed changes to the ODCM completed in 2009 and 2010. Routine and abnormal effluent release results and reports, as applicable, were reviewed and discussed with responsible licensee representatives. Status of the radioactive gaseous and liquid effluent processing and monitoring equipment, and applicable equipment changes, as described in the UFSAR and current ODCM were discussed with responsible staff.

Equipment Walk-Downs: The inspectors walked-down and discussed selected components of gaseous processing systems, and selected U1 and U2 liquid waste processing and discharge systems to ascertain material condition, configuration and alignment. To the extent practical, the inspectors observed and evaluated the material condition of in-place liquid waste processing equipment for indications of degradation or leakage that could constitute a possible release pathway to the environment. The walk-downs were accompanied by Radiation Protection personnel and included discussion and evaluation of observed leaks, degraded material condition, status of in-place plant work order tags, and configuration control associated with the waste drain collection system (drain tank(s), clarifier and pumps), gas decay tanks, and associated piping and valves. The inspectors observed collection of a clarifier liquid sample and discussed liquid effluent discharge pathways and operability of the effluent radiation monitors with plant personnel.

Effluent Processing: The inspectors discussed processing of liquid waste tanks using the liquid waste system installed in 2007, reviewed gaseous and liquid release permits plant personnel. The reviews included review and discussion of selected dose calculation summaries. Release quantities and dose impacts were reviewed and discussed. The inspectors reviewed 10 CFR 61 analysis data for expected nuclide distributions used to quantify effluents, treatment of hard to detect nuclides, and determination of appropriate calibration nuclides for effluent analysis instruments. The inspectors reviewed the calculated public dose results for any indications of higher than anticipated or abnormal releases.

Ground Water Protection: The inspectors reviewed the current groundwater sample results. The inspectors discussed possible changes in the groundwater program and site hydrology that may result from ongoing construction work adjacent to the protected area and recently identified tritium in several on-site monitoring wells. The groundwater program was discussed with Radiation Protection representatives.

Problem Identification and Resolution: The inspectors reviewed selected CAP CR documents in the areas of gaseous and liquid effluent processing and release activities.

The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure PI-AA-200, Corrective Action, Revision 17. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

Effluent process and monitoring activities were evaluated against details and requirements documented in UFSAR Sections 11 and 12; ODCM; 10 CFR Part 20; Appendix I to 10 CFR Part 50; and approved licensee procedures. In addition, ODCM and UFSAR changes since the last onsite inspection were reviewed against the guidance in NUREG-1301 and Regulatory Guide (RG) 1.109, RG 1.21, and RG 4.1.

Records reviewed are listed in Section 2RS6 of the Attachment to this report.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program (REMP)

a. Inspection Scope

REMP Implementation: The inspectors observed routine sample collection and surveillance activities as required by the licensees environmental monitoring program.

The inspectors noted the material condition and operability of airborne particulate filter and iodine cartridge sample stations and observed collection of weekly air samples and rainwater at selected monitoring locations. Environmental thermoluminescent dosimeters at selected sites were checked for material condition. The inspectors determined the current location of selected sample points using global positioning system instrumentation. Land use census results, changes to the ODCM, and sample collection/processing activities were discussed with environmental technicians and licensee staff.

The inspectors reviewed the last two calibration records for selected environmental air sampler flowmeters. The inspectors also reviewed the 2009 and 2010 Annual Radiological Environmental Operating Reports, interlaboratory cross-check program results, and procedural guidance for environmental sample collection and processing.

Selected environmental measurements were reviewed for consistency with licensee effluent data, evaluated for radionuclide concentration trends, and compared with detection level sensitivity requirements.

Procedural guidance, program implementation, and environmental monitoring results were reviewed against: 10 CFR Part 20; Appendix I to 10 CFR Part 50; TS Section 5.0; ODCM; RG 4.15, Quality Assurance for Radiological Monitoring Programs (Normal Operation) - Effluent Streams and the Environment; and the Branch Technical Position, An Acceptable Radiological Environmental Monitoring Program - 1979. Documents reviewed are listed in Section 2RS7 of the Attachment to this report.

Meteorological Monitoring Program: The inspectors performed a walk-down with licensee staff of the meteorological tower. The inspectors observed the physical condition of the tower and its instrumentation and discussed equipment operability and maintenance history with licensee staff. The inspectors evaluated transmission of locally generated meteorological data to other licensee groups such as emergency operations personnel and main control room operators. For the meteorological measurements of wind speed, wind direction, and temperature, the inspectors reviewed the last two calibration records for applicable tower instrumentation.

Licensee procedures and activities related to meteorological monitoring were evaluated against: ODCM; UFSAR Chapter 11; and proposed Revision 1 to RG 1.23, Meteorological Programs in Support of Nuclear Power Plants (1980). Documents reviewed are listed in Section 2RS7 of the Attachment to this report.

Identification and Resolution of Problems: The inspectors reviewed selected CRs in the areas of radiological environmental monitoring and meteorological tower maintenance.

The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with PI-AA-200, Corrective Action, Revision 17. Documents reviewed are listed in section 2RS7 in the Attachment to this report.

b. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation

a. Inspection Scope

Waste Processing and Characterization: During inspector walk-downs, accessible sections of the liquid and solid radwaste processing systems were assessed for material condition and conformance with system design diagrams. Inspected equipment included radwaste storage tanks, resin transfer piping, resin and filter packaging components, and abandoned deborating equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee staff.

The 2010 Radioactive Effluent Report and radionuclide characterizations from 2009 - 2010 for each major waste stream were reviewed and discussed with radwaste staff.

For primary resin, primary filters, and DAW, the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream sampling, mixing, concentration averaging, and stabilization methodology for resins and filters was evaluated and discussed with radwaste staff. The inspectors also reviewed the licensees procedural guidance for monitoring changes in waste stream isotopic mixtures.

Radioactive Material Storage: During walk-downs of indoor and outdoor radioactive material storage areas, the inspectors observed the physical condition and labeling of storage containers and the posting of Radioactive Material Areas. The inspectors also reviewed licensee procedural guidance for long-term storage and monitoring of radioactive material.

Transportation: The inspectors observed preparation activities for a shipment of contaminated refueling outage tools. The inspectors observed licensee surveys of the shipping packages, performed independent dose rate measurements, and interviewed shipping technicians regarding Department of Transportation (DOT) regulations.

Selected shipping records were reviewed for consistency with licensee procedures and compliance with NRC and DOT regulations. The inspectors reviewed emergency response information, DOT shipping package classification, waste classification, radiation survey results, and evaluated whether receiving licensees were authorized to accept the packages. Licensee procedures for opening and closing Type A containers and Type B shipping casks were compared to recommended vendor protocols and Certificate of Compliance requirements. In addition, training records for selected individuals currently qualified to ship radioactive material were reviewed.

Problem Identification and Resolution: The inspectors reviewed CRs in the area of radwaste/shipping. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure PI-AA-200, Corrective Action, Revision 17.

The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radwaste processing, radioactive material handling, and transportation activities were reviewed against the requirements contained in the licensees Process Control Program, UFSAR Chapter 11, 10 CFR Part 20, 10 CFR Part 61, 10 CFR Part 71, and 49 CFR Parts 172-178. Licensee activities were also evaluated against guidance provided in the Branch Technical Position on Waste Classification (1983) and NUREG-1608.

Documents reviewed during the inspection are listed in Section 2RS8 of the Attachment to this report.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

Mitigating Systems Performance Index: The inspectors performed a periodic review of the five following Unit 1 and 2 Mitigating Systems Performance Indicators (PIs) to assess the accuracy and completeness of the submitted data and whether the performance indicators were calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspection was conducted in accordance with NRC IP 71151, Performance Indicator Verification.

Specifically, the inspectors reviewed the Unit 1 and Unit 2 data reported to the NRC for the period July 1, 2010, through June 30, 2011. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs.

• High Pressure Injection System

• Emergency AC Power System

• Cooling Water Systems

• Auxiliary Feedwater System

• Residual Heat Removal System

Occupational Radiation Safety Cornerstone: The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from January, 2010 through June, 2011. For the assessment period, the inspectors reviewed ED alarm logs and selected CRs related to controls for exposure significant areas. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in Sections 2RS1 and 4OA1 of the Attachment to this report.

Public Radiation Safety Cornerstone: The inspectors reviewed the Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences PI results from January, 2010 through June, 2011. The inspectors reviewed CAP documents, effluent dose data, and licensee procedural guidance for classifying and reporting PI events. Documents reviewed are listed in Sections 2RS6 and 4OA1 of the Attachment to this report.

The inspectors completed two of the required samples specified in IP 71151.

Emergency Preparedness Cornerstone: The inspector sampled licensee submittals relative to the PIs listed below for the period April 1, 2010, through June 30, 2011. To verify the accuracy of the PI data reported during that period, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used to confirm the reporting basis for each data element.

• Emergency Response Organization Drill/Exercise Performance (DEP)

• Emergency Response Organization Readiness (ERO)

• Alert and Notification System Reliability (ANS)

The inspection was conducted in accordance with NRC IP 71151, Performance Indicator Verification. For the specified review period, the inspector examined data reported to the NRC, procedural guidance for reporting PI information, and records used by the licensee to identify potential PI occurrences. The inspector verified the accuracy of the PI for ERO drill and exercise performance through review of a sample of drill and event records. The inspector reviewed selected training records to verify the accuracy of the PI for ERO drill participation for personnel assigned to key positions in the ERO.

The inspector verified the accuracy of the PI for alert and notification system reliability through review of a sample of the licensees records of periodic system tests. The inspector also interviewed the licensee personnel who were responsible for collecting and evaluating the PI data. Licensee procedures, records, and other documents reviewed within this inspection area are listed in the Attachment to this report.

This inspection activity satisfied one inspection sample each for the Drill/Exercise Performance, ERO Drill Participation, and Alert and Notification System as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered into the Corrective Action Program

As required by IP 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished by reviewing daily CR report summaries and periodically attending daily CR Review Team meetings.

.2 Annual Sample:

Review of CR430757, 2J EDG Frequency Out of Spec During 2-PT-82J

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CR430757, 2J EDG Frequency Out of Spec During 2-PT-82J, to ensure that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. This CR was associated with the operation of the 2J EDG and its required frequency band. The inspectors also evaluated the CR against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 17, and 10 CFR 50, Appendix B.

b. Findings and Observations

No findings were identified.

.3 Operating Experience Smart Sample (OpESS) FY 2010-01 Recent Inspection

Experiences for Components Installed Beyond Vendor Recommended Service Life

a. Inspection Scope

The inspectors performed a review regarding the licensees processes at the site to address replacement or refurbishment of components identified as having a specific lifetime to ensure that vendor recommended service life times are being identified and that appropriate maintenance activities have been implemented. The inspector ensured that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors also evaluated licensee corrective actions against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 17, and 10 CFR 50, Appendix B.

b. Findings

No findings were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report (LER) 05000338, 339/2010-001-00: Non-Functional

Fire Barrier Penetrations Containing Aluminum Conduit Due to Configuration

On May 13, 2010, results of aluminum conduit seal penetration tests determined certain fire barrier penetration configurations would not perform their design function. At the time of discovery, fire watches for the affected area were already in place. The effects of fire on aluminum conduit were not originally considered when the fire testing packages were complied for North Anna. Fire barrier penetrations containing aluminum conduit were tested through a contracted vendor and a design change will be implemented to correct as needed based on test results and site evaluation. Procedures controlling Fire Protection Program are being revised to address the test results. The licensee entered this problem in their CAP as CR436110. The inspector reviewed the LER and determined that this issue had been identified and documented as NCV 05000338, 339/2011003-06, Inadequate Qualification testing of Fire Barrier Penetrations Seals. No additional findings were identified. This LER is closed.

.2 (Closed) LER 05000338, 339/2010-003-00: Potential for Containment Sump Strainer

Blockage due to Unacceptable Insulation in Containment

On September 22, 2010, with Unit 1 defueling during a scheduled refueling outage, an insulation discrepancy was noted while investigating shielding material on the Reactor Pressure Vessel nozzles. The original insulation was replaced with Microtherm per an earlier design change. Visual inspections confirmed the existence of Microtherm in Unit 2 containment as well. A flawed methodology was used to determine types and quantities of insulation during the GSI-191 containment walkdowns, resulting in unacceptable insulation not being included in the containment debris inventory and subsequently remediated. Unacceptable insulation was identified within the zones of influence for Unit 1 and 2, and remediated. A special inspection was performed by the NRC and the results are documented in North Anna Inspection Report 05000338/2010006 and 05000339/2010006. The enforcement aspects of this are discussed in section 4OA7 of this report. This LER is closed.

.3 Unit 1 and 2 Automatic Reactor Trip Due to Earthquake

On August 23, 2011, at approximately 1:51 p.m. EST, the site experienced a magnitude 5.8 earthquake with an epicenter approximately twelve miles southwest of the plant.

Both reactor trip breakers opened on negative flux rate approximately 11 seconds after the event. Sudden pressure relay actuations were experienced on the RSSTs approximately 12 seconds after the event leading to a loss of off-site power (LOOP)event. At approximately 20 seconds after the event, all four EDGs and the SBO DG auto started. An Alert was declared at 2:03 p.m. based on shift manager judgment due to an inability to enter the EAL for a seismic event because the LOOP prevented the seismic panel from reporting the earthquake magnitude in the control room. At 2:40 p.m., 2H EDG was tripped in the control room due to a coolant leak. At 2:55 p.m., an Alert was declared for Unit 2 due to the loss of 2H EDG. Approximately 38 minutes later, the SBO DG was aligned to the 2H bus. At 10:58 p.m., offsite power was restored supplying all the emergency buses. Both units were safely shutdown and stabilized under hot shutdown conditions. Resident inspectors responded to the event. An augmented inspection team was implemented to further review and analyze licensee actions with regard to this seismic event. The results of the inspection, which took place from August 30, 2011, through October 3, 2011, will be documented in the NRC Augmented Inspection Team Report 05000338/2011011 and 05000339/2011011.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with the licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors normal plant status review and inspection activities.

b. Findings

No findings were identified.

.2 Review of the Operation of an Independent Spent Fuel Storage Installation (Inspection

Procedure 60855.1)

a. Inspection Scope

Inspectors reviewed the normal operation of the Independent Spent Fuel Storage Installation (ISFSI). On June 27, 2011, the inspectors evaluated ISFSI activities related to DOM-32PTH-028. They verified, by the direct observation and independent evaluation of selected activities, that the licensee performed the loading and unloading in a safe manner and in compliance with approved procedures. The inspectors walked down the ISFSI pad to assess the material condition of the casks, the installation of security equipment, and the performance of monitoring systems. The inspectors reviewed licensee cask loading and handling procedures, and reviewed previous cask loading and ISFSI related plant issues and corrective action status.

b. Findings

No findings were identified.

.3 (Closed) Unresolved Item (URI) 05000338, 339/2011008-01: Seismic Qualification of

Safety Related Breakers with Thermal Overload Unsecured

The inspectors had previously opened URI 05000338, 339/2011008-01 Seismic Qualification of Safety Related Breakers with Thermal Overload Unsecured, in NRC Problem Identification and Resolution Inspection Report 05000338/2011008 and 05000339/2011008 concerning the seismic qualification of safety related breakers with thermal overloads that are not securely attached to their mounting base. The inspectors had questioned whether the licensee had considered past operability, seismic qualification, extent of condition and common cause attributes when they closed CR423620 as closed to work performed with no further action required. As a result of the inspectors questions, the licensee had a third party independent laboratory seismically test this type of safety related breaker with its thermal load in a condition similar to the as-found condition to address post operability concerns. A further review of the information related to the laboratory seismic testing results revealed no performance deficiencies. This URI is closed.

.4 (Closed) FIN-TBD, 05000338, 339/2011003-05, Failure to Take Adequate Corrective

Action to Preclude a Fire in the Units 1 and 2 Control Room Complex.

a. Inspection Scope

On February 3, 2011, the control room operators received annunciator, 1H-G4, Annunciator System DC Ground, and subsequently noticed a strong, acrid smell within the control room area. An investigation revealed flames approximately 2 - 4 inches in height coming from a circuit card in the Hathaway annunciator cabinet, 1-EI-CB-21. The fire was extinguished and the problem entered into their CAP as CR412487.

b. Findings

Introduction:

A Green self-revealing finding was identified regarding inadequate corrective action associated with control room annunciator card resistor failures resulting in a fire in the respective cabinet located in the Units 1 and 2 control room complex.

Description:

On February 3, 2011, the control room operators received annunciator, 1H-G4, Annunciator System DC Ground, and subsequently noticed a strong, acrid smell within the control room area. An investigation revealed flames approximately 2 - 4 inches in height coming from a circuit card in the Hathaway annunciator cabinet, 1-EI-CB-21. The fire was extinguished and the problem entered into their CAP as CR412487. The inspectors reviewed the corrective action history related to annunciator card failures and noted the following timeline:

• January 20, 2010: the licensee initiated CR365779, Annunciator did not illuminate during performance of 2-PT-32.1.5, for which apparent cause evaluation (ACE)18031 was completed on March 11, 2010, but did not specifically note that the resistor failure was a fire precursor.

• June 27, 2010: CR385982 was initiated for an annunciator problem and a slight acrid smell in the control room. CA172487 was initiated for maintenance inspections that identified degraded resistors on annunciator cards causing enough heat to melt an adjacent plastic relay.

• June 30, 2010: CR386430, Annunciator card in 1-EI-CB-12 found to be severely overheated, was initiated as a result of the inspections completed for CA172487, and CA172718, document completion of inspection, results, and any additional recommendations, was also initiated.

• July 7, 2010: CR387108, Several backboards V & W Annunciator cards had overheated resistors and relays, was initiated based on the inspections performed by CA172718. This CR also initiated CA173282, investigate annunciator card issues and document long-term corrective actions, and CA173407, Due 7-15, CAART update, CA to Engineering to assess immediate threat.

• July 14, 2010: CA173407 stated, The annunciator cards for 1-EI-CB-12 & 13 have all been inspected by I&C with the above listed items requiring replacement/repair as a proactive measure due to the obvious degradation. The condition of the associated resistors/relays does not warrant an immediate threat concern, but the identified components should be replaced/repaired as soon as practicable.

• July 28, 2010: CA174851, Replace all carbon resistors in the Hathaway system, was initiated with a due date of April 13, 2011.

• October 24, 2010: CR400369, The input resistor and relay for annunciator 2B-H1 need to be replaced, was initiated and stated, Operations noticed a burnt smell in Unit 2 control room and the annunciator for PRZ RELIEF TK HI TEMP, 2B-H1, locked in. This CR was closed to WO59102227590 which documented, Found the resistor & relay badly burned.

The inspectors reviewed ACE18534 initiated from CR412487 and noted that the licensee concluded the cause was a lack of prioritization of the work order associated with the replacement of the resistors in the Hathaway system. The inspectors reviewed the licensees CAP procedure, PI-AA-200, Corrective Action, and noted the following steps:

• Step 5.3.7 Condition Adverse to Quality, An all-inclusive term used in reference to any of the following: failures, malfunctions, deficiencies, deviations, defective material and equipment and non-conformances. These conditions are required to be promptly identified and corrected.

• Step 5.3.13 Deviating Condition, An other-than-expected result of an activity, or a non-routine occurrence or condition, regardless of quality classification, that affects or results in the following: Defective or malfunctioning equipment.

The inspectors concluded that the licensee failed to meet the standards established by their CAP procedure for adequate corrective action for a deviating condition or condition adverse to quality (CAQ) associated with annunciator card resistor degradation which subsequently resulted in a fire in the Units 1 and 2 control room complex. The inspectors also noted that the licensee failed to understand the significance of the resistor degradation with respect to possible fire and resultant impact on a common control room for both units.

Analysis:

The licensee identified that age related degradation was occurring within the carbon resistors on the Hathaway annunciator cards. The failure to complete replacement of the carbon resistors within a reasonable time led to an overheating condition and a fire on card no. 9 in rack 3 of bay 2 of Hathaway cabinet 1-EI-CB-21 which represented a performance deficiency. The finding was more than minor because it could be reasonably viewed as a precursor to a significant event based on fire development leading to an evacuation of the control room. The finding was screened using phase 1 of the SDP and was determined to be a fire initiator contributor within the initiating events cornerstone and required a phase 3 fire SDP risk assessment in as it represented a fire within the main control room (MCR). A regional SRA performed an SDP phase 3 fire risk assessment for this finding in accordance with NRC Inspection Manual Chapter (IMC) 0609 Appendix F, NUREG/CR 6850 and NUREG/CR 6850 supplement 1. The major assumptions of the analysis included:

(1) A one year exposure period;

(2) A probability of MCR abandonment due to MCR smoke and heat habitability conditions determined by the licensees CFAST analysis;

(3) A bounding conditional core damage probability of 0.1 for the MCR abandonment scenario;

(4) An increase in the MCR operator actions due to the use of self contained breathing apparatus (SCBAs) for the scenarios without MCR abandonment;

(5) Fire would result in a transient initiator for non-MCR abandonment scenarios;

(6) Fire would not result in damage to any equipment required for safe shutdown. The factors which mitigated the risk included the low probability of MCR abandonment and the lack of fire damage to any safety related equipment. The dominant sequence was a fire in the Hathaway Cabinet in the logic room which would allow smoke and heat to be routed by the ventilation system into the MCR requiring MCR abandonment due to habitability conditions and a failure to satisfactorily implement the remote safe shutdown procedure resulting in core damage from inadequate core cooling. The SDP phase 3 risk evaluation determined that the risk of the finding was an increase in core damage frequency of <1E-6/year, a Green finding of very low safety significance. The inspectors determined there were no cross-cutting aspects because the performance deficiency was not representative of current licensee performance.

Enforcement:

Licensee procedure, PI-AA-200, requires that a CAQ is required to be promptly identified and corrected. Contrary to this, on February 3, 2011, the licensee failed to adequately correct a CAQ involving degradation of annunciator card resistors which resulted in a fire in the Units 1 and 2 control room complex. Because this finding does not involve a violation of regulatory requirements, has a very low safety significance, and has been entered into the licensees CAP as CR400369, it is identified as FIN, 05000338, 339/2011004-01, Failure to Take Adequate Corrective Action to Preclude a Fire in the Units 1 and 2 Control Room Complex.

.5 (Closed) URI 05000338, 339/2010006-01: Failure to Remove Particulate Insulation to

Meet Strainer Performance Requirements

The inspectors had previously opened URI 05000338, 339/2010006-01 Failure to Remove Particulate Insulation to Meet Strainer Performance Requirements, in NRC Special Inspection Report 05000338/2010006 and 05000339/2010006 concerning the use of Cal-Sil and Microtherm Insulation in the planned designs for the RS and LHSI containment sump strainers. No immediate safety concern for this issue was identified as both units were shut down at the time of this inspection activity. It was determined that additional inspection would be required. The NRC further reviewed the licensees additional information and inspection data, and determined that the licensee performed reasonable searches to identify the insulation inside containment and has either removed the insulation or properly analyzed leaving it in containment. The enforcement aspects of this are discussed in section 4OA7 of this report. This URI is closed.

4OA6 Meetings, Including Exit

.1 Mods/50.59 Inspection Exit Meeting

An inspection debrief meeting with members of the licensee staff was conducted on May 26, 2011, to discuss the progress of this inspection. Following additional in-office review and inspection activities, a final exit meeting with Mr. Fred Mladen and other members of the licensee staff was conducted on July 21, 2011, to discuss the results of the inspection. Proprietary information reviewed by the team as part of routine inspection activities was either returned to the licensee or disposed of in accordance with prescribed controls.

.2 Radiation Protection Baseline Inspection Exit Meeting

On July 29, 2011, the inspectors discussed the results of the inspection with Mr. Michael Crist, Plant Manager, and other responsible staff

.3 Emergency Preparedness Inspection Exit Meeting

On September 1, 2011, the lead inspector presented the inspection results to Mr.

Michael Crist and other members of his staff. The inspector confirmed that proprietary information was not provided during the inspection.

.4 Inservice Inspection Exit Meeting

Mr. Michael Crist was present for each exit meeting for both the ISI and the SGISI portions. The exit meetings for the Unit 1 and the Unit 2 SGISI portion, was conducted on September 15, 2011, and September 29, 2011, respectively. The exit meeting for the Unit 2 ISI portion was conducted on September 30, 2011. All proprietary information that was provided to the inspector during the inspection, was returned to the licensee

Exit Meeting Summary

On October 28, 2011, the resident inspectors presented the inspection results to Mr.

Larry Lane and other members of the staff, who acknowledged the findings. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section 2.3.2 of the NRC Enforcement Policy, for being dispositioned as an NCV.

10 CFR 50, Appendix B, Criterion XVI, requires the licensee to identify and correct conditions adverse to quality involving the unacceptable presence of Microtherm and Cal-Sil insulation within the GSI 191 zone of influence (ZOIs) inside each Units containment.

Contrary to this above, on September 22, 2010, the licensee identified that an inadequate methodology was used to determine the types and quantities of insulation during the GSI-191 containment walkdowns in 2003 and 2004, resulting in unacceptable insulation not being included in the containment debris inventory and subsequently removed. The issue is more than minor because it associated with the Mitigating Systems cornerstone and the related attribute of equipment availability and reliability because the presence of Microtherm and Cal-Sil insulation within the ZOI would impact the availability and reliability of the containment sump strainers in post-loss of coolant accident (LOCA)/high energy line break (HELB) conditions. A phase 1 Significance Determination Process (SDP) screening determined that the finding represented a potential loss of long term decay heat removal as the Microtherm could impact flow from both the Low Pressure Safety Injection (LHSI) containment sump strainer and the Recirculation Spray (RS) sump strainer during the recirculation phase of a LOCA. The phase 2 SDP evaluation determined that the finding was potentially greater than Green but did not account for the specific LOCA size and frequency required to release the insulation, the probability factor of the LOCA occurring at locations where the insulation was present, or the potential recovery actions, therefore a detailed phase 3 SDP risk assessment was performed by a regional Senior Reactor Analyst (SRA). The risk was mitigated by the low probability of the required initiators and the proceduralized recovery actions. The result of the phase 3 SDP evaluation was a core damage frequency increase for the PD of <1E-6 per year, a Green finding of very low safety significance.

The licensee has documented in their corrective action program as CR 396377.

ATTACHMENT: SUPPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

W. Anthes, Manager, Nuclear Maintenance

M. Becker, Manager, Nuclear Outage and Planning

R. Brill, Boric Acid Corrosion Program

M. Bradley, Supervisor, Radiation Protection Operations

C. Cherry, ISI Program Engineer

J. Collins, Manager, Nuclear Emergency Preparedness

M. Crist, Plant Manager

B. Derreberry, Supervisor ISI/NDE

J. Daugherty, Manager, Nuclear Maintenance

R. Evans, Manager, Radiological Protection and Chemistry

C. Gum, Manager, Nuclear Protection Services

E. Hendrixson, Director, Nuclear Site Engineering

W. Hoffner, Fleet EP Manager

S. Hughes, Manager, Nuclear Operations

P. Kemp, Project Manager

L. Lane, Site Vice President

J. Leberstien, Technical Advisor, Licensing

F. Mladen, Director, Station Safety and Licensing

J. Schleser, Manager, Organizational Effectiveness

M. Olin, Emergency Preparedness Site Supervisor

D. Plogger, EP Specialist

G. Rossetti, Design Engineering

R. Scanlon, Manager, Nuclear Site Services

R. Simmons, Supervisor, Radiation Protection Technical Services

R. Tanner, Welding Supervisor

D. Taylor, Supervisor, Station Licensing

M. Walker, Manager, Engineering Programs

R. Wesley, Manager, Nuclear Training

M. Whalen, Technical Advisor, Licensing

NRC Personnel

J. Reece, Senior Resident Inspector, North Anna Power Station

C. Sanders, Resident Inspector (Acting), North Anna Power Station

G. Kolcum, Senior Resident Inspector, North Anna Power Station

R. Clagg, Resident Inspector, North Anna Power Station

LIST OF ITEMS

Opened and Closed

05000338, 339/2011004-01 FIN

Failure to Take Adequate Corrective Action to Preclude a Fire in the Units 1 and 2 Control Room

Complex (Section 4OA5.4)

Closed

05000338, 339/2010-001-00 LER

Non-Functional Fire Barrier Penetrations Containing Aluminum Conduit Due to Configuration (Section 4OA3.1)

05000338, 339/2010-003-00 LER

Potential for Containment Sump Strainer Blockage due to Unacceptable Insulation in Containment (Section 4OA3.2)

05000338, 339/2011008-01 URI

Seismic Qualification of Safety Related Breakers with Thermal Overload Unsecured (Section 4OA5.3)

05000338, 339/2011003-05 FIN-TBD Failure to Take Adequate Corrective Action to

Preclude a Fire in the Units 1 and 2 Control Room Complex (Section 4OA5.4)

05000338, 339/2010006-01 URI

Failure to Remove Particulate Insulation to Meet

Strainer Performance Requirements (Section 4OA5.5)

Discussed

None