IR 05000338/2010005

IR 05000338-10-005, 05000339-10-005, 07200056-10-002, on 10/01/2010 - 12/31/2010, North Anna Power Station, Units 1 & 2, and Independent Spent Fuel Storage Installation

ML110280480
Person / Time
Site:	North Anna
Issue date:	01/28/2011
From:	Gerald Mccoy NRC/RGN-II/DRP/RPB5
To:	Heacock D Virginia Electric & Power Co (VEPCO)
References
IR-10-002, IR-10-005
Download: ML110280480 (51)

Text

January 28, 2011

SUBJECT:

NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000338/2010005, 05000339/2010005, AND 07200056/2010002

Dear Mr. Heacock:

On December 31, 2010, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your North Anna Power Station Units 1 and 2 and the North Anna Independent Spent Fuel Storage Installation. The enclosed integrated inspection report documents the inspection findings which were discussed on January 25, 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 three NRC-identified findings, and one self-revealing finding of very low safety significance (Green). Three of these findings were determined to involve violations of NRC requirements. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. However, because of the very low safety significance of these issues and because they were entered into your corrective action program, the NRC is treating these as non-cited violations (NCV) consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you wish to contest these non-cited violations, 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. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

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, 50-339,72-056 License Nos.: NPF-4, NPF-7

Enclosure:

Inspection Report 05000338/2010005, 05000339/2010005, and 7200056/2010002

w/ Attachment: Supplemental Information

REGION II==

Docket Nos.:

50-338, 50-339,72-056

License Nos.:

NPF-4, NPF-7

Report No:

05000338/2010005, 05000339/2010005, 07200056/2010002

Licensee:

Virginia Electric and Power Company (VEPCO)

Facility:

North Anna Power Station, Units 1 & 2 and the North Anna Independent Spent Fuel Storage Installation

Location:

1022 Haley Drive Mineral, Virginia 23117

Dates:

October 1, 2010 through December 31, 2010

Inspectors:

J. Reece, Senior Resident Inspector

R. Clagg, Resident Inspector

W. Loo, Senior Health Physicist, (Sections 2RS1, 2RS2, 2RS3, 2RS5,

4OA1.2, and 4OA5.3)

A. Nielsen, Senior Health Physicist, (Sections 2RS1, 2RS2, 2RS3, 2RS5,

4OA1.2, and 4OA5.3)

E. Lea, Jr., Senior Operations Engineer, (Section 1R11.2)

Approved by:

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

Enclosure

SUMMARY OF FINDINGS

IR 05000338/2010-005, 05000339/2010-005, 07200056/2010-002; 10/01/2010 - 12/31/2010;

North Anna Power Station, Units 1 and 2 and North Anna Independent Spent Fuel Storage Installation: Routine Integrated Inspection Report; Identification and Resolution of Problems.

The report covered a 3 month period of inspection by resident inspectors, senior health physicists, and reactor inspectors from the region. Four findings were identified of which three were determined to be non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC)0609, Significance Determination Process (SDP). The cross-cutting aspect was determined using IMC 0310, Components within the Cross Cutting Areas. 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 Green, self-revealing finding was identified for the failure to maintain a preventative maintenance (PM) procedure for circuit breakers current with industry information and operating experience (OE), as required by procedure, DNAP-2001,

Equipment Reliability Process, Revision 0. The licensee entered this problem into their corrective action program as condition report 331819.

The failure to maintain an adequate preventive maintenance (PM) procedure led to an age related failure of a motor starter (main contactor) causing a fire in safety-related breaker cubicle J1 of motor control center (MCC) 1J1-2S which supplied power to the D control rod drive mechanism cooling fan, 01-HV-F-37D. The failure to establish an adequate PM task for testing the main contactor of a circuit breaker to ensure that it is in good operating condition and will operate reliably until the next scheduled maintenance was determined to be a performance deficiency.

Significance Determination Process (SDP) phase 1 screening of the finding was performed and the finding was determined to increase the likelihood of a fire external event and required a phase 3 SDP evaluation. A phase 3 SDP analysis was performed by a regional SRA in accordance with Inspection Manual Chapter 0609 Appendix F, NUREG /CR -6850 as amended by NUREG/CR -6850 supplement 1, with the NRC North Anna SPAR risk model used to determine the conditional core damage probability (CCDP) for the fire scenarios. The dominant sequence was a fire in MCC1J1-2S damaging MSIV cables resulting in a reactor trip transient with failure of high pressure recirculation and residual heat removal due to fire effects leading to core damage. The evaluation concluded that the core damage frequency (CDF) increase of the potential fire scenarios was characterized as of very low safety significance (Green). This finding involved the cross-cutting area of problem identification and resolution, the component of OE, and the aspect of implementation and institutionalization of OE through changes to station processes and procedures (P.2(b)), because the licensee failed to incorporate existing industry OE to ensure procedural guidance was adequate for testing of the main contactor. (Section 4OA5.6)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,

Criterion III, Design Control, for the failure to ensure that design control measures for field changes impacting the support of station battery cables were commensurate with those applied to the original design requirements. The licensee entered this problem into their corrective action program as condition report 358461.

The inspectors determined that the failure to adhere to the requirements of Criterion III for field changes involving the support of station battery cables was a performance deficiency (PD). This PD had a credible impact on safety due to an increase in battery post loading not analyzed by the vendor for a seismic event impacting the unsupported cables. The PD was more than minor, because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences and the related attribute of design controls due to changes made to battery cable supports which created a condition adverse to quality. In accordance with NRC Inspection Manual Chapter (IMC) 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined that the finding was of very low significance (Green) because the design deficiency did not result in the loss of functionality. The finding had no cross-cutting aspects because it is not indicative of current licensee performance. (Section 4OA5.4)

Green.

A Green, non-cited violation of 10 CFR 50, Appendix B, Criterion XVI,

"Corrective Action," was identified by the NRC for failure to promptly identify and correct a condition adverse to quality regarding fatigued fuse clips associated with safety-related breakers. The licensee entered this problem into their corrective action program as condition report 400128.

The inspectors determined that the failure to promptly initiate corrective actions for fatigued fuse clips was a performance deficiency (PD) which resulted in two safety-related breaker failures. The inspectors reviewed IMC 0612, Appendix B, and determined the PD was more than minor because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and the related attribute of design control for the initial structure, system, component design.

In accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, the inspectors performed a Phase 1 analysis and determined that the finding was of very low significance because the finding was not a design deficiency, did not represent a loss of safety function and did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event. This finding involved the cross-cutting area of problem identification and resolution, the component of the corrective action program, and the aspect of thorough evaluation of problems such that resolutions address extent of condition,

P.1(c), because the licensee failed to initiate adequate corrective actions to address extent of condition for fatigued fuse clips. (Section 4OA2.2)

Cornerstone: Barrier Integrity

Green.

A non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," was identified by the inspectors for two examples of the failure to promptly identify and correct a condition adverse to quality present in the actuator diaphragms of 1-CH-HCV-1200C, letdown orifice isolation, and 1-RC-PCV-1456, reactor coolant system (RCS) pressurizer power operated relief valve (PORV). The licensee entered these problems into their corrective action program as condition reports 355000 and 387916.

The inspectors determined that the failure to promptly correct conditions adverse to quality for 1-CH-HCV-1200C and 1-RC-PCV-1456 was a performance deficiency (PD). The NRC Enforcement Manual allows for the grouping of multiple examples of the same violation during an inspection period and the assignment of an issue to that example which is most significant. The inspectors determined that the second example, involving 1-RC-PCV-1456, was the more significant issue. The inspectors reviewed IMC 0612, Appendix B and determined the finding was more than minor because it affected the Barrier Integrity cornerstone objective of providing reasonable assurance that physical design barriers (e.g. RCS) protect the public from radionuclide releases caused by accidents or events. Specifically, the pressurizer PORVs provide protection to the RCS by preventing brittle fracture at low temperature conditions and protect RCS integrity at high temperature conditions.

The inspectors reviewed IMC 0609, Attachment 4 and determined that since the finding involved a degradation of the Barriers Cornerstone, specifically the RCS barrier, a phase 3 analysis was required. The NRCs SPAR model was utilized to assess the risk significance of the finding modeling the impact of an increased likelihood of failing-to-open. The analyst calculated new failure probabilities for the Unit 1 PORVs (1-RC-PCV-1455C/1456) based on actual/observed failures of the valves. The analyst confirmed that the other valves affected by the performance deficiency (e.g., loop drain valves) were of negligible risk significance and were not included in the North Anna SPAR model. The dominant sequences were transients where a loss of the Condensate Storage Tank occurs and one/both of the PORVs fail to open when called upon, in order to initiate feed and bleed, subsequently leading to core damage. The analyst determined that the risk increase in core damage frequency was <1E-6 per year, a finding of very low safety significance,

Green.

The cause of this finding involved the cross-cutting area of problem identification and resolution, the component of corrective action program, and the aspect of implementation of corrective action (P.1(d)), because the licensee failed to correct the safety issue that existed with 1-RC-PCV-1456 in a timely manner, commensurate with its safety significance and complexity. (4OA5.5)

Licensee Identified Violations

A violation of very low safety significance, which was identified by the licensee, was 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 in a planned refueling outage which started on September 12, 2010.

Unit 1 returned to Rated Thermal Power (RTP) on November 4, 2010, and operated at or near full RTP for the remainder of the report period.

Unit 2 began the inspection period in a forced outage which started on September 29, 2010, and returned to full RTP operation on October 20, 2010. The unit experienced another forced shutdown on November 6, 2010, and returned to full RTP operation on November 9, 2010, and operated at or near full RTP for the remainder of the report period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

==

.1 Seasonal Susceptibilities (cold)

a. Inspection Scope

The inspectors reviewed the licensees adverse weather preparations for cold weather operations specified in 0-GOP-4.2, Extreme Cold Weather Operations, Revision 31, and 0-GOP-4.2A, Extreme Cold Weather Daily Checks, Revision 7, and the licensees corrective action data base for cold weather related issues. The inspectors walked down the two risk-significant areas listed below to verify compliance with procedural requirements and to verify that the specified actions provided the necessary protection for the applicable structures, systems, or components (SSCs). The inspectors reviewed the licensees corrective action program (CAP) database to verify that weather related problems due to temperature were being identified at the appropriate level, entered into the CAP, and appropriately resolved.

• Unit 1 and 2 Emergency Diesel Generator (EDG) Rooms

• Unit 1 and 2 Refueling Water Storage Tanks

b. Findings

No findings were identified.

.2 Site Specific Event

a. Inspection Scope

The inspectors performed two site specific weather related inspections due to anticipated adverse weather conditions. The inspectors reviewed licensee adverse weather response procedures and site preparations including work activities that could impact the overall maintenance risk assessments.

• On October 27, 2010, the licensee entered into 0-AP-41, Severe Weather Conditions, Revision 51, as the plant and dam area were put under a tornado watch.

• On November 30, 2010, the licensee responded to a hazardous weather forecast associated with an approaching cold front with high winds.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

==

.1 Partial Walkdowns

a. Inspection Scope

The inspectors conducted five 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.

• Unit 1 1-RS-P-3B and related support components during maintenance on 1-RS-P-3A

• Unit 2 2H EDG during emergent work on Unit 2 2J EDG

• Unit 1 1-HV-FL-3A during planned maintenance on 1-HV-FL-3B

• A Train casing cooling during planned maintenance work on the B Train

• A Train chemical addition to RWST during emergent work on 2-QS-MOV-202B

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown and inspection of the Unit 2 Casing Cooling System to assess proper alignment and to identify discrepancies that could impact its availability and functional capacity. The inspectors assessed the physical condition and position of each casing cooling valve, whether manual, power operated or automatic to ensure correct positioning of the valves. The inspection also included a review of the alignment and the condition of support systems including fire protection, room ventilation, and emergency lighting. Equipment deficiency tags were reviewed and the condition of the system was discussed with the engineering personnel. Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified.

==1R05 Fire Protection

==

.1 Fire Protection - Tours

a. Inspection Scope

The inspectors conducted tours of the four 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 001, Fire Protection/Appendix R (Fire Safe Shutdown) Program, CM-AA-FPA-101, Control of Combustible and Flammable Materials, Revision 002, and CM-AA-FPA-102, Fire Protection and Fire Safe Shutdown Review and Preparation Process and Design Change Process, Revision 000. 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.

• Containment Unit 1 (fire zone 1-1a / RC-1)

• Turbine Building (includes Chiller Rooms and Z-21B, Z021C, A-22, Z-34, Z-35, Z-46B) and Turbine Building Lube Oil Room (fire zone 8a / TB and TB-LOR)

• Charging Pump Cubicle 1-1A (fire zone 11Aa / CPC-1A), Charging Pump Cubicle 1-1B (fire zone 11Ba / CPC-1B), Charging Pump Cubicle 1-1C (fire zone 11Ca / CPC-1C), Charging Pump Cubicle 2-1A (fire zone 11Da / CPC-2A, Charging Pump Cubicle 2-1B (fire zone 11Ea / CPC-2B), and Charging Pump Cubicle 2-1C (fire zone 11Fa / CPC-2C)

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

b. Findings

Units 1 and 2 Appendix R Fire Protection for RCS Instrumentation in Containment

Introduction:

A URI was identified by the inspectors relating to an issue involving Appendix R fire protection for containment instrumentation on Units 1 and 2.

Description:

The licensee initiated CR396368 and CR397441 for Units 1 and 2 respectively to document resident inspector concerns regarding radiant heat shields used for Appendix R fire protection features associated with reactor coolant system (RCS) pressurizer level and pressure transmitters and respective cabling located within containment. The concerns were related to adequate protection from an exposure fire which can involve either in situ or transient combustibles.

The inspectors require additional information from the licensee to determine if there is a performance deficiency which is greater that minor. This issue is identified as URI 05000338, 339/2010005-01, Appendix R Fire Protection for RCS Instrumentation in Containment.

.2 Fire Protection - Drill Observation

a. Inspection Scope

During a fire protection drill on November 18, 2010, at the station records building the inspectors assessed the timeliness of the fire brigade in arriving at the scene, the fire-fighting 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.

b. Findings

No findings were identified.

==1R06 Flood Protection Measures

==

.1 Internal Flooding

a. Inspection Scope

The inspectors assessed the internal flooding vulnerability of the Unit 1 and 2 Cable Vault / Cable Tunnel / Emergency Switchgear Room interfaces with respect to adjacent safety-related areas to verify that the flood protection barriers and equipment were being maintained consistent with the UFSAR. The licensees corrective action documents were reviewed to verify that corrective actions with respect to flood-related items identified in condition reports were adequately addressed. The inspectors conducted a field survey of the selected areas to evaluate the adequacy of flood barriers, and floor drains to protect the equipment, as well as their overall material condition.

b. Findings

No findings were identified.

.2 Cables in Manholes/Underground Bunkers

a. Inspection Scope

The inspectors performed an annual review of cables located in underground bunkers/manholes. The inspectors evaluated, as appropriate, the two bunkers/manholes listed below for the following:

(1) verified by direct observation that the cables were not submerged in water,

(2) verified by direct observation that cables and/or splices appeared intact,

(3) verified that drainage or an appropriate dewatering device (sump pump) was in operation; and

(4) verified that level alarm circuits were set appropriately to ensure that the cables would not be submerged.

• 01-SEC-MH-VAM-H-2

• 01-BLD-MBAR-SWTV5

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification Program

==

.1 Quarterly Resident Inspector Observations

a. Inspection Scope

The inspectors observed an operator requalification simulator exam which involved a steam generator (SG) tube leak, uncontrolled rod motion, an SG tube rupture and a failure of a pressurizer power operated relief valve to close. 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.

b. Findings

No findings were identified.

.2 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On February 5, 2010, the licensee completed the annual requalification operating tests required to be administered to all licensed operators in accordance with 10 CFR 55.59(a)(2). The inspectors performed an in-office review of the overall pass/fail results of the individual operating tests and the crew simulator operating tests. These results were compared to the thresholds established in Manual Chapter 609 Appendix I, Operator Requalification Human Performance Significance Determination Process.

b. Findings

No findings were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

For the three equipment issues listed below, the inspectors evaluated the effectiveness of the respective licensee's preventive and corrective maintenance and related maintenance rule evaluations (MRE). 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.

• CR403015, 2-EE-EG-2J governor oil inadvertently drained during insulation work

• MRE012619, 1-CH-TV-1204A closed during SI functional due to jumper being bumped

• MRE012105, Tap changer for A Reserve Station Service Transformer failed

b. Findings

The enforcement aspects related to CR403015 are discussed in section 4OA7 of this report.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

The inspectors evaluated, as appropriate, the six 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.

• Entry into 0-AP-8, Response to Grid Instability, Revision 7, due to potential for low offsite power voltage condition to exist in the event of a grid disturbance

• Emergent work on main feedwater pump 1-FW-P-1C due to leak identified on suction relief valve 1-FW-RV-102A

• Emergent work for Unit 1 B loop T-hot failing low

• Emergent work for 2J EDG involving Woodward governor oil inadvertently drained during insulation work

• Forced Unit 2 shutdown due to excessive main generator hydrogen leakage

• Emergent entry into 0-AP-41, Severe Weather Conditions, Revision 51, for a tornado watch issued for Louisa County Virginia on 12/1/2010

b. Findings

No findings were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed four 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.

• OD000399, "Determine Operability of 1-FW-P-2 with Slight Leakby of 1-MS-TV-111B"

• OD000386, Operability Determination for Rod Bow Phenomenon

• OD000391, Determine Operability of 2H EDG at Low Loads

• OD000392, Pipe Support on Unit 1 A Seal Injection Line not in Contact with Bottom of Pipe

b. Findings

No findings were identified.

==1R18 Plant Modifications

==

.1 Temporary Modifications

a. Inspection Scope

The inspectors reviewed 2-PT-57.4, Safety Injection Operational Test, Revision 54, PCTM for jumper installation to verify that the modification did not affect systems operability or availability as described by the TS and UFSAR. In addition, the inspectors verified that the temporary modification was in accordance with VPAP-1403, Temporary Modifications, Revision 13, and CM-AA-TDC-204, Temporary Modifications, Revision 000, and for the related work package, that adequate controls were in place, procedures and drawings were updated, and post-installation tests verified the operability of the affected systems.

b. Findings

No findings were identified.

.2 Permanent Modifications

a. Inspection Scope

The inspectors reviewed the completed permanent plant modification design change package (DCP) NA 05-108, Replace RSST Load Tap Changers/NAPS/Units 1 and 2.

The inspectors conducted a walkdown of the installation, discussed the desired improvement with system engineers, and reviewed the 10 CFR 50.59 Safety Review/Regulatory Screening, technical drawings, test plans and the modification package to assess the TS implications.

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 13.

• WO 59102183558, Perform modification to support 1-CH-PH-R-96.40

• WO 59080099001, 1-RC-HCV-1557A Actuator diaphragm replacement

• WO 59102221433, Replace motor in association with Design Change NA-10-00162

• WO 59102209746, Inspect/Rebuild operator due to over thrust

• WO 59102233358, Restore oil level in 2J EDG Woodward governor

b. Findings

No findings were identified.

==1R20 Refueling and Other Outage Activities

==

.1 Unit 1 Refueling Outage Completion

a. Inspection Scope

The inspectors reviewed the Outage Safety Review (OSR) and contingency plans for the Unit 1 refuelling outage, which began September 12, 2010, 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 Inspection procedure 71111.20, Refueling and Outage Activities, to observe portions of the refuelling, maintenance activities, and startup activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk plan and applicable TS. The inspectors monitored licensee controls over the outage activities listed below.

• Licensee configuration management, including daily outage reports, to evaluate maintenance of defense-in-depth commensurate with the OSR 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 and an accounting for instrument error.

• Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities.

• 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.

• Refueling activities, including fuel handling and sipping to detect fuel assembly.

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

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

b. Findings

No findings were identified.

.2 Unit 2 Forced Outage

a. Inspection Scope

The inspectors continued their review of the OSR and related contingency plans for the Unit 2 forced outage, which began September 29, 2010, 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 Inspection procedure 71111.20, Refueling and Outage Activities, to observe portions of the maintenance and startup activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk plan and applicable TS.

The inspectors monitored licensee controls over the outage activities listed below.

• Licensee configuration management, including daily outage reports, to evaluate maintenance of defense-in-depth commensurate with the OSR 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.

• Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities.

• Controls over activities that could affect reactivity.

• Startup and ascension to full power operation, tracking of startup prerequisites, and walkdown of the primary containment to verify that debris had not been left which could block emergency core cooling system strainers..

• Licensee identification and resolution of problems related to forced outage activities.

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-71.1Q, 1-FW-P-2 Turbine Driven Auxiliary Feedwater Pump and Valve Test, Revision 55 RCS Leakage:

• 1-PT-52.2A, Reactor Coolant System Leak Rate (Computer Calculation), Revision Other Surveillance Tests:

• 2-PT-82,2A, 2H Diesel Generator Test (Simulated Loss of Offsite Power), Revision

• 2-PT-82H, 2H Emergency Diesel Generator Slow Start Test, Revision 30

Containment Isolation Valve:

• 1-PT-61.3.1, Unit 1 Containment Type C Test, Revision 32

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

Simulator Drill

a. Inspection Scope

On November 2, 2010, the inspectors observed a licensee simulator based training session that involved a steam generator tube rupture and failure of a pressurizer power operated relief valve (PORV) to close which required an Alert to be declared. The inspectors assessed emergency procedure usage, emergency plan classification, notification, and the licensees identification and entrance of any problems into their CAP. These inspections evaluated the adequacy of the licensees conduct of the drill and critique performance. There were no drill issues requiring a condition report.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational Radiation Safety and Public Radiation Safety

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). The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, hot particles, airborne radioactivity, gamma surveys with a range of dose rate gradients, and pre-job surveys for selected Unit 1 (U1) Refueling Outage (RFO) work activities. The inspectors also discussed with cognizant licensee representatives changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected U1 RFO 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 Unit 1 (U1) and Unit 2 (U2) Locked HRA and Very HRA locations. Changes to procedural guidance for Locked HRA and Very HRA controls were discussed with selected Radiation Protection (RP) supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool (SFP) were reviewed and discussed in detail with cognizant licensee representatives. 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 plant shutdown and U1 refueling operations were reviewed and discussed.

Occupational workers adherence to selected RWPs and RP Technician (RPT)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 for selected U1 RFO activities. ED alarm logs were reviewed and worker response to dose and dose rate alarms during selected work activities was evaluated. For HRA tasks involving significant dose rate gradients, the inspectors evaluated the use and placement of whole body and extremity dosimetry to monitor worker exposure.

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 reviewed records for selected release point survey instruments and discussed equipment sensitivity, alarm setpoints, and release program guidance with cognizant licensee staff. The inspectors compared recent 10 Code of Federal Regulations (CFR) Part 61 results for the Dry Active Waste (DAW) radioactive waste (radwaste) 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 cognizant licensee staff.

Problem Identification and Resolution. Condition Reports (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, Revisions 12 - 15. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

RP activities were evaluated against the requirements of UFSAR Section 12; TS Sections 5.4 and 5.7; 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 to this report.

The inspectors completed all specified line-items detailed in inspection procedure (IP)71124.01 (sample size of 1).

b. Findings

No findings were identified.

2RS2 As Low As Reasonably Achievable (ALARA)

a. Inspection Scope

ALARA Program Status: The inspectors reviewed and discussed with cognizant licensee representatives, plant exposure history and current trends including the sites Three-Year Rolling Average (TYRA) collective exposure history for calendar year (CY)2007 through CY 2009. Current and proposed activities to manage site collective exposure and trends regarding collective exposure were evaluated through review of previous TYRA collective exposure data and review of the licensees ALARA program implementing plan. Current ALARA program guidance and recent changes, as applicable, regarding estimating and tracking exposure were discussed with cognizant licensee representatives and evaluated.

Radiological Work Planning: The inspectors reviewed planned work activities and their collective exposure estimates for the current U1 refueling outage (RFO). Work activities, exposure estimates and mitigation activities were reviewed for the following high collective exposure tasks: U1 reactor head lift, U1 seal table work, U1 pressurizer work, U1 eddy current testing, and U2 containment entry for Microtherm insulation inspection.

For the selected tasks, the inspectors reviewed dose mitigation actions and established dose goals. During the inspection, use of remote technologies including teledosimetry and remote visual monitoring were verified as specified in RWP or procedural guidance.

Current collective dose data for selected tasks were compared with established estimates and, where applicable, changes to established estimates were discussed with responsible licensee ALARA planning representatives. The inspectors reviewed previous post-job reviews conducted for the U2 RFO and verified that the items were entered into the licensees Corrective Action Program for evaluation.

Verification of Dose Estimates and Exposure Tracking Systems: The inspectors reviewed select ALARA work packages and discussed assumptions with responsible planning personal regarding the bases for the current estimates. The licensees on-line RWP cumulative dose data bases used to track and trend current personal and cumulative exposure data and/or to trigger additional ALARA planning activities in accordance with current procedures were reviewed and discussed. Selected work-in-progress reviews and adjustments to cumulative exposure estimate data were evaluated against work scope changes or unanticipated elevated dose rates.

Source Term Reduction and Control: The inspectors reviewed historical dose rate trends for shutdown chemistry, cleanup, and resultant chemistry and radiation protection trend-point data against the current U1 RFO data. Licensee actions to mitigate noble gas and iodine exposures resulting from fuel leaks were discussed with cognizant licensee representatives.

Problem Identification and Resolution: The inspectors reviewed and discussed selected CRs associated with ALARA program implementation. The reviewed items included CRs, self-assessments, and quality assurance audit documents. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with licensee procedure, PI-AA-200, Corrective Action, Revisions 12 - 15.

The licensees ALARA program activities and results were evaluated against the requirements of UFSAR Section 12; TS Sections 5.4 and 5.7; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Sections 2RS1 and 2RS2 of the Attachment to this report.

Radiation worker performance was reviewed as part of observations conducted for IP 71124.01 and is documented in Section 2RS1. The inspectors completed all specified line-items detailed in IP 71124.02 (sample size of 1).

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls: The inspectors reviewed the use of temporary and permanent engineering controls to mitigate airborne radioactivity inside U1 containment during the 2010 fall refueling outage. The inspectors observed the use of Negative Pressure Units (NPUs) and cavity covers (tenting) to control contamination during activities in the reactor cavity and transfer canal and reviewed NPU testing records. Use of containment purge to reduce airborne levels in general areas was reviewed. The inspectors evaluated the effectiveness of continuous air monitors and air samplers placed in work area breathing zones to provide indication of increasing airborne levels.

Respiratory Protection Equipment: The inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material. This included review of devices used for routine tasks and devices stored for use in emergency situations. The inspectors reviewed ALARA evaluations for the use of respiratory protection devices during reactor head removal. Selected Self-Contained Breathing Apparatus (SCBA)units and Negative Pressure Respirators (NPRs) staged for routine and emergency use in the Main Control Room and other locations were inspected for material condition, SCBA bottle air pressure, number of units, and number of spare masks and air bottles available. The inspectors reviewed maintenance records for selected SCBA units for the past two years and evaluated SCBA and NPR compliance with National Institute for Occupational Safety and Health certification requirements. The inspectors also reviewed records of air quality testing for supplied-air devices and SCBA bottles.

The inspectors observed the use of powered air-purifying respirators and reviewed training curricula for various types of respiratory protection devices. The inspectors interviewed radworkers and control room operators on use of the devices including SCBA bottle change-out and use of corrective lens inserts. Respirator qualification records (including medical fitness) were reviewed for several Main Control Room operators and emergency responder personnel in the Maintenance and RP departments. In addition, qualifications for individuals responsible for testing and repairing SCBA vital components were evaluated through review of training records.

Licensee activities associated with the use of engineering controls and respiratory protection equipment was reviewed against 10 CFR Part 20; UFSAR Chapter 12; RG 8.15, Acceptable Programs for Respiratory Protection; and applicable licensee procedures. Documents reviewed during the inspection are listed in Section 2RS3 of the report Attachment.

Problem Identification and Resolution: CRs associated with airborne radioactivity mitigation and respiratory protection 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, Revisions 12 - 15. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results. Documents reviewed are listed in Section 2RS3 of the Attachment to this report.

The inspectors completed all specified line-items detailed in IP 71124.03 (sample size of 1).

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

Radiation Monitoring Instrumentation: During tours of the auxiliary building, SFP areas, and RCA exit point, the inspectors observed installed radiation detection equipment including the following instrument types: Area Radiation Monitors (ARMs), Continuous Air Monitors (CAMs), liquid and gaseous effluent monitors, Personnel Contamination Monitors (PCMs), Small Article Monitors (SAMs), and portal monitors. The inspectors observed the physical location of the components, noted the material condition, and compared sensitivity ranges with UFSAR requirements.

In addition to equipment walk-downs, the inspectors observed source checks and alarm setpoint testing of various portable and fixed detection instruments, including ion chambers, telepoles, PCMs, SAMs, and portal monitors. For the portable instruments, the inspectors observed the use of a high-range calibrator and discussed periodic output value testing with a health physics technician. The inspectors reviewed the last two calibration records and evaluated alarm setpoint values for selected ARMs, PCMs, portal monitors, SAMs, effluent monitors, and a WBC. This included a sampling of instruments used for post-accident monitoring such as containment high-range ARMs and effluent monitor high-range noble gas and iodine channels. Radioactive sources used to calibrate selected ARMs and effluent monitors were evaluated for traceability to national standards. Calibration stickers on portable survey instruments and air samplers were noted during inspection of storage areas for Aready-to-use@ equipment. The most recent 10 CFR Part 61 analysis for DAW was reviewed to determine if calibration and check sources are representative of the plant source term. The inspectors also reviewed countroom quality assurance records for gamma ray spectrometry equipment and liquid scintillation detectors.

Effectiveness and reliability of selected radiation detection instruments were reviewed against details documented in the following: 10 CFR Part 20; NUREG-0737, Clarification of TMI Action Plan Requirements; TS Section 3.3.3; UFSAR Chapters 11 and 12; and applicable licensee procedures. Documents reviewed during the inspection are listed in Section 2RS5 of the report Attachment.

Problem Identification and Resolution: The inspectors reviewed selected CRs in the area of radiological instrumentation. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure PI-AA-200, Corrective Action, Revisions 12 - 15. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results. Documents reviewed are listed in Section 2RS5 of the Attachment to this report.

The inspectors completed all specified line-items detailed in IP 71124.05 (sample size of 1).

b. Findings

No findings were identified

4OA1 Performance Indicator (PI) Verification

.1 Safety System Function Failures (SSFF) PI

a. Inspection Scope

The inspectors performed a periodic review of the Safety System Functional Failures PI for both Unit 1 and Unit 2 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 inspection procedure 71151, Performance Indicator Verification. Specifically, the inspectors reviewed the Unit 1 and Unit 2 data reported to the NRC for the period October 1, 2009, through September 30, 2010. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs.

b. Findings

No findings were identified.

.2 Occupational and Public Radiation Safety PIs

a. Inspection Scope

The inspectors sampled licensee data for the PIs listed below. To verify the accuracy of the PI data reported during the period reviewed, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 6, were used to verify the basis for each data element.

Occupational Radiation Safety (ORS) Cornerstone

The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the ORS Cornerstone from July 2009 to June 2010. 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.

Public Radiation Safety (PS) Cornerstone

The inspectors reviewed the Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent Occurrences PI results from July 2009 through June 2010. The inspectors reviewed CAP documents, effluent dose data, and licensee procedural guidance for classifying and reporting PI events. The inspectors also interviewed licensee personnel responsible for collecting and reporting the PI data. Reviewed documents are listed in Section 4OA1 of the Attachment.

The inspectors completed 2 of the required 2 samples for IP 71151.

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 inspection procedure 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 CR367053, No Position Indication of 2-SI-MOV-1863A on Unit 2 Vertical Board

a. Inspection Scope

The inspectors reviewed the licensees assessments and corrective actions for CR367053, No Position Indication of 2-SI-MOV-1863A on Unit 2 Vertical Board, to ensure 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 the CR against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revisions 12 - 15, and 10 CFR 50, Appendix B.

b. Findings and Observations

Inadequate Corrective Action for Fatigued Fuse Clips in Safety-Related Breakers

Introduction:

A Green NCV of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," was identified by the NRC for the failure to promptly correct a condition adverse to quality regarding fatigued fuse clips associated with safety-related breakers.

Description:

On January 29, 2010, during performance of, 2-PT-213.8, Valve Inservice Inspection (A Train of Safety Injection System), Revision 10, 2-SI-MOV-1863A (A low head safety injection pump discharge to charging pump suction valve) failed. The licensee entered this problem into their CAP as CR367053 which also initiated apparent cause evaluation, ACE018012. The inspectors reviewed ACE018012 and noted the following:

• The apparent cause was that the method for checking the continuity of the control power circuit was not clearly specified in the preventative maintenance procedures.

• A contributing cause was fatigue of the fuse block clips due to age degradation.

• The corrective action specified for both the apparent and contributing cause were PM procedure revisions to ensure the continuity check included the fuse block with fuses installed and additional training for the technicians performing the revised procedure.

• The extent of condition review identified that the condition of fatigued fuse clips could exist in other breakers.

The inspectors identified that the continuity check methodology might not fully identify a fatigued fuse clip and that no corrective actions were specified to address safety-related breakers with existing fatigued fuse clips representing a condition adverse to quality.

Consequently, on October 22, 2010, the licensee initiated CR400128 to address these concerns. The inspectors noted the following safety-related breaker failures due to fatigued fuse clip problems during the fourth quarter, 2010:

• 59-01-EE-BKR-1J1-2N-A1-CKTBRK (F CRDM fan circuit)

• 59-02-EE-BKR-2J1-2S-B3-CKTBRK (Chemical addition tank B outlet valve)

The inspectors concluded that the licensee failed to promptly initiate corrective actions to address existing conditions adverse to quality relating to fatigued fuse clips which led to additional safety-related component failures.

Analysis:

The inspectors determined that the failure to promptly initiate corrective actions for fatigued fuse clips was a performance deficiency. The inspectors determined the finding was more than minor because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and the related attribute of design control for the initial SSC design. The inspectors evaluated the finding using the significance determination process and determined that the finding was of very low significance because the finding was not a design deficiency, did not represent a loss of safety function and did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event. This finding involved the cross-cutting area of problem identification and resolution, the component of the corrective action program, and the aspect of thorough evaluation of problems such that resolutions address extent of condition, P.1(c), because the licensee failed to initiate adequate corrective actions to address the extent of condition for fatigued fuse clips.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," states in part that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, the licensee failed to promptly correct a condition adverse to quality regarding fatigued fuse clips associated with safety-related breakers. Because the finding is of very low safety significance and it was entered into the licensees CAP as CR400128, this violation is being treated as a Green NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000338, 339/2010005-02, Inadequate Corrective Action for Fatigued Fuse Clips in Safety-Related Breakers.

.3 Annual Sample:

Review of CR359447, Difference Between Requirements in WM-AA-100 and VPAP-0502, for Closure of URI 05000338, 339/2009005-04, Development of Work Orders

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CR359447, Difference between requirements in WM-AA-100 and VPAP-0502 for development of work orders, to ensure 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 the CR against the requirements of the licensees Correction Action Program as specified in procedure, PI-AA-200, Corrective Action Program, Revisions 12 - 15 and 10 CFR 50, Appendix B.

b. Findings and Observations

No findings were identified. The inspectors had previously opened URI 05000338, 339/2009005-04, Development of Work Orders in NRC Integrated Inspection Report 05000338/2009005 and 05000339/2009005 based on a work order that contained job steps in lieu of a maintenance procedure for a safety related component and that did not have documentation of appropriate technical reviews.

The inspectors reviewed the licensees administrative procedures for controlling work orders and noted that VPAP-0502, Procedure Process Control, Revision 49, required appropriate levels of review for work order instructions whereas WM-AA-100, Work Management, Revision 4, did not. The licensee entered this issue into their CAP as CR359447 on November 24, 2009.

The inspectors reviewed CR359447 and noted that corrective actions were not yet complete. This CR initiated corrective action (CA) 153773 which was assigned to Outage and Planning for review and recommendations. CA153773 initiated the following CAs on February 25, 2010:

• CA161508, Add cross references to WM-AA-100 and VPAP-0502

• CA161509, O&P to work with Planning to develop a Routing Guide

The inspectors noted that CA161508 was closed to CA176387, Work Management (O&P) to provide Mark-ups/input, on August 16, 2010, and was not due until February 25, 2011. CA161509 was closed to another action item, Fleet Project Charter O&P 19 for a new administration procedure, WM-AA-1001, Common Work Order Planning, which has an implementation date of June 11, 2011.

The inspectors had previously expressed a concern regarding the lack of rigor in using WO job steps in lieu of a procedure which was documented on October 25, 2006, in CR003194, Use of work order instructions in lieu of procedures.

The inspectors concluded that even though the corrective actions for ensuring adequate rigor in technical review of work order instructions for safety related equipment had not been timely, the licensee had not experienced a significant consequence. URI 05000338, 339/2009005-04, Development of Work Orders, is closed.

.4 Annual Sample:

Operator Work-around Review

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for operator workarounds (OWAs). The inspectors reviewed the cumulative effects of the licensees OWAs and licensee procedure OP-AA-1700, Operations Aggregate Impact, Revision 2. The inspectors reviewed the data package associated with this procedure which included an evaluation of the cumulative effects of the OWAs on the operators ability to safely operate the plant and effectively respond to abnormal and emergency plant conditions. The inspectors reviewed and monitored licensee planned and completed corrective actions to address underlying equipment issues causing the OWAs. The inspectors also evaluated OWAs against the requirements of the licensees CAP as specified in PI-AA-200, Corrective Action, Revisions 12 - 15, 10 CFR 50, Appendix B, and OP-AA-100, "Conduct of Operations," Revision 10.

b. Findings and Observations

No findings of significance were identified. In general, the inspectors verified that the licensee has identified operator workaround problems at an appropriate threshold, entered them in the corrective action program, and has proposed or implemented appropriate corrective actions.

.5 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees correction action program documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment and corrective maintenance issues but also considered the results of daily inspector corrective action program item screening discussed in Section 4OA2.1. The review included issues documented outside the normal correction action program in system health reports, corrective maintenance work orders, component status reports, site monthly meeting reports, and maintenance rule assessments. The inspectors review nominally considered the six month period of July through December 2010, although some examples expanded beyond those dates when the scope of the trend warranted.

The inspectors compared and contrasted their results with the results contained in the licensees latest integrated quarterly assessment report. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy.

b.

Assessment and Observations

No findings were identified. In general, the licensee has identified trends and has addressed the trends with their corrective action program. However, the inspectors noted an adverse trend for CAP documents regarding issues with reactivity management. Subsequent review of the licensees second and third quarter CAP trend reports verified that the licensee had also identified an adverse trend in this area during the second quarter that the issue was captured in CR386083, and removed from the trend report during the third quarter. The inspectors reviewed procedure OP-AA-300, Reactivity Management, Revision 11. The inspectors identified several CRs that documented reactivity management concerns during the third and fourth quarters.

Specifically, the inspectors identified the following CRs regarding reactivity management:

• CR405718, High level divert valve is leaking by 1-SD-LCV-107A

• CR405192, U-1 blender make-ups resulting in power increases

• CR397710, Boric acid flow to the Unit 1 blender is indicating erratically

• CR394337, Air leak on 1-CH-FCV-1113B, boric acid blender VCT flow control valve

• CR391719, Slight VCT level increase while stroking 1-SI-MOV-1863B per 1-PT-213.8B

• CR390517, 2-SD-TK-1B, Normal level control valve fully opened and emptied tank

• CR389664, B S/G High capacity blow down valve (2-BD-TV-200D) tripped closed on high flow

The inspectors verified that the licensee had identified the trend and placed this issue in their CAP as CR409474.

4OA3 Event Followup

(Closed) Licensee Event Report (LER) 05000338/2010-002-00: Forced Shutdown due to Un-Isolable C Steam Generator Surface Sample Line Leakage

On July 14, 2010, with Unit 1 operating in Mode 1 at 100% power, the licensee entered TS 3.4.4 due to the declaration of inoperability for the C RCS loop following the discovery of un-isolable leakage of approximately

.263 gpm on the C SG secondary

sample line which forced a TS required shutdown. The cause of the leakage was external corrosion from moisture collection in the external insulation for the carbon steel pipe. The licensee entered this problem in their CAP as CR387863, performed extent of condition for the other SGs resulting in the replacement of piping sections, and subsequently developed additional CAP actions or Unit 2. This LER is closed.

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 verified by direct observation, or review of selected records, that the licensee had identified fuel assemblies placed in the Independent Spent Fuel Storage Installation (ISFSI). The inspectors verified that the parameters and characteristics of each fuel assembly were recorded, and that a record of each fuel assembly was made as a controlled document. This inspection was performed in parallel with inspection procedure 71130.11 documented in a NRC inspection report 05000338, 339/2010-404.

b. Findings

No findings were identified

.3 (Closed) Temporary Instruction (TI) 2515/179 Verification of Licensee Responses to

NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System (NSTS) Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

a. Inspection Scope

The inspectors performed the TI concurrent with IP 71124.01 Radiation Hazard

Analysis.

The inspectors reviewed the licensees source inventory records and identified the sources that met the criteria for reporting to the NSTS. The inspectors visually identified the sources contained in various calibration systems and verified the presence of the source by direct radiation measurement using a calibrated portable radiation detection survey instrument. The inspectors reviewed the physical condition of the irradiation devices to include documented source leak checks as appropriate. The inspectors reviewed the licensees procedures for source receipt, maintenance, transfer, reporting and disposal. The inspectors reviewed documentation that was used to report the sources to the NSTS. Documents reviewed are listed in Sections 2RS1 of the

.

b. Findings

No findings were identified. TI 2515/179 is complete for this licensee.

.4 (Closed):

URI 05000338, 339/2009005-03, Units 1 and 2 Station Battery Cable Installation Issues

Introduction:

The inspectors had previously opened URI 05000338, 339/2009005-03, Units 1 and 2 Station Battery Cable Installation Issues, in NRC Integrated Inspection Report 05000338/2009005 and 05000339/2009005, based on cable installation that did not appear to meet vendor installation requirements. The inspectors identified a Green, NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the failure to ensure that design control measures for field changes impacting the support of station battery cables were commensurate with those applied to the original design requirements.

Description:

On November 17, 2009, the inspectors identified issues involving installation of cabling associated with the emergency DC bus station batteries on Units 1 and 2. Specifically, the inspectors noted that the vendor manual, NA-VTM-000-59-E141-00001, Station Batteries, Revision 6, section 7.4.3, step 7 stated in part to support cables so that the cell posts do not bear the load. The inspectors reviewed an earlier version of the manual to verify that the same requirement existed and found that Section 58, step 8.m had to same requirement. Additionally, the vendor was contacted for the justification for this statement and responded that they did not have calculations to identify a load limit. Therefore, for seismic testing and installation purposes, the vendor required and specified adequate support for the battery cables for battery installations.

The inspectors noted that the licensee installed the batteries in 1985 under the following modifications, design changes (DC) 85-29 for Unit 1, 85-30-2 Unit 2 batteries 2-I, 2-II and 2-III, and in 1992 under DC 92-017-2 for Unit 2 battery 2-IV, and that the DCs contained instructions that required the installation of supports as necessary to restrain and support the battery cables. The batteries and racks were supplied by Enersys and came with a seismic certificate of compliance indicating the successful completion of seismic testing in accordance with IEEE requirements. The batteries were subsequently replaced between September 23, 2001, and September 24, 2004, under the licensees work order process. The inspectors reviewed the work order packages for information that would demonstrate a change to the existing support design and no changes were identified. Additionally, the licensee was not able to produce any design documentation that showed a change to the existing cable support configurations.

The inspectors concluded that the change in battery cable support configurations constituted a field change for which the design control measures were not commensurate with those of the original design as required by 10 CFR 50, Appendix B, Criterion III.

Analysis:

The inspectors determined that the failure to adhere to the requirements of 10 CFR 50, Appendix B, Criterion III for field changes involving the support of station battery cables was a performance deficiency (PD). This PD had a credible impact on safety due to an increase in battery post loading not analyzed by the vendor for a seismic event impacting the unsupported cables. The PD was more than minor, because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences and the related attribute of design controls due to changes made to battery cable supports which created a condition adverse to quality. In accordance with NRC Inspection Manual Chapter (IMC) 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined that the finding was of very low significance (Green) because the design deficiency did not result in the loss of functionality. The finding had no cross-cutting aspects because it is not indicative of current licensee performance.

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control, requires in part that design changes, including field changes, shall be subject to design control measures commensurate with those applied to the original design and be approved by the organization that performed the original design. Contrary to this, on November 17, 2009, the licensee failed to ensure that design control measures for field changes impacting the support of station battery cables were commensurate with those applied to the original design requirements. Because this finding is of very low safety significance and because it was entered in the licensees corrective program as CR358461, this violation is being treated as an NCV consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000338, 339/2010005-03, Inadequate Design Control Measures for Field Changes Affecting Station Battery Cables.

.5 (Closed):

Apparent Violation (AV)05000338/2010004-03, Failure to Promptly Correct Conditions Adverse to Quality for Valve Actuator Diaphragms

Introduction:

The inspectors had previously opened AV 05000338/2010004-02, Failure to Promptly Correct Conditions Adverse to Quality for Valve Actuator Diaphragms in NRC Integrated Inspection Report 05000338/2010004. A Green NCV of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," was identified by the inspectors for two examples of the failure to promptly identify and correct a condition adverse to quality present in the actuator diaphragms of 1-CH-HCV-1200C and 1-RC-PCV-1456.

Description:

The first example occurred on October 26, 2009 when the licensee identified air leaking from the actuator diaphragm of 1-CH-HCV-1200C and initiated CR354854, Air leaking from diaphragm while stroking 1-CH-HCV-1200C and CR355000, Failed diaphragm found torn at bolt holes to document the condition. The second example occurred on July 15, 2010, when pressurizer PORV, 1-RC-PCV-1456, failed to open on demand and the licensee initiated CR387916, 1-RC-PCV-1456 failed to open with key switch in open to document the condition. At the time of their failure each of these valve actuators were in the licensees CAP as requiring diaphragm replacement due to the presence of improperly drilled actuator bolt holes and overtorqued actuator casing bolts.

The licensee had previously experienced an air operated valve (AOV) diaphragm failure in March 2009 with the failure of 1-RC-PCV-1455C due, in part, to improperly drilled actuator bolt holes and overtorqued actuator casing bolts. The failure of 1-RC-PCV-1455C and the technical aspects of improperly drilled actuator bolt holes and overtorqued actuator casing bolts are discussed in NRC integrated inspection report 05000338, 339/2009003. The inspectors reviewed licensee ACE017534, ACE to Eng to investigate the failed 1-RC-PCV-1455C diaphragm and OD000283, Create OD to document the operability of associated components, Revisions 0, 1, 2, and 3.

OD000283 was revised following each of the subsequent AOV diaphragm failures. The inspectors also reviewed Root Cause Evaluation (RCE) 01021, 1-RC-PCV-1456 diaphragm failure. The inspectors determined that 1-CH-HCV-1200C and 1-RC-PCV-1456 were identified in April 2009 as having an actuator diaphragm with additional bolt holes drilled and overtorqued casing bolts. The inspectors also determined that each failure was the result of overtorqued casing bolts or the drilling of additional bolt holes.

The inspectors concluded that the presence of a drilled, overtorqued actuator diaphragm in 1-CH-HCV-1200C and 1-RC-PCV-1456 were known conditions adverse to quality.

The inspectors also concluded that the licensee failed to promptly correct this condition adverse to quality, as required by 10 CFR 50, Appendix B, Criterion XVI, and that this resulted in the failure of 1-CH-HCV-1200C and 1-RC-PCV-1456.

Analysis:

The inspectors determined that the failure to promptly correct conditions adverse to quality for 1-CH-HCV-1200C and 1-RC-PCV-1456 was a performance deficiency. The NRC Enforcement Manual allows for the grouping of multiple examples of the same violation during an inspection period and the assignment of an issue to that example which is most significant. The inspectors determined that the second example, involving 1-RC-PCV-1456, was the more significant issue. The inspectors reviewed IMC 0609, Appendix B, and determined that the finding was more than minor because it affected the Barrier Integrity cornerstone objective or providing reasonable assurance that physical design barriers (e.g. RCS) protect the public from radionuclide releases caused by accidents or events. Specifically, RCS equipment and barrier performance, in that the pressurizer PORVs provide protection to the RCS by preventing brittle fracture at low temperature conditions and protect RCS integrity at high temperatures. The inspectors reviewed IMC 0609, Attachment 4, and determined that since the finding involved a degradation of the Barrier Cornerstone, specifically the RCS barrier, a phase 3 analysis was required.

The NRCs SPAR model was utilized to assess the risk significance of the finding modeling the impact of an increased likelihood of failing-to-open. The analyst calculated new failure probabilities for the Unit 1 PORVs (1-RC-PCV-1455C/1456) based on actual/observed failures of the valves. The analyst confirmed that the other valves affected by the performance deficiency (e.g., loop drain valves) were of negligible risk significance and were not included in the North Anna SPAR model. The dominant sequences were transients where a loss of the Condensate Storage Tank occurs and one/both of the PORVs fail to open when called upon, in order to initiate feed and bleed, subsequently leading to core damage. The analyst determined that the risk increase in core damage frequency was <1E-6 per year, a finding of very low safety significance, Green. The cause of this finding involved the cross-cutting area of problem identification and resolution, the component of corrective action program, and the aspect of implementation of corrective action (P.1(d)), because the licensee failed to correct the safety issue that existed with 1-RC-PCV-1456 in a timely manner, commensurate with its safety significance and complexity.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," states, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, on July 15, 2010, the licensee failed to promptly correct a known condition adverse to quality involving 1-RC-PCV-1456 which resulted in the failure of the valve to open on demand. Because the finding is of very low safety significance (Green) and it was entered into the licensees CAP as CR354854, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000338/2010005-04, Failure to Promptly Correct Conditions Adverse to Quality for Valve Actuator Diaphragms.

.6 (Closed):

FIN - TBD 05000338/2010004-07, Failure to Maintain PM Procedures for Circuit Breakers Current with Industry Information and OE

Introduction:

The inspectors had previously opened FIN - TBD 05000338/2010004-07, Failure to Maintain PM Procedures for Circuit Breakers Current with Industry Information and OE, in NRC Integrated Inspection Report 05000338/2010004, 05000339/2010004, based on a fire in a safety related breaker cubicle. A Green, self-revealing finding was identified for the failure to maintain PM procedures for circuit breakers current with industry information and OE, as required by procedure, DNAP-2001, Equipment Reliability Process, Revision 0.

Description:

On April 22, 2009, a licensee operator, who was escorting several fire watch personnel to instruct them on which areas to patrol due to the removal from service of area fire detectors, noticed an odor from an electrical fire located in the Unit 1 cable vault area. The source of the fire was located at the safety-related breaker cubicle, 01-EE-BKR-1J1-2S-J1, for D control rod drive mechanism (CRDM) fan. The operators obtained a carbon dioxide (CO2) fire extinguisher, opened the cubicle and observed flame and smoke, and extinguished the fire with CO2. A visual examination of the breaker revealed that the molded case circuit breaker (MCCB) and main contactor had experienced the most damage.

The licensee initiated CR331819 and the associated RCE 000976 in accordance with their CAP. A vendor examination of the breaker components was also performed to determine the cause of the fire and was completed in December 2009. The inspectors reviewed RCE000976 and respective vendor analysis and found the following information:

• The direct cause of the fire was overheating of the main contactor coil due to age related insulation degradation between the windings of the coil. This component was original equipment and in service approximately 35 years.

• The root cause was a failure to implement an appropriate preventative maintenance (PM) program for replacement of main contactors (also known as motor starters) and the contributing cause was a lack of appropriate predictive maintenance.

• The historical, similar breaker events involving a fire had no failures associated with the age-related failure of a main contactor.

• The extent of cause involves all coils installed for greater than 35 years and includes breakers of other manufacturers installed in the plant.

The inspectors performed an independent review of historical events to determine if there were other opportunities for the licensee to previously identify problems with age related failure of main contactor coils. The inspectors identified Plant Issue N-2006-1877 which documented an event on March 31, 2006, involving smoke coming from non-safety related breaker cubicle, 1-EP-MCC-1C2-2-B1-CKTBRK, for turbine building exhaust fan, 1-HV-F-29J, and the activation of the stations fire brigade.

Troubleshooting determined the failure was a burned coil in the 52 relay or main contactor. The inspectors noted the cause was documented as normal age related degradation, and there were no additional corrective actions because enhancements to PM procedures had added numerous detailed inspections of all components in the modules. The inspectors reviewed the following licensee program procedures for information concerning the establishment and maintenance of PM procedures.

Licensee procedure, ER-AA-BKR-1001, effective April 5, 2007, contains the following information: Step 3.2.1 states that Routine preventive maintenance (PM) shall be performed on all circuit breakers in the Dominion Circuit Breaker Program. A PM task shall be established for each circuit breaker in the Program. PM requires minimal or no disassembly, and is performed to ensure a circuit breaker is in good operating condition and that it will operate reliably until the next scheduled maintenance. Routine preventive maintenance is also used to monitor the condition of the breaker and correct any minor problems or degradations.

Licensee procedure, VPAP-0817, Circuit Breaker and Associated Switchgear Maintenance Program, Revision 0, effective September, 2001, contains the following information:

• Step 4.2 includes in part in the circuit breaker definition a discussion of a circuit breaker assembly that consists of items such as control circuit components and primary/secondary disconnect devices.

• Step 6.1.1 states in part that because of normal aging of circuit breaker material and lubricants a PM program shall be established to ensure circuit breaker operability and reliability.

• Step 6.1.5 states in part that components housed in the same cubicle shall be cleaned and tested at the time of the MCCB maintenance; examples of this include contactors (motor starters).

Licensee procedure, DNAP-2001, Equipment Reliability Process, Revision 0, effective March, 2003, states in step 3.4.2, Preventive Maintenance Program, that the Preventive Maintenance Program is a living program, with a documented technical basis for each PM. Each PM basis shall be kept current based on operating experience, corrective action reviews, and PM feedback.

Licensee procedure, DNAP-0104, Dominion Nuclear Self-Assessment Program, Revision 0, effective March, 2003, states in step 5.3.5, Industry Standards, that criteria for a program or process for which the majority of the industry uses or is considered to be an acceptable level of performance. These standards can be obtained from documents describing an acceptable program such as those written by INPO, NEI, EPRI, or industry work groups (e.g., Westinghouse Owners Group). Step 5.3.11, Operating Experience, states in part that OE is any lessons learned information made available from the nuclear or other industry.

The inspectors performed a search of industry programs to determine the availability of operations experience and preventative maintenance program information relative to main contactors and identified several EPRI technical reports and a Sandia Laboratory report which specifically addressed Klockner-Moeller breakers and related component failures as noted below: EPRI TR-106857, Volume 4: Motor Control Centers, July, 1997; EPRI TR-107042, Improving Maintenance Effectiveness, March, 1998; EPRI TR-1000806, Demonstration of Life Cycle Management Planning for Systems, Structures, and Components, January, 2001; EPRI TR-1009832, Molded Case Circuit Breaker Application and Maintenance Guide, Revision 2, December, 2004; and SAND93-7069, Aging Management Guideline for Commercial Nuclear Power Plants - Motor Control Centers, February, 1994.

The inspectors reviewed the licensees electrical PM procedure, 0-EPM-0304-01, Testing/Replacing 480-Volt Breaker Assemblies, Revision 49, performed during the last PM for 01-EE-BKR-1J1-2S-J1 on September 21, 2007, and Revision 56, which was in effect at the time of the fire event in 2009. The inspectors noted that 0-EPM-0304-01, step 6.4, Breaker Module Inspection, stated in part to check each relay coil for continuity and freedom of movement and motor starter contacts for continuity. When compared to available industry information, the inspectors concluded that 0-EPM-0304-01 did not contain guidance to adequately test the main contactors to detect degradation of the respective coil winding, and that adequate time existed for the licensee to follow their aforementioned program requirements stated in procedures, ER-AA-BKR-1001, VPAP-0817, DNAP-2001 and DNAP-0104, to research industry information to establish an adequate PM procedure for circuit breakers. The inspectors further concluded that the occurrence of a breaker cubicle fire in 2006 as noted above provided sufficient evidence to allow the licensee to foresee and correct an adverse condition regarding age related degradation of main contactors.

Analysis:

The failure to maintain an adequate preventive maintenance (PM) procedure led to an age related failure of a motor starter (main contactor) causing a fire in safety-related breaker cubicle J1 of motor control center (MCC) 1J1-2S which served the D control rod drive mechanism cooling fan, 01-HV-F-37D. The failure to establish an adequate PM task for testing the main contactor of a circuit breaker to ensure that it is in good operating condition and will operate reliably until the next scheduled maintenance was determined to be a performance deficiency. Significance Determination Process (SDP) phase 1 screening of the finding was performed and the finding was determined to increase the likelihood of a fire external event and required a phase 3 SDP evaluation.

A phase 3 SDP analysis was performed by a regional SRA in accordance with Inspection Manual Chapter 0609 Appendix F, NUREG /CR -6850 as amended by NUREG/CR -6850 supplement 1, with the NRC North Anna SPAR risk model used to determine the conditional core damage probability (CCDP) for the fire scenarios. The major assumptions for the evaluation included:

• The fire would not create a damaging hot gas layer, only local fire damage scenarios involving MCC 1J1-2S and cable trays 1TK049P and 1TK047P were considered.

• The fire would not be credible to damage both trains of any safety function prior to the initiation of automatic or manual suppression due to the amount of fire growth required to encompass both trains of a function.

• The fire would result in a transient initiator due to the absence of equipment and cables in the fire zone of influence which could cause a loss of offsite power initiator.

• The fire would result in damage to Main Steam Isolation Valve (MSIV) cables resulting in spurious closure of the MSIV and a plant transient initiator.

• The CCDP was developed assuming that all loads on MCC 1J1-2S and 2N would not have power subsequent to the fire except for loads where a hot short could produce a more risk significant impact. Hot short probability was assumed as 0.6.

• Recovery credit was assumed for manual operation of certain AFW, CVCS and HPI accessible MOVs with a failure probability developed using SPAR H techniques of 1E-1 to account for local manual MOV operation.

The dominant sequence was a fire in MCC1J1-2S damaging MSIV cables resulting in a reactor trip transient with failure of high pressure recirculation and residual heat removal due to fire effects leading to core damage. The evaluation concluded that the core damage frequency (CDF) increase of the potential fire scenarios was characterized as of very low safety significance (Green). This finding involved the cross-cutting area of problem identification and resolution, the component of OE, and the aspect of implementation and institutionalization of OE through changes to station processes and procedures (P.2(b)), because the licensee failed to incorporate existing industry OE to ensure procedural guidance was adequate for testing of the main contactor.

Enforcement:

Licensee procedure, DNAP-2001, Equipment Reliability Process, Revision 0, effective March 2003 requires in step 3.4.2, Preventive Maintenance Program, that the Preventive Maintenance Program is a living program, with a documented technical basis for each PM. Each PM basis shall be kept current based on operating experience, corrective action reviews, and PM feedback. Contrary to this, on April 22, 2009, the licensee failed to maintain PM procedure, 0-EPM-0304-01, current based on operating experience, corrective action reviews, and PM feedback, to ensure that main contactors for their respective circuit breaker would operate reliably until the next scheduled maintenance. Consequently, a main contactor failure occurred resulting in a breaker cubicle fire. Because this finding does not involve a violation of regulatory requirements, has very low safety significance, and has been entered into the licensees CAP as CR331819, it is identified as FIN 05000338, 339/2010005-05, Failure to Maintain PM Procedures for Circuit Breakers Current with Industry Information and OE.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 25, 2011, the senior resident inspector 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.

.2 Radiation Protection Inspection Exit

On September 30, 2010, the inspectors discussed results of the onsite radiation protection inspection with Mr. L. Lane, Site Vice-President, and other licensee representatives. In addition, during a subsequent telephone conversation on October 12, 2010, with Mr. R. Evans, Radiation Protection Manager, and other licensee representatives, the inspectors discussed additional inspection efforts and reviews that had been completed for the RP inspection. The inspectors noted that proprietary information was reviewed during the course of the inspection but would not be included in the documented report.

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 meet the criteria of Section 2.3.2 of the NRC Enforcement Policy for characterization as a NCV:

• 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"

states, in part, that activities affecting quality shall be prescribed by documented procedures. Contrary to this, the licensee identified that they failed to adequately prescribe procedure, VPAP-0905, Insulation Control Program, Revision 5, for adequate control of insulation work to avoid critical components. Consequently, the 2J EDG was rendered inoperable and unavailable when the governor drain petcock was inadvertently opened during replacement of insulation on the exhaust manifold.

This issue is in the licensees CAP as CR403015, 2-EE-EG-2J governor oil inadvertently drained during insulation work.

ATTACHMENT: SUPPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

W. Anthes, Manager, Nuclear Maintenance

M. Becker, Manager, Nuclear Outage and Planning

P. Bradley, Supervisor, Radiation Protection and Chemistry (RP&C)

M. Crist, Plant Manager

R. Evans, Manager, Radiological Protection and Chemistry

T. Huber, Director, Nuclear Engineering

S. Hughes, Manager, Nuclear Operations

C. Gum, Manager, Nuclear Protection Services

L. Lane, Site Vice President

M. Lane, Supervisor RP&C

P. Kemp, Manager, Organizational Effectiveness

F. Mladen, Director, Station Safety and Licensing

B. Morrison, Supervisor Nuclear Engineering

C. McClain, Manager, Nuclear Training

R. Scanlon, Manager, Nuclear Site Services

J. Scott, Supervisor, Nuclear Training (operations)

G. Simmons, Supervisor RP&C

D. Taylor, Supervisor, Station Licensing

LIST OF ITEMS

Opened

05000338, 339/2010005-01 URI Appendix R Fire Protection for RCS Instrumentation in Containment (Section 1R05.1)

Opened and Closed

05000338, 339/2010005-02 NCV Inadequate Corrective Action for Fatigued Fuse Clips in Safety-Related Breakers (Section 4OA2.2)

05000338, 339/2010005-03 NCV Inadequate Design Control Measures for Field Changes Affecting Station Battery Cables (Section 4OA5.4)

05000338/2010005-04 NCV Failure to Promptly Correct Conditions Adverse to Quality

for Valve Actuator Diaphragms (Section 4OA5.5)

05000338, 339/2010005-05 FIN Failure to Maintain PM Procedures for Circuit Breakers Current with Industry Information and OE (Section 4OA5.6)

Closed

05000338/2010-002-00 LER Forced Shutdown due to Un-Isolatable C Steam

Generator Surface Sample Leak Line (Section 4OA3)

05000338, 339/2515/179 TI Verification of Licensee Responses to NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System (NSTS) Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

(Section 4OA5.3)

05000338/2010004-03 AV Failure to Promptly Correct Conditions Adverse to Quality for Valve Actuator Diaphragms (Section 4OA5.5)

05000338, 339/2009005-04 URI Development of Work Orders (Section 4OA2.3)

05000338, 339/2009005-03 URI Units 1 and 2 Station Battery Cable Installation Issues (Section 4OA5.4)

05000338/2010004-07 FIN-TBD Failure to Maintain PM Procedures for Circuit Breakers Current with Industry Information and OE (Section 4OA5.6)

Discussed

None