IR 05000338/2006003

IR 05000338-06-003, IR 05000339-06-003, IR 07200016-06-001, on 04/01/2006 - 06/30/2006, for North Anna, Units 1 & 2, and Independent Spent Fuel Storage Installation. Routine Integrated Resident and Regional Report

ML062090554
Person / Time
Site:	North Anna
Issue date:	07/28/2006
From:	Landis K D NRC/RGN-II/DRP/RPB5
To:	Christian D A Virginia Electric & Power Co (VEPCO)
References
IR-06-001, IR-06-003
Download: ML062090554 (38)

Text

July 28, 2006

Virginia Electric and Power CompanyATTN.: Mr. David A. ChristianSr. Vice President and Chief Nuclear OfficerInnsbrook Technical Center - 2SW 5000 Dominion Boulevard Glen Allen, VA 23060-6711

SUBJECT: NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTIONREPORT NOS. 05000338/2006003, 05000339/2006003, AND 07200016/2006001 AND ANNUAL ASSESSMENT MEETING

SUMMARY

Dear Mr. Christian:

On June 30, 2006, the United States Nuclear Regulatory Commission (NRC) completed aninspection at your North Anna Power Station, Units 1 and 2. The enclosed integratedinspection report documents the inspection findings, which were discussed on July 14, 2006, with Mr. Jack Davis and other members of your staff. The inspections examined activities conducted under your licenses as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based upon the results of this inspection, one NRC-identified finding and two self-revealingfindings of very low safety significance (Green) were identified. These three findings were determined to involve violations of NRC requirements. However, because of their very lowsafety significance and because they were entered into your corrective action program, the NRC is treating these three findings as non-cited violations (NCVs) consistent with Section VI.Aof the NRC Enforcement Policy. In addition, three licensee-identified violations, which weredetermined to be of very low safety significance (Green), are listed in Section 4OA7 of this report. If you contest any non-cited violation in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.

20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the North Anna Power Station.

VEPCO 2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response, if any, will be available electronically for public inspection in theNRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's 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/Kerry D. Landis, ChiefReactor Projects Branch 5 Division of Reactor ProjectsDocket Nos.:50-338, 50-339, 72-016License Nos.:NPF-4, NPF-7, SNM-2507Enclosures:Inspection Reports 05000338/2006003, 05000339/2006003, and07200016/2006001 w/Attachment: Supplemental Informationcc w/encl: (See page 3)

__ML062090554 OFFICERII:DRPRII:DRPRII:DRSRII:DRSRII:DRSRII:DRSRII:DRSSIGNATUREJTR /RA/GJW /RA/MAS /RA/ECM /RA/SJV /RA/RRR /RA/BWM /RA/NAMEJReeceGWilsonMScottEMichelSViasRRodriguezBMillerDATE07/27/200607/27/200607/27/200607/27/200607/27/200607/27/200607/27/2006 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRSSIGNATUREKJH /RA/NAMEKHarperDATE07/27/2006 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO VEPCO 3cc w/encl.

Chris L. Funderburk, Director Nuclear Licensing and Operations Support Virginia Electric and Power Company Electronic Mail DistributionJack M. DavisSite Vice President North Anna Power Station Electronic Mail DistributionExecutive Vice PresidentOld Dominion Electric Cooperative Electronic Mail DistributionCounty AdministratorLouisa County

P. O. Box 160 Louisa, VA 23093Lillian M. Cuoco, Esq.Senior Counsel Dominion Resources Services, Inc.

Electronic Mail DistributionAttorney GeneralSupreme Court Building 900 East Main Street Richmond, VA 23219Distribution w/encl.: (See page 4)

VEPCO 4Report to D. A. Christian from Kerry D. Landis dated July 28, 2006SUBJECT:NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTIONREPORT NOS. 05000338/2006003, 05000339/2006003, AND 07200016/2006001 AND ANNUAL ASSESSMENT MEETING SUMMARYDistribution w/encl.

S. Monarque, NRR L. Slack, RII RIDSNRRDIPMLIPB PUBLIC EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos.:50-338, 50-339, 72-016License Nos.:NPF-4, NPF-7, SNM-2507 Report Nos.:05000338/2006003, 05000339/2006003, 07200016/2006001 Licensee:Virginia Electric and Power Company (VEPCO)

Facilities:North Anna Power Station, Units 1 & 2North Anna Independent Spent Fuel Storage InstallationLocation:1022 Haley DriveMineral, Virginia 23117Dates:April 1, 2006 - June 30, 2006 Inspectors:J. Reece, Senior Resident InspectorG. Wilson, Resident Inspector M. Scott, Senior Reactor Inspector, Section 1R07E. Michel, Reactor Inspector, Section 1R07 R. Rodriguez, Reactor Inspector, Sections 1R02, 1R17 S. Vias, Senior Reactor Inspector, Sections 1R02, 1R17 B. Miller, Reactor Inspector, Sections 1R02, 1R17 K. Harper, Reactor Inspector, Sections 1R02, 1R17Approved by:K. Landis, Chief, Reactor Projects Branch 5Division of Reactor Projects EnclosureCONTENTSSummary of Plant Status.....................................................5REACTOR SAFETY.........................................................51R02Evaluation of Changes, Tests, or Experiments

...............................51R04Equipment Alignment..................................................6 1R05Fire Protection........................................................7

/1R06Flood Protection Measures

..............................................71R11Licensed Operator Requalification Program

.................................91R12Maintenance Effectiveness

..............................................91R13Maintenance Risk Assessments and Emergent Work Control..................111R15Operability Evaluation................................................ .121R17Permanent Plant Modifications..........................................141R19Post-Maintenance Testing..............................................161R20Refueling and Other Outage Activities....................................161R22Surveillance Testing..................................................17 1R23Temporary Modifications...............................................18 1EP6Drill Evaluation......................................................18OTHER ACTIVITIES........................................................194OA1Performance Indicator Verification.......................................19 4OA2Identification and Resolution of Problems..................................194OA3Event Followup......................................................24 4OA5Other Activities.................................................24 4OA6Meetings, Including Exit...............................................25 4OA7

Licensee-Identified Violations

...........................................26ATTACHMENT: SUPPLEMENTARY INFORMATIONKey Points of Contact......................................................A-1 List of Items Opened, Closed, and Discussed...................................A-1List of Documents Reviewed................................................A-2 EnclosureSUMMARY OF FINDINGSIR 05000338/2006-003, IR 05000339/2006-003, IR 07200016/2006-001; 04/01/2006 -06/30/2006; North Anna Power Station Units 1 & 2, and North Anna Independent Spent FuelStorage Installation. Routine Integrated Resident and Regional Report. Inservice Inspection. 10 CFR 50.59 Modification Inspection. Biennial Heat Sink Performance Inspection.The report covered a three-month period of inspection by the resident inspectors, senior reactorinspectors, and reactor inspectors from the region. One NRC-identified and two self-revealingGreen findings were identified. These 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). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercialnuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3,dated July 2000.A.

Cornerstone: Mitigating Systems

Green.

A self-revealing non-cited violation of 10 CFR 50 Appendix B CriterionXVI was identified for inadequate corrective action which resulted in an inoperable control room chiller. On May 16, 2006, the chiller failed to start due toa faulty chilled water flow switch. Previously, a work order was initiated as part of a corrective action document to replace the flow switch due to aging.

However, the work order was completed without performing the switch replacement. The licensee documented this failure in their corrective action program.The finding is more than minor due to the impact on the Mitigating Systemscornerstone objective to ensure the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable c onsequencesand its attribute of procedure quality. The finding is of very low safety significance because it did not result in a loss of safety function of one or more trains and was not potentially risk-significant due to possible external events.

The cause of this finding involved the problem identification and resolution cross-cutting area based on the failure of the work order to complete the actions of a corrective action document. (Section 1R12)*Green. The inspectors identified a non-cited violation of Technical Specification(TS) 5.4.1a associated with the licensee's failure to correctly implement a maintenance procedure which resulted in a failure of a Unit 1 pressurizer power operated relief valve (PORV) on March 31, 2006. The inspectors' review of the root cause evaluation in conjunction with the associated work order and interview with plant personnel resulted in the conclusion that a critical cause of the degraded PORV was a failure to correctly implement the maintenance procedure by installing AC voltage versus the required DC voltage solenoid operated valves 4Enclosurein the PORV control system. The licensee entered this problem into theircorrective action program.This finding is more than minor due to the impact on the Mitigating Systemscornerstone objective to ensure the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable c onsequencesand its attribute of procedure quality. The finding is of very low safety significance because it did not result in a loss of safety function of one or more trains and was not potentially risk-significant due to possible external events.

This finding involved the human performance cross-cutting area based on the failure to implement a procedure correctly. (Section 1R15)*Green. A self-revealing non-cited violation of 10 CFR 50 Appendix B CriterionXVI was identified for the licensee's failure to properly identify and evaluate the extent of condition involving high cycle fatigue of components associated withEmergency Diesel Generators (EDGs). The failure to correct this condition adverse to quality resulted in a broken lube oil filter vent line and subsequent inoperability of the Unit 2 J EDG on October 16, 2005. The licensee repairedthis problem through their corrective action program.This finding is more than minor due to the impact on the Mitigating Systemscornerstone objective to ensure the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable c onsequencesand its attribute of procedure quality. The finding is of very low safety significance because it did not result in a loss of safety function of one or more trains and was not potentially risk-significant due to possible external events.

This finding impacts the cross-cutting area of problem identification and resolution, in that, the licensee failed to properly identify and evaluate the extentof condition involving high cycle fatigue of components associated with theEDGs. (Section 4OA2)

B.Licensee-Identified Violations

Three violations of very low safety significance were identified by the licensee, and havebeen reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. These violations and their corresponding corrective action tracking numbers are listed in Section 4OA7 of this report.

Enclosure

REPORT DETAILS

Summary of Plant StatusUnit 1 began the inspection period in a scheduled refueling outage that started on March 12,2006, and was returned to service on April 10, 2006. Unit 1 continued the inspection period at or near 100 percent power for the rest of the reporting period except for minor power reductions as needed to perform required periodic testing.Unit 2 began the inspection period at 100 percent power, and remained at or near full power forthe entire reporting period except for minor power reductions to perform required periodic testing.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection

a. Inspection Scope

Seasonal Adverse Weather Preparation Reviews The inspectors reviewed the licensee's adverse weather preparations for hot weatheroperations specified in 0-GOP-4.1, "Hot Weather Operations," and the licensee's correction action data base for hot weather related issues. The inspectors walked down the two risk-significant areas listed below to verify compliance with the procedural requirements and to verify that the specified actions provided the necessary protection for the structures, systems, or components. *Unit 1 & 2 Service Water (SW) pump house components; and,*Unit 1 & 2 Emergency Diesel Generator (EDG) Room components.

b. Findings

No findings of significance were identified.

1R02 Evaluation of Changes, Tests or Experiments

a. Inspection Scope

The inspectors reviewed selected samples of evaluations to confirm that the licensee had appropriately considered the conditions under which changes to the facility,Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests conducted, without prior NRC approval. The inspectors reviewed evaluations for sixchanges and additional information, such as calculations, supporting analyses, the UFSAR, and drawings to confirm that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The six evaluations reviewed are listed in the Attachment.

6EnclosureThe inspectors also reviewed samples of changes for which the licensee haddetermined that evaluations were not required, to confirm that the licensee's conclusionsto "screen out" these changes were correct and consistent with 10CFR50.59. The fifteen "screened out" changes reviewed are listed in the Attachment.The inspectors also reviewed plant issues to confirm that problems were identified at anappropriate threshold, were entered into the corrective action process, and appropriate corrective actions had been initiated.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors conducted four equipment alignment partial walkdowns to evaluate the operability of selected redundant trains or backup systems, listed below, with the othertrain or system inoperable or out of service. The inspectors reviewed the functionalsystem descriptions, UFSAR, system operating procedures, and TS to determinecorrect system lineups for the current plant conditions. The inspectors performedwalkdowns of the systems to verify that critical components were properly aligned and toidentify any discrepancies which could affect operability of the redundant train or backupsystem. Documentation reviewed is listed in the Attachment.*Unit 1 "B" Train Low Head Safety Injection System, during a licensee performedsurveillance testing on 1-SI-P-A;*Unit 1 "A" Casing Cooling walkdown performed during scheduled maintenanceon 1-RS-P-3B;*2J EDG walkdown performed during scheduled maintenance on 2H EDG; and,

• 2H EDG walkdown performed during scheduled maintenance on 2J EDG.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown and inspection of the Unit 2 CasingCooling Subsystem to assess properly alignment and to identify discrepancies that couldimpact its availability and functional capacity. The inspectors assessed the physicalcondition of the pumps, valves, pipe supports, and instrumentation. The inspection also 7Enclosureincluded a review of the alignment and the condition of support systems including fireprotection, room ventilation and emergency lighting. Equipment deficiency tags werereviewed and the condition of the system was discussed with engineering personnel. The operating procedures, drawings and other documents utilized and reviewed as partof the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted tours of the nine areas listed below and important to reactorsafety to verify the licensee's implementation of fire protection requirements as described in Virginia Power Administrative Procedure (VPAP)-2401, "Fire Protection Program." 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, andfeatures; and

(3) the fire barriers used to prevent fire damage or fire propagation.*Quench Spray Pump House and Safeguards Area Unit 1 (includes Z-16-1) (firezone 15-1a / QSPH-1);*Normal Switchgear Room Unit 2 (fire zone 5-2 / NSR-2);

• Battery Room 2 - I Unit 2 (fire zone7A-2 / BR2- I);

• Battery Room 2 - II Unit 2 (fire zones 7B-2 / BR2-II);

• Battery Room 2 - III Unit 2 (fire zone 7C-2 / BR2-III);*Casing Cooling Tank and Pump House Unit 2 (fire zone Z-41-2 / CCT&PH-2);

• Quench Spray Pump House and Safeguards Area Unit 2 (includes Z-16-2) (firezone 15-2a / QSPH-2);*Technical Support Center (fire zone 46b / TSC); and,

• Casing Cooling Tank & Pump House Unit 1 (fire zone Z-41-1 / CCT&PH-1).

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed internal flood protection measures associated with the Unit 1and Unit 2 Quench Spray Pump House (QSPH) area. Flooding from a service water pipe rupture in the QSPH could impact risk-significant components in the auxiliarybuilding and in the safeguards buildings. The inspectors reviewed the instrumentation and associated alarms for the rooms above to verify that the instrumentation was 8Enclosureperiodically calibrated and that the respective alarms were appropriately integrated intoplant procedures. The inspectors also reviewed licensee instructions in the event of severe flooding and evaluated the availability of systems, structures and components forsafe shutdown under worst case water levels. This inspection will continue into the nextquarter to complete ongoing evaluations.

b. Findings

No findings of significance to date were identified.

1R07 Heat Sink PerformanceBiennial Review

a. Inspection Scope

The inspectors reviewed inspection records, test results, maintenance work orders, andother documentation to ensure that heat exchanger (HX) deficiencies that could mask ordegrade performance were identified and corrected. The test procedures and records were also reviewed to verify that these were consistent with Generic Letter (GL) 89-13 licensee commitments, and industry guidelines. Risk significant heat exchangers (HX)reviewed included the Component Cooling System (CC) HXs, and Control Room Chillers.The inspectors reviewed HX inspection and cleaning work instructions, workmaintenance history, and completed inspection records for all the safety related HXs selected. The documents were reviewed to verify inspection methods were consistent with industry standards, to verify HX design margins were being maintained, and to verify performance of the HXs under the current maintenance frequency was adequate.The inspectors also reviewed general health of the service water system via review ofdesign basis documents, system health reports, inservice testing requirements, heatexchanger performance testing calculations, and discussions with the HX and SW system engineers. These documents were reviewed to verify the design basis wasbeing maintained and to verify adequate SW system performance under current preventive maintenance, chemical treatments, cleaning, inspections, and test frequencies. The inspectors physically walked down accessible portions of the SW system including the CC system, control room chillers, and the SW reservoir and LakeAnna dam. The inspectors reviewed the dam inspection reports and associated followup transmittals on the reservoir and the Lake Anna dam. The inspectors also verified SW system corrosion and degradation were beingmonitored and addressed via review of corrosion control program procedures, SW pipe replacement and material condition action plans, and discussions of coatings and cathodic protection systems with applicable engineers. The inspectors reviewed thelicensee's SW Project activities that are in progress for piping coating, man-way installation and cathodic protection over the next several years.

9EnclosurePlant issues evaluation reports were reviewed for potential common cause problemsand problems which could affect system performance to confirm that the licensee wasentering problems into the corrective action program and initiating appropriate corrective actions. Documents reviewed are listed in the Attachment

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed an annual licensed operator requalification simulatorexamination on June 13, 2005. The scenario, Simulator Examination Guide SXG-61, involved a loss of service water pump, a letdown line leak, loss of a condensate pump, an Anticipated Transient Without Scram, and a fault of all three steam generators.The scenario required classifications and notifications that were counted for NRCperformance indicator input. The inspectors observed crew performance in terms of communications; ability to take timely and proper actions; prioritizing, interpreting, andverifying 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 inspectorsobserved the post training critique to determine that weaknesses or improvement areas revealed by the training were captured by the instructors and reviewed with the operators.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the three equipment issues listed below, the inspectors evaluated the licensee'seffectiveness of the corresponding preventive and corrective maintenance. The inspectors performed walkdowns of the accessible portions of the systems, performed in-office reviews of procedures and evaluations, and held discussions with systemengineers. The inspectors compared the licensee's actions with the requirements of the Maintenance Rule (10 CFR 50.65) using VPAP 0815, "Maintenance Rule Program," and Engineering Transmittal CEP-97-0018, "North Anna Maintenance Rule Scoping and Performance Criteria Matrix." Other documents reviewed are listed in Attachment.

10Enclosure*Mechanical issues concerning equipment that controls temperature andPressure Differential Indicators for the Unit 2 Rod Drive Room;*Maintenance issues concerning control room chiller 1-HV-E-4B chilled water flowswitch; and,*Maintenance issues concerning the auxiliary lube oil pump on 1-CH-P-1A.

b. Findings

Introduction:

A Green self-revealing, Non-cited Violation (NCV) of 10 CFR 50 AppendixB Criterion XVI was identified as a result of the licensee's failure to adequately implement corrective action which resulted in an inoperable control room chiller.Description: On May 16, 2006, the licensee attempted to place 1-HV-E-4B, controlroom chiller, in service; however, the chiller failed to start and was declared inoperableper TS 3.7.11, Condition A, which requires restoration within 30 days. Troubleshooting by the licensee determined that a chilled water flow switch, 1-HV-FS-1213B was thecause of the failure to start and was subsequently replaced using a commercial grade dedication process. The inspectors performed a review of the work history associated with the aforementioned flow switch in addition to the similar flow switches on the other control room chillers, 1-HV-E-4A and 1-HV-E-4C, and identified the followinginformation:*May 1, 2001: The licensee performed preventive maintenance (PM) on flowswitch, 1-HV-FS-1213A (control room chiller, 1HV-E-4A) and identifiedintermittent operation. Plant Issue N-2001-1327 was initiated due to the intermittent operation and the equipment age of about 25 years. This plant issuewas closed to Work Order (WO) 00440514-01 which replaced the flow switch.*June 24, 2003: The licensee performed a PM on flow switch, 1-HV-FS-1213A(control room chiller, 1HV-E-4A) and identified intermittent operation. PlantIssue N-2003-2482 was initiated due to the intermittent operation and the equipment age of about 25 years. This plant issue was also closed to a WO using the following statement, "WO 00493252 01 status 30 to replace flow switch due to age. PI is listed on WO. Current flow switch in t he system is operable." However, the WO remained incomplete, and the switch was only adjusted.*August 16, 2004: WO 00493252-01 was completed with the last work performedidentified as "as left data sat. no adjustments. functioned sat." Flow switch, 1-HV-FS-1213B, was not replaced as noted as corrective action in Plant Issue N-2003-2482.*January 25, 2005: WO 00526971-01, which was initiated to perform acalibration on flow switch, 1-HV-FS-1213B, as a routine PM was cancelled and noted that "flow switch was calibrated under WO 493242-01 on 08/16/04."*May 16, 2006: After starting successfully for each quarter since closure of WO00493242-01 in August, 2004, chiller 1-HV-E-4B failed to start. The previousfailure was 'intermittent operation', and the previous switch adjustment apparently allowed some successful starts. Notwithstanding, the documented corrective action to replace the switch due to age was not performed; thus, the 11Enclosureswitch was unable to meet the expected performance requirements between thespecified PM frequency.The inspectors determined that the failure to replace flow switch, 1-HV-FS-1213B, asspecified by WO 00493252-01 was contrary to the requirements of 10 CFR 50, Appendix B, Criterion XVI which requires in part that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected.Analysis: The failure to implement adequate corrective action had a credible impact onreactor safety because of the failure of the control room chiller to start on demand. Theinspectors reviewed IMC 0612 and determined that the issue was more than minor due to the impact on the mitigating systems cornerstone objective to ensure the availability,reliability, and capability of systems that respond to initiating events to preventundesirable consequences and its attribute of procedure quality. The inspectors evaluated this finding using IMC 0609, Appendix A and determined that it was of very low safety significance (Green). Although it impacted the mitigating systemcornerstone, the finding is of very low safety significance because it did not result in a loss of safety function of one or more trains and was not potentially risk-significant due to possible external events. The cause of this finding involved the problem identification and resolution cross-cutting area based on the failure of the work order to complete the actions of a corrective action document.Enforcement: 10 CFR 50 Appendix B, Criterion XVI requires in part that measures shallbe established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, on August 16, 2004, WO 00493252-01 was completed without performing the corrective actions documented in Plant Issue N-2003-2482. This finding is of very low safety significance and is in the licensee's corrective action program as Plant Issue N-2006-2683; therefore, this violation is characterized as a NCV, consistent with Section VI.A of the NRC Enforcement Policy:

NCV-05000338, 339/2006003-01, Inadequate Corrective Action Results In Failure of Control Room Chiller to Start.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

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

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

(2) the management of risk;

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

(4) that maintenance risk assessments and emergent work problems were adequately identified and resolved. The inspectors verified that the licensee was complying with the requirements of 10 CFR 50.65 (a)(4) and the data output from thelicensee's safety monitor associated with the risk profile of Units 1 and 2.

12Enclosure*Maintenance rule risk evaluation for unplanned work on April 7, 2006 whileexecuting Procedure 0-AP-41, " Severe Weather Conditions," entered due to a tornado watch with 1-SW-P-4 unavailable due to a failed missile barrier;*Maintenance rule risk evaluation for risk associated with trouble shooting -32problems while performing rack work, switchyard and "C" Reserved Station Service Transformer (RSST) work on overhead lines on April 27, 2006;*Emergent work on 2-BD-TV-200B during performance of work associated with1-PT-36.1A instrument racks, switchyard, and "C" RSST on overhead lines;*Emergent work on 1-CH-P-1A during the performance of work associated withinstrument racks, "C" RSST on overhead lines, switchyard and 1-PT-82H;*Emergent work associated with the Unit 1 main generator voltage regulatorduring performance of work involving 1-CH-P-1C, 1-FP-P-2, 2PT-36.1A, instrument racks, switchyard and "C" RSST work on overhead lines; and,*Emergent work associated with 1B Feedwater Pump seal leak duringperformance of work involving instrument racks, 2-EE-EG-2J, and "C" RSST onoverhead lines.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed six operability evaluations affecting risk-significant mitigatingsystems, listed below, to assess, as appropriate:

(1) the technical adequacy of theevaluations;

(2) whether continued system operability was warranted;

(3) whether otherexisting 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;

(5) where continued operability was consideredunjustified, the impact on TS Limiting Conditions for Operation and the risk significance in accordance with the SDP. The inspectors' review included a verification that the operability determinations were made as specified by Procedure VPAP-1408, "SystemOperability." Documents reviewed by the inspectors are listed in the Attachment.*Plant Issue N-2006-2320, during the performance of 2-PT-75.2A, the acceptancecriteria for the discharge check valve (1-SW-10) on 1-SW-P-1B could not be met;*Plant Issue N-2006-2358, discovered a Recirculation Spray (RS) pipe supportwith a loose pipe clamp bolt and a bent rod end;*Plant Issue N-2006-2436, stainless steel tubing for the 1H EDG Lube Oil Filterand Strainer Constant Vent line was found with broken and loose support clips;*Plant Issue N-2006-2676, 1-CH-RV-106A would not control pressure. Theapparent failure of the valve to open caused 1-CH-P-1A1 to pull high amps; 13Enclosure*Plant Issue N-2006-1905, Solenoid operated valves installed on1-RC-SOV-1455C-1 and 1-RC-SOV-1455C-2 were identified as 120V/60 Hz versus the required 125V DC; and,*Plant Issue N-2006-3458, unistrut for conduit support in 2H EDG room is notsupported by the center hanger and a gap exists between unistrut and hanger washer.

b. Findings

Introduction:

A Green, NCV of TS 5.4.1a was identified by the NRC as a result of thelicensee's failure to implement a maintenance procedure which resulted in a degraded condition of a pressurizer PORV.Description: On March 31, 2006, Unit 1 was in Mode 5 with both pressurizer PORVsopen to comply with TS requirements for a vent path. At 0158 hours0.00183 days <br />0.0439 hours <br />2.612434e-4 weeks <br />6.0119e-5 months <br /> the licensee determined that pressurizer PORV 1-RC-PCV-1455C was closed with its respective switch in 'open' during evaluation of a ground alarm on the 1-I vital inverter. The PORV was reopened by using the nitrogen backup system at 0238 hours0.00275 days <br />0.0661 hours <br />3.935185e-4 weeks <br />9.0559e-5 months <br />. During repairs thelicensee discovered that the solenoid operated valves (SOV) 1-RC-SOV-1455C-1 & 2, used to stroke the valve on instrument air, were AC voltage as opposed to the required DC voltage. Separate SOVs are used to operate the PORV with the nitrogen backupsystem. The inspectors reviewed the licensee's past operability evaluation and notedthat the impact on TS operability was not clearly identified. The inspectors alsoreviewed the licensee's root cause evaluation (RCE) and noted that it focused onwarehouse parts issues concerning a transfer of SOVs between stock numbers without consideration of part descriptions. The inspectors also noted that subsequent evaluations of the RCE by station nuclear safety personnel and the corrective action review board had rejected the RCE due to no external operational experience review, no corrective actions relative to combining stock numbers, no organizational failure discussion, no repeat problem discussion, and why previous corrective actions did not prevent recurrence. The inspectors reviewed the work package, WO 00507310-01, that installed new SOVs as preventative maintenance in September, 2004. The inspectors identified that electrical maintenance procedure, 0-ECM-2101-01, "Trouble-Shooting,Testing, and Replacing ASCO Solenoid-Operated Valves," Revision 7, had the following caution statement, "Coil must be correct voltage type (AC or DC) and have correct voltage and current ratings." Additionally, the inspectors noted that the work package contained an electrical elementary diagram, 11715-ESK-6NR, which showed that the SOVs undergoing replacement were part of a 125 VDC circuit. The inspectors interviewed plant personnel and determined that compliance with the caution statementis performed by reviewing the nomenclature located on the SOV to ensure to correctness. The inspectors concluded that a critical cause of the event was a failure to implement the procedure correctly. This is contrary to the requirements of TS 5.4.1awhich requires in part that written procedures shall be implemented covering the activities in the applicable procedures recommended by Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978, of which part 9.a. requires procedures for performing maintenance.

14EnclosureAnalysis: The failure to implement 0-ECM-2101-01 correctly resulted in the installationof wrong SOVs in the control system for the respective PORV and the consequentimpact on TS operability. The inspectors reviewed IMC 0612 and determined that theissue was more than minor due to the impact on the mitigating systems cornerstoneobjective to ensure the availability, reliability, and capability of systems that res pond toinitiating events to prevent undesirable consequences and its attribute of procedure quality. The inspectors evaluated this finding using IMC 0609, Appendix A and determined that it was of very low safety significance (Green). Although it impacted the mitigating system cornerstone, the finding is of very low safety significance because itdid not result in a loss of safety function of one or more trains and was not potentially risk-significant due to possible external events. The cause of this finding involved the human performance cross-cutting area based on the failure to implement a procedure correctly.Enforcement: TS 5.4.1a requires in part that written procedures shall be implementedcovering the activities in the applicable procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, of which part 9.a. requires procedures forperforming maintenance. Contrary to the above, on September 26, 2004,0-ECM-2101-01 was incorrectly implemented which subsequently impacted TS operability of pressurizer PORV, 1-RC-PCV-1455C. This finding is of very low safetysignificance and is in the licensee's corrective action program as Plant Issue N-2006-1905; therefore, this violation is characterized as a NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000338/2006003-02, Failure to Implementa Maintenance Procedure Impacting Pressurizer PORV Operability.

1R17 Permanent Plant Modifications

a. Inspection Scope

The inspectors evaluated engineering change packages for seven modifications toevaluate the modifications for adverse effects on system availability, reliability, and functional capability. The seven modifications and the associated attributes reviewedare as follows: *DCP 03-168 Install Remote Closure SOVs for Pressurizer Spray Valves(Initiating Events)

SEnergy Needs (air, electricity)

SOperations SStructural SFailure Modes*DCP 03-108, MFRV Positioner Modification AV2 to AV1 (Mitigating Systems)

SMaterials/Replacement Components (material compatibility,environmental qualification, seismic qualification)

STiming (response time)

SProcess Medium (fluid pressures)

SLicensing Basis 15Enclosure*DCP 04-102, MOV Overall Gear Ratio Modification (Mitigating Systems)

STiming (response time)

SMaterials/Replacement Components (material compatibility, functi onalproperties)

SEnergy Needs (electricity)

SOperations SLicensing Basis*DCP 96-237, Install Test Taps in HVAC Ducts (Mitigating Systems)

SVentilation Boundary SOperations SSystem Flow Requirements*DCP 91-005, 3 SG Blowdown Tank Piping Rerouting (Mitigating Systems,Barrier Integrity)

SMaterials/Replacement Components SFlowpaths SEquipment Protection SFailure Modes*DCP 03-133, Modify 2-HV-HV-2 Control Logic to Trip When 2-HV-F-16 FlowStops (Mitigating Systems)

SControl Signals SVentilation Boundary STiming*DCP 01-162, Replacement of Vital Bus Inverters 2-III & 2-IV (MitigatingSystems)

SEnergy Needs (electricity)

SMaterials/Replacement Components (material compatibility, functi onalproperties)Documents reviewed included procedures, engineering calculations, modification designand implementation packages, work orders, site drawings, corrective action documents, applicable sections of the living UFSAR, supporting analyses, TS, and design basis information. Specific documents are listed in the Attachment.The inspectors also reviewed selected plant issues and an audit associated withmodifications to confirm that problems were identified at an appropriate threshold, were entered into the corrective action process, and appropriate corrective actions had been initiated.

b. Findings

No findings of significance were identified.

16Enclosure1R19Post Maintenance Testing

a. Inspection Scope

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

(1) theeffect 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 its safety function.

The inspectors verified that these activities were performed in accordance with licensee procedure VPAP-2003, "Post Maintenance Testing Program."*Procedure 0-MCM-0650-0, "Disassembly Inspection and Repair of the OutsideRecirculation Spray Pump Seal Accumulator," Revision 5, and Procedure 1-PT-64.1.1, "Outside Recirculation Spray Pump 1-RS-P-2A," Revision 21, perWO 740587-01;*Procedures 0-ECM-0307-1, "Replacement of Thermal Overload Devices,"Revision 13, and 0-ECM-0206-01, "Installation of Lugs," Revision 06, per WO 527389;*Procedure 0-ECM-2102-01, "Trouble Shooting, Testing, and ReplacingEQ-Related ASLO Solenoid Operator Valves," Revision 8, Procedure 0-ECM-02002-01, "Installation and Removal of EGS Bayonet Connector,"

Revision 10, and Procedure 0-ECM-0206-01, "Installation of Lugs," Revision 6, per WO 747758-01;

• Procedure 0-MCM-701-34, "Removal and Installation of Emergency DieselGenerator," and Procedure 2-PT-82.4A, "2H Emergency Diesel Generator Test (Start by ESF Actuation)," Revision 56, per WOs 730135 and 730659;*Procedure 0-ICP-MIS-G-001, "Miscellaneous Instrumentation Calibration,"Revision 8, per WO 127299; and,*WO 00529611-03 to replace 1-CH-285 (cut out and weld in new valve).

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities

a. Inspection Scope

The inspectors continued this inspection activity from the previous quarter and usedinspection procedure 71111.20, "Refueling and Outage Activities," to observe portions of the maintenance and startup activities to verify that the licensee maintained 17Enclosuredefense-in-depth commensurate with the outage risk plan and applicable TS. Theinspectors monitored licensee controls over the outage activities listed below. *Licensee configuration management, including daily outage reports, to evaluatedefense-in-depth commensurate with the outage safety plan and compliance with the applicable TS when taking equipment out of service.*Controls over the status and configuration of electrical systems and switchyard toensure that TS and outage safety plan requirements were met.*Decay heat removal processes to verify proper operation and that steamgenerators, when relied upon, were a viable means of backup cooling.*Controls to ensure that outage work was not impacting the ability to operate thespent fuel pool cooling system during and after-core offload.*Reactor water inventory controls including flow paths, configurations, andalternative means for inventory addition, and controls to prevent inventory loss.*Reactivity controls to verify compliance with TS and that activities which couldaffect reactivity were reviewed for proper control within the outage risk plan.*Heatup and startup activities to verify that TS, license conditions, and otherrequirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant conditions. Reactor Coolant System (RCS) integrity was verified by reviewing RCS leakage calculations and containment integrity was verified by reviewing the status ofcontainment penetrations and containment isolation valves.*Containment closure activities, including a detailed containment walkdown priorto startup, to verify no evidence of leakage and that debris had not been left which could affect the performance of the containment sump.Specific documentation reviewed during the inspection processes are listed in theAttachment.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the six surveillance tests listed below, the inspectors examined the test procedure,witnessed testing, and reviewed test records and data packages, to determine whether the scope of testing adequately demonstrated that the affected equipment wasfunctional and operable, and that the surveillance requirements of the TS were met. Documentation reviewed is listed in the Attachment.*1-PT-61.3, "Operations Periodic Test - Containment Type C Test," Revision 26;*1-PT-52.2, "Reactor Coolant System Leak Rate (Hand Calculation);"

• 1-PT-63.1B, "Quench Spray System - 'B' Subsystem;"*2-PT-82H, "2H Emergency Diesel Generator Test Slow Start Test," Revision 40; 18Enclosure*1-PT-71.3Q, "1-FW-P-3B, "B" Motor-Driven AFW Pump and Valve Test,"Revision 37; and, *2-PT-82.4A, "2H Diesel Generator Test (Start by ESF Actuation)," Revision 56.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed one temporary plant modification to verify that themodifications did not affect system operability or availability as described by the TS andUFSAR. In addition, the inspectors verified that the installation of the temporary modification was in accordance with the work package, that adequate controls were in place, procedures and drawings were updated, and post-installation tests verified the operability of the affected systems.The temporary plant modification reviewed was Temporary Modification 2006-1768,"Install a Temporary Manual/Auto Station for 1-MS-PC-1464B on Unit 1 MCR Bench-Board."

b. Findings

No findings of significance were identified.

Cornerstone:

Emergency Preparedness1EP6Drill Evaluation

a. Inspection Scope

On May 23, 2006, the inspectors reviewed and observed the performance of anemergency planning drill that involved an earthquake, loss of cooling accident, andequipment failures resulting in a Site Area Emergency and subsequent General Emergency. The inspectors assessed emergency procedure usage, emergency plan classification, notifications, and the licensee's identification and entrance of anyproblems into their corrective action program. This inspection evaluated the adequacy of the licensee's conduct of the dr ill and critique performance. Drill issues werecaptured by the licensee in their corrective action program and were reviewed by the inspectors.

b. Findings

No findings of significance were identified.

19Enclosure4.OTHER ACTIVITIES4AO1Performance Indicator (PI) Verification

a. Inspection Scope

Cornerstones: Initiating Event, Mitigating Systems, and Barrier IntegrityThe inspectors sampled licensee submittals of performance indicator data reported tothe NRC for the three Performance Indicators listed below for Unit 1 and Unit 2:*Unplanned Power Changes;*Safety System Functional Failures, and,

• Reactor Coolant System Leakage.The inspectors reviewed data from the licensee's corrective action program,maintenance rule records, operating logs and maintenance work orders for the period covering the second quarter 2005 through the first quarter 2006. The data was compared with that displayed on the NRC's public web site. The performance indicatormethod of assessment was compared with the guidelines contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guidelines." During plant tours the inspectors also periodically assessed the Occupational ExposureControl Effectiveness and the RETS/ODCM Radiological Effluent Occurrence Performance Indicators by determining if high radiation areas (>1R/hr) were properly secured, and looking for unmonitored radiation release pathways.

b. Findings

No findings of significance were identified. The performance indicators all remained inthe licensee response band (Green).4OA2Identification and Resolution of Problems

.1 Daily ReviewAs 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 licensee's corrective action program. This review was accomplished by reviewing daily Plant Issues summary reports and periodically attending daily Plant Issue Review Team meetings.

.2 Annual Sample Review

a. Inspection Scope

The inspectors reviewed the licensee's assessments and corrective actions for PlantIssue N-2005-4494, "At approx. 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> into 2-PT-83.12J the 2J emergency diesel generator lube oil filter vent line pulled from its union connector which cause the engine to be shut down as several gallons of oil sprayed from the line," and Plant Issue N-2006-1578, "RS Sump Inspection - inspected the top cover plates of the "B" RS Sump

... to confirm the size of the two small openings (one of 2" X 1 " and another of 2" X 1 1/8") next to the containment line (back of sump cover) found during 1-PT-57.3." The plant issues were reviewed to ensure that the full extent of the issue was identified, appropriate evaluations were performed, and appropriate corrective actions were specified and prioritized. The inspectors also evaluated the plant issues against the requirements of the licensee's corrective action program as specified in VPAP-1601, "Corrective Action Program," VPAP-1501, "Deviations," and 10 CFR 50, Appendix B.

b. Findings and Observations

EDG Lube Oil Filter Vent LineIntroduction: A Green non-cited violation (NCV) was identified for failure to correct acondition adverse to quality associated with the broken lube oil filter vent line on the 2J EDG.

Description:

On October 16, 2005, the licensee initiated Plant Issue N-2005-4494 inresponse to the failure of the lube oil filter vent line on the Unit 2J EDG identified during 2-PT-83.12J, "2J Diesel Generator Test (Start by ESF Actuation) Followed by 24-Hour Run and Hot Restart Test." The 2J EDG was previously removed from service to complete maintenance for leaking water bypass gaskets and to replace control relays, but the licensee failed to complete WO 720789-01 to repair a broken U-bolt support for a main lube oil line. Plant Issue N-2005-3166 documented the licensee's functional evaluation for this broken U-bolt support and determined that it did not present an operability issue at that time. However, during 2-PT-83.12J on October 16, 2005,operators identified an increase in vibrations on the diesel and alerted engineers who concluded that the overall vibrations were normal. Shortly thereafter, the lube oil filtervent line ruptured at its ferrule connection rendering the diesel inoperable. After replacement of this vent line, the diesel was restarted for a post maintenance test and to complete 2-PT-83.12J; however, the lube oil filter vent line failed again at the same location causing operators to shut down the diesel. The inspectors reviewed the licensee's functional evaluation for the cracked U-bolt support, the planned EDG outage work order package (WO 725645-01), and the following plant issue reports:*Plant Issue N-2005-1522, licensee identified a cracked support bracket on the 1JEDG;*Plant Issue N-2005-4578, NRC inspectors identified a cracked support bracketon the 1J EDG; 21Enclosure*Plant Issue N-2005-0660, licensee identified a cracked weld support on the 1H &2H EDG;*Plant Issue N-2005-3166, licensee identified a cracked U-bolt support on the 2JEDG; and,*Plant Issue N-2004-1925, corrective actions established a process to reviewoutstanding work orders before and following each EDG maintenance period to ensure proper maintenance was completed and that no outstanding work existed that would challenge the EDG operability until the next maintenance period.The inspectors noted that the licensee had previously taken some corrective actions torepair the support bracket weld cracks due to high cycle fatigue, but failed to adequately address the lube oil filter vent line. Additionally, the inspectors noted that thecracked U-bolt support was inadequately evaluated as not an immediate impact and was scheduled for repair 10 months later. The inspectors concluded that the failure of the licensee to assess the high cycle fatigue conditions involving the lube oil filter ventline lead to its subsequent failure. The inspectors also independently reviewed and verified that the licensee's evaluation had determined similar findings. The inspectors concluded that the failure to properly identify and correct the high cycle fatigue problemis contrary to 10 CFR 50 Appendix B, Criterion XVI, which requires in part that measures shall be established to assure that conditions adverse to quality, such as deficiencies and defective material and equipment are promptly identified and corrected.Analysis: The inspectors determined the finding is more than minor because it affectedthe mitigating systems cornerstone objective to ensure the availability, reliability, andcapability of systems that respond to initiating events to prevent undesirableconsequences and its attribute of equipment performance. This had a credible impact on safety because it affected the availability of the emergency diesel generator. Theinspectors further referenced IMC 0609 for the SDP review and determined the finding was of very low safety significance. Although it affected the mitigating systemcornerstone, the finding is of very low safety significance because it did not result in a loss of safety function of one or more trains and was not potentially risk-significant due to possible external events. This finding impacts the cross-cutting area of problem identification and resolution, in that, the licensee failed to properly identify and evaluatethe extent of condition involving high cycle fatigue of components associated with theEDGs.Enforcement: 10 CFR, Appendix B, Criterion XVI states in part, "Measures shall beestablished to assure that conditions adverse to quality, such as deficiencies, defective material and equipment are promptly identified and corrected." Contrary to this on October 16, 2005, the licensee failed to properly identify and correct a high cycle fatigueproblem impacting the lube oil filter vent line which subsequently rendered the 2J EDG inoperable. This finding is of very low safety significance and is entered into the licensee's corrective action program as Plant Issue N-2005-4494; therefore, this violation is characterized as a NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000339/2006003-03, Failure to Correct a Condition Adverse to Quality Regarding High Cycle Fatigue Failure of the 2J EDG Lube Oil Filter Vent Line.

22EnclosureContainment Recirculation Spray Sump PumpA licensee identified violation associated with this review is documented in section 4OA7of this report. On March 23, 2006, during the cycle 18 refueling outage the licenseeidentified two openings (2" x 1" and 2" x 1 1/8") in the RS sump enclosure during performance of 1-PT-57.3, "Containment Recirculation Spray Sump Visual Examination," and initiated Plant Issue N-2006-1578 for an evaluation. The inspectorsreviewed the licensee's evaluation and subsequent corrective actions and noted that additional plant issues were initiated as a result of more openings found during an extent of condition review:*N-2006-1595, "A 1-1/4" diameter hole in each RS pump baseplate was open tothe inside of the IRS A and B circular screens (elevation 222' - 11-3/4");"*N-2006-1637, "An opening (1/2" x 1-1/2") in IRS A pump circular screen lowerflange that provided a direct path to the pump well (elevation 214' - 7-3/8");"*N-2006-1819, "Gaps larger than 1/4" in top cover of RS sump (elevation 221' -9-3/8");" and,*N-2006-1938, "Two gaps larger than 1/4" in top cover plate of the sump(elevation 221' - 9-3/8")".The inspectors also reviewed plant issues related to the RS system from the 2004 cycle17 refueling outage and noted the following plant issues:*N-2004-3605, "Openings larger than

.12 inch were found: a)in the top plate ofthe RS sump; b) between several vertical screen panels; and c) on the top of

several panels connection to the sump structure. These openings allow for a bypass around the vertical fine mesh screens for both the 'A' and 'B' sides of the sump;"*N-2004-3744, "Subsequent to the evaluation for IPR 04-314 and N-2004-3605,additional gaps were identified under the two screen panels (horizontal bottom)on each end of the sump (screen panels 1B, 2B, and 1A, 2A). Te gaps varied from 1/4" to 1/2" in height and were 35" long;"*N-2004-4186, "Additional gaps were found in the front of the "A" side of thesump in the tube steel above the vertical screen panels and the corners of the "A" side of the sump. During investigation into N-2004-4186, another potential gap was located on the "B" side corner of the sump in the tube steel above the vertical screen panels;" and,*N-2004-4011, "Debris was found in the shell (RS) side of the RS heatexchangers. ET-NAF-04-0099 concluded that the RS system had been operablebut degraded prior to Fall 2004."The inspectors concluded that the licensee's failure to implement adequate correctiveactions for the plant issues in 2004 to preclude the RS sump deficiencies identified during the 2006 refueling outage is a violation of 10 CFR 50, Appendix B, Criterion XVI, which requires in part that in the case of significant conditions adverse to quality, measures shall assure that the cause of the condition is determined and corrective 23Enclosureaction taken to preclude repetition. The enforcement aspects are discussed inSection 4OA7.

.3 Semi-Annual Review to Identify Trends

a. Inspection Scope

As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"the inspectors performed a review of the licensee's corrective action program through the plant issue reports to identify trends that could indicate the existence of a moresignificant safety issue. The inspectors' review considered the results of daily inspector plant issue item screening discussed in section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The inspector's review nominally considered the six-month period of January through June 2006, although some examples expanded beyond those dates when the scope of the trend warranted. The review also covered areas not documented in plant issues reports such as: departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, selfassessment reports, and maintenance rule assessments. The inspectors compared and contrasted their results with the results contained in the licensee's latest quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensee's trend report were reviewed for adequacy.

b.Assessment and ObservationsNo findings of significance were identified. The inspectors evaluated the licenseetrending methodology and observed that the licensee had performed reviews as directed by VPAP-1601, "Corrective Action," and the "Dominion Trend Analysis Manual" The inspectors compared the licensee process results with the results of the inspectors' daily screening and did not identify a discrepancy or potential trend in the plant issue reportdata that the licensee had failed to identify by a unique plant issue document.The inspectors performed a review of plant issues associated with control roomdifferential pressure problems and specifically those that involved entry into TS 3.7.10,"Main Control Room/Emergency Switchgear Room (MCR/ESGR) Emergency Ventilation System (EVS), and/or TS 3.7.13, "Main Control Room/Emergency Switchgear Room (MCR/ESGR) Bottled Air System." The inspectors found that from the period of January 1, 2006 through June 6, 2006, the licensee initiated Plant Issues N-2006-2937,N-2006-3029, and N-2006-3068. The inspectors also noted that from June 14, 2005 until end of the year, the licensee initiated ten plant issues for MCR/ESGR differentialpressure problems requiring entry into the applicable TS. On June 22, 2006, the licensee again entered TS 3.7.10/3.7.13 due to low differential pressure and initiatedPlant Issue N-2006-3388. Based on testing performed and documented under ET-SE-97-0162, Revision 7, "Control Room Positive Pressure Indications," new procedural limits for MCR/ESGR were introduced that allowed exit of the TS LCOs.

However, following the introduction of the new limits the licensee encountered more ventilation problems resulting in an additional three Plant Issues, N-2006-3587, N-2006-3630, and N-2006-3639 between July 3, 2006 and July 6, 2006. The inspectors 24Enclosurereviewed the licensee's trend results and noted that the control room differentialpressure problems were captured in a category for unplanned TS LCO entries and highlighted by comments noting that the problems constituted more than half of theissues within this category. The licensee is continuing to trend this issue.4OA3Event Followup(Closed) Licensee Event Report (LER) 05000338/2006001-00: Manual Reactor TripDue to Shutdown Bank "A" Group 2 Step Counter InoperableOn April 7, 2006, Unit 1 was in Mode 3, zero percent power, preparing for restartfollowing a refueling outage. As part of the performance for rod drop time measurement, Shutdown Bank "A" Groups 1 and 2 control rods were being withdrawn from the core. Group 2 step counter stopped at 215 steps, while Group 1 and individual rod position indicators showed continued motion to 225 steps. The Shutdown Bank Group 2 step counters were declared inoperable and a manual reactor trip was initiated by opening the reactor trip breakers in accordance with Technical Requirement 3.1.3 due to a mismatch of the Shutdown Bank "A" Group step counters. This was a valid actuation of the Reactor Protection System. The failed digital step counter for Shutdown Bank "A" Group 2 was evaluated, and the internal connections were noted to be inadequate due to a problem with the manufacturing process. The failed digital step counter was replaced on April 8, 2006, and rod drop time measurement testing was subsequently completed satisfactorily. The applicable maintenance procedure was revised to include steps directing pre-installation testing and inspection. This LER is closed.4OA5Other Activities

.1 (Closed) NRC Temporary Instruction (TI) 2515/165 "Operational Readiness of OffsitePower and Impact on Plant Risk" The inspectors reviewed licensee procedures and controls, and interviewed operationsand maintenance personnel to verify these documents contained specific attributes

delineated in the TI to ensure the operational readiness of offsite power systems inaccordance with plant TS; the design requirements provided in 10 CFR 50, Appendix A, General Design Criterion 17, "Electric Power Systems;" and the impact of maintenance on plant risk in accordance with 10 CFR 50.65(a)(4), "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Documents reviewed are listed in the Attachment. Appropriate documentation of the results of this inspection was provided to NRC headquarters staff for further analysis, as required by the TI. Thiscompletes the Region II inspection TI requirements for North Anna Power Station.

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

a. Inspection Scope

25EnclosureThe inspectors observed: loading spent fuel assemblies into the spent fuel dry storagecask TN-32-41; verification of assemblies being loaded into the cask; setting the lid on the top of canister; verification of positive engagement of lifting devices being positioned; lifting of the loaded cask above the water surface; draining a small portion of water from the cask for the lid bolting; removing water from bolt holes; hand tightening lid bolts; draining the water from the cask; moving the loaded cask to the cask setting area by following the heavy load lifting path; drying the cask; and backfill with helium. Observations were compared to the licensee's procedures to ensure compliance. The inspectors also observed radiation protection controls and monitoring.The inspectors reviewed required records and data contained in the working copy of theprocedure. The inspectors reviewed TN-32-41 Independent Spent Fuel Storage Installation (ISFSI) Fuel Assembly and Insert Component Certification and CaskLoading Map to verify that the loaded assemblies met the Technical Specification TN-32Cask Operating Limits. This documents contained the description and limits of thespent fuel assemblies to be placed in the canister, such as initial fuel enrichment, fuel burnup, decay heat, time discharged, fuel assembly design, time since discharged for burnable poison rods, and uranium content. The inspectors reviewed training certificates and qualification records for crane operators and cask loading operators.

The inspectors reviewed spent fuel cask crane periodic inspection, function test, and maintenance records. Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.4OA6Meetings, including Exit

.1 Exit Meeting

On July 14, 2006, the resident inspectors presented the inspection results to Mr. Jack Davis and other members of the staff. The licensee acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

.2 Annual Assessment MeetingOn April 18, 2006, the NRC Chief of Reactor Projects Branch 5 met with Virginia Electricand Power Company to discuss the NRC's Reactor Oversight Process (ROP)

and theNorth Anna Power Station annual assessment of safety performance for the period of January 1, 2005 - December 31, 2005. Attendees included licensee corporate and site management, licensee site staff and members of the local news media. This meeting was open to the public. The presentation material used for the discussionis available from the NRC's document system (ADAMS) as accession number ML051030203. ADAMS is accessible from the NRC Web site ashttp://www.nrc.gov/reading-rm/adams.html (the Public Reading Room).

26Enclosure4OA7Licensee-Identified ViolationsThe following findings of very low significance (Green) were identified by the licenseeand are violations of NRC requirements which meet the criteria of Section VI of the NRCEnforcement Policy, NUREG-1600, for being characterized as NCVs.*TS 5.4.1 requires that written procedures shall be established, implemented, andmaintained covering the activities in the applicable procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, of which part9.a. requires procedures for performing maintenance. Contrary to the above, onMarch 13, 2006, the licensee failed to establish adequate procedure steps in maintenance procedure 0-ECM-0706-01, "Woodward Governor Adjustment."

This resulted in inadequate tuning of the 1J EDG Woodward governor which subsequently resulted in 1J EDG frequency outside of the allowable TS band and a declaration of inoperability. The inspectors reviewed IMCs 0612 and 0609and determined that the finding was of very low safety significance given that only one train was affected for less than the TS allowed outage time The licensee has this finding documented in their corrective action program as Plant Issue N-2006-1056.*TS 5.4.1 requires that written procedures shall be established, implemented, andmaintained covering the activities in the applicable procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, of which part9.b. requires the development of procedures to perform preventative maintenance. Contrary to the above, on March 14, 2006, the licensee failed toestablish a preventative maintenance procedure that would inspect, clean andtest the K relays on the 1H EDG. This resulted in high resistance readings on the relays due to dirt buildup and oxidation residue which rendered the diesel inoperable due to the output breaker closing greater than time allowed by TS.

The inspectors reviewed IMCs 0612 and 0609 and determined that the finding was of very low safety significance given that only one train was affected for less than the TS allowed outage time. The licensee has this finding documented in their corrective action program as Plant Issue N-2006-1112.*10 CFR 50, Appendix B, Criterion XVI requires in part that in significant cases ofconditions adverse to quality, measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.

Contrary to this on March 23, 2006, the licensee identified that corrective actionstaken for Plant Issue N-2004-3605 did not identify all breeches in the Unit 1 containment sump enclosure. The finding had a credible impact on safety based on the dimensions of the breeches which were greater than the analyzed values.

The inspectors reviewed IMCs 0612 and 0609 and determined that the finding was of very low safety significance. Although it impacted the mitigating systemcornerstone, the finding is of very low safety significance because it did not result in a loss of safety function of one or more trains and was not potentially risk-significant due to possible external events. The licensee has this finding documented in their corrective action program as Plant Issue N-2006-1578.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

W. Anthes, Assistant Manager, Maintenance

G. Bischof, Director (former), Nuclear Safety and Licensing

J. Breeden, Supervisor, Radioactive Analysis and Material Control

W. Corbin, Director, Nuclear Engineering

J. Costello, Supervisor, Nuclear Emergency Preparedness (Virginia)

J. Crossman, Assistant Manager, Nuclear Operations

T. Clune, Supervisor, Electrical Maintenance

J. Davis, Site Vice President

R. Evans, Manager, Radiological Protection

R. Foster, Supply Chain Manager

S. Hughes, Manager, Nuclear Operations

P. Kemp, Supervisor, Nuclear Safety & Licensing

J. Kirkpatrick, Manager, Maintenance

L. Lane, Director, Operations and Maintenance

G. Lear, Manager, Organizational Effectiveness

J. Leberstien, Licensing Technical Advisor

T. Maddy, Manager, Nuclear Protection Services

C. McClain, Manager, Nuclear Training

F. Mladen, Manager, Nuclear Site Services

J. Rayman, Emergency Planning Supervisor

G. Salomone, Licensing

M. Sartain, Manager, Nuclear Engineering

J. Scott, Supervisor, Nuclear Training (operations)

B. Standley, Nuclear Site Engineering Assistant Manager

D. Stoddard, Director (new), Nuclear Safety and Licensing

M. Whalen, Station Licensing

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSEDOpened and

Closed

05000338, 339/2006003-01NCVInadequate Corrective Action Results in Failure of ControlRoom Chiller to Start (Section 1R12)

05000338/FIN-2006003-02NCVFailure to Implement a Maintenance Procedure ImpactingPressurizer PORV Operability (Section 1R15)

05000339/FIN-2006003-03NCVFailure to Correct a Condition Adverse to QualityRegarding High Cycle Fatigue Failure of the 2J EDG Lube

Oil Filter Vent Line (Section 4OA2)

A-2AttachmentClosed

05000338/LER-2006-001-00LERManual Reactor Trip Due to Shutdown Bank "A" Group 2Step Counter Inoperable (Section 4OA3)2515/165TIOperational Readiness of Offsite Power and Impact onPlant Risk (Section 4OA5)

Section 1R01: Adverse Weather Protection*Plant Issue

N-2006-3007, Based on inspector identified elevated EDG roomtemperatures, the following issues need to be addressed: Critical equipment affected by high temperature, tracking hours of equipment that exceed its design rating, appropriate monitoring of local temperature indicators (TI) to determine required actions; current method of averaging of local TIs to determine actions, adequacy of procedure for taking action on elevated room temperatures.*Calculation 14937.75-E-18, "Analysis of Operation of Overload Relays in MCCsDuring Station Blackout"*0-GOP-5.5, "EDG Hot Weather Operations"Section 1R02: Evaluation of Changes, Tests, and ExperimentsFull Evaluations*2000-SE-MOD-02, Charging Pump Upgrades*2000-SE-MOD-11, Remove Upper Disc Pressurization Connection Valves andFlanges*2005-SE-OT-01 Isolation of Component Cooling to Containment Penetrations

• 1997-SE-MOD-07, Install Test Taps in HVAC Ducts

• 1991-SE-MOD-076, 3 SG Blowdown Tank Piping Rerouting

• 2004-SE-OT-03, Incorporate Reactor Coolant Environmental Effects in theCalculation of Safety Injection Accumulator and Charging Line Nozzle Cumulative Usage Factors for Safety Injection and Charging Line Nozzles Connected to the Reactor Coolant SystemScreened Out Items*DCP 03-108, MFRV Positioner Modification AV2 to AV1*DCP 04-102, MOV Overall Gear Ratio Modification

• DCP 03-150, 2-FW-62 Replacement

• DCP 02-803 Scaling Change for Delta Flux Input to OTT Function forFramatome Fuel Load*DCP 04-135, Pressurizer Safety Valve Inlet Nozzle Material Reconciliation

A-3Attachment*DCP 04-149, Alternate Containment Temporary Equipment Hatch CoverPenetrations for Framatome Use*DCP 03-168, Install Remote Closure SOV's for Pressurizer Spray Valves

• DCP 01-121, Replace 2" Nozzles on the SI Accumulators

• DCP 03-154, Secondary Side Piping Program - Pipe Replacement

• DCP 04-136, Modify Unit 2 MS H-43 Support

• DCP 03-122, Replace the Agastat Timing Relays in the EDG Load SequencingCircuits in Order to Reduce the Frequency of Out of Tolerance Discoveries*DCP 03-146, Replace 2J EDG Temperature Switches

• DCP 03-133, Modify 2-HV-HV-2 Control Logic to Trip When 2-HV-F-16 Flow Stops*DCP 04-100, Change the Control Method for two MOVs (2-RS-MOV-200A and2-RS-MOV-200B) by Modifying the Torque Switch Bypass to Cover the Entire Close Stroke*DCP 01-162, Replacement of Vital Bus Inverters 2-III & 2-IVProcedures*VPAP-3001, Safety Evaluations, Revision 6*VPAP-3001, Safety and Regulatory Reviews, Revision 12Plant Issues*N-2002-0166, MOV Dynamic Test Data Obtained During

GL 96-05 TestingIndicates Non-Conservative Valve Factors*N-2004-3249, The Safety Review/Regulatory Screen for

DC 03-172 was FoundIn Error During Preparation of Field Change 2

Section 1R04: Equipment AlignmentPartial Walkdown*Procedure

1-OP-7.1A, Valve Checkoff - Low Head Safety Injection System*Procedure 2-PT-57.1B, Emergency Core Cooling Subsystem - Low Head SafetyInjection Pump (2-SI-P-B)*Plant Drawing 12050-FM-096A, Flow Diagram - Safety Injection System

• Plant Issue N-2006-2428, during 1-PT-213.8A noticed "banging or clanging"sound from rod connecting 1-SI-MOV-1860A Valve MotorComplete Walkdown*List of open work orders for Unit 2 Recirculation Spray System*Procedure 2-OP-7.10, "Operation of Casing Cooling S

ubsystem of theRecirculation Spray System"*UFSAR 6.2.2, "Containment Heat Removal Systems - ContainmentDepressurization System"*Plant Issue N-2006-2312, During NRC walkdown Eberline hand and foot monitordoes not meet seismic housekeeping requirements of

VPAP-0312.*Plant Issue N-2006-2313, Boric acid packing leak discovered on 2-RS-ICV-3077by NRC Resident Inspector

A-4AttachmentSection 1R07: Heat Sink PerformanceProcedures*0-PT-75.15, Generic Letter 89-13 Service Water System Testing RequirementsCoordination, Revision 5, dated 08/30/04*2-PT-77.13B, Control Room Chiller Equipment Performance Test (2-HV-E-4B),Revision 10, dated 05/5/04*0-PT- 75.22, Service Water System Reservoir Sludge Depth Measurement,Revision 4, dated 01/17/06*0-PT-75.7, Service Water Reservoir-Ground Water Level, Revision 7, dated

2/14/05*1-PT-9.2, Service Water Reservoir ISI, Revision 3, dated 08/17/04

• 0-PT-75.6.2, Service Water Pump House Drain System: Flow Rate and Clarity,Revision 7, dated 09/14/05*0-PT-75.12, Visual Inspection of the Service Water Reservoir Dike Crest andToe, Revision 3, dated 11/17/05*0-PT-115, Survey of Settlement Monitoring Points, Revision 5, dated 03/27/06

• 2-PT-74B, Component Cooling Heat Exchanger 2-CC-E-1B Performance Test,Revision 008, dated 06/24/06*2-PT-74A, Component Cooling Heat Exchanger 2-CC-E-1A Performance Test,Revision 007, dated 02/03/04*0-PT-75.8, Service Water Reservoir Loss Monitoring Procedure, Revision 003, dated 07/07/04*NASES-3.20, Generic Letter 89-13 Programs, Revision 2, dated 10/05/05Calculations*MAT-0002, Wall Thickness Measurements of Selected Service Water SprayArray Piping Lines at North Anna, Revision 3*MAT-0003, Wall Thickness Measurements of Selected Service Water PipingLines at North Anna, Revision 2*CE-1386, Stability of SWR Dike, Revision 0Drawings*11715-FM- 078A, Sheet 1, Flow/Valve Operating Numbers Diagram ServiceWater System, Revision 63*11715-FM-078A, Sheet 4, Flow/Valve Operating Numbers Diagram ServiceWater System, Revision 94*11715-FP-5AL, Sheet 1, Buried Return Headers Service Water Piping, Revision1

• 11715-FC-38D-13, Sheet 4, Service Water Pump House Outline

• 11715-FP-5A, Sheet 1, Service Water Lines Yard, Revision 19Miscellaneous*Inservice SW pump performance data for last two years*NRC letter to Mr Michael P. Whalen, North Anna Licensing, Summary of DamSafety Inspection for the Service Water Reservoir Dam at North Anna Power Station, dated 09/08/04

A-5Attachment*VEPCO letter to the NRC, Ms. Caverly, VEPCO North Anna Power Station Unit 1& 2 Dam Safety Inspection Response for the Service Water Reservoir, dated

2/10/04*VEPCO letter to the NRC, Ms. Caverly, VEPCO North Anna Power Station Unit 1& 2 Dam Safety Inspection Response for the Service Water Reservoir, dated

01/25/05*VEPCO letter to the NRC, Serial 89-572H, Consolidated Response to GenericLetter 89-13 Service Water Problems Affecting Safety-Related Equipment*FERC letter to North Anna Power Station (P-6335- VA), dated 02/09/06

• Engineering Transmittal No. N02-073, Revision 0, Monitoring of Structures,Report of 5 Year Periodic Inspection, dated 10/30/02 [reviewed SW only]*Engineering Transmittal

CME 99-0039, Revision 0, Component Cooling HeatExchanger Periodic Test 2-PT-74A, Revision 5 06/14/99, dated 06/23/99*Engineering Transmittal

CME 98-0017, Revision 0, Component Cooling HeatExchanger, 2-CC-E-1B Post Installation Performance Test, dated 03/18/98*Final Safety Analysis Report Table 3.9-1, Revision 39 [SW Valve list]

• Inservice Testing Basis, Section 6.20, Service Water, Revision 7

• North Anna Power Station Updated Final Safety Analysis Report, Section 9.2.1Service Water System, dated 02/15/06*MR PI Evaluation Response N-2002-0129-E2, Service Water Spray 1A2 Crack

• PM Task Evaluation N-PMTE-2004-0232, Change Frequency of Inspection andCleaning of Unit 2 CC Heat Exchangers from Annual to Two Years, dated

11/18/04*ITC-SA-04-29, Dominion

GL 89-13 Program Service Water System ProblemsAffecting Safety-Related Equipment*Plant Issue N-2002-0066-B, Heat exchanger inspections

• System Design Basis Document, Section 9, SW Design Requirements, Revision

9*2006 Quarter 1, SW Health Report

• Work Order

5900063688, Unit 2, 1B Component Cooling Heat ExchangerInspection/Cleaning /Plugging, 02/13/06*Work Request

00102667, 1A Service Water Traveling Screen Chain ThicknessBelow 20%, 06/15/05

Section 1R12: Maintenance Effectiveness*N-2003-2665, Cannot maintain Unit 2 rod drive room temperature below thebackboards log spec of 85 F.*N-2006-1021, Due to

PCS high temperature alarm (85 deg F) in U2 Rod Driveplaced 2-HV-HV-2 (rod drive supply) in auto*N-2006-1956, Noted during Unit 2 safeguards logs that both Rod Drive MG setoutput voltages had decreased below the minimum value of 250-270 volts*N-2006-1959, During performance of 1-PT-212.9, "A" main steam trip valvefailed to close in the required time using the "A" SOV*N-2006-1965, During UT examination of Base Metal Excavation 1 Repair 4 onPenetration #74 a ID connected flaw was found

A-6Attachment*N-2006-2361, 2-HV-MOD-2227 Cable Vault Supply Damper is not opening fullywith 2-HV-HV-2 in SLOW*N-2006-2553, found 1-CH-P-1A1 ("A" charging pump aux oil pump) not runningand both lights off locally*N-2006-2574, 01-CH-P-1A1

WO 745597-02, upon disassembly found that one ofthe shaft bushings on the idle gear had severe wear*N-2006-2583, cleared tags on 1-CH-P-1A1 to allow electricians to take amps

• N-2006-2584, lifted tag and ran 1-CH-P-1A1, A CH pump auxiliary oil pump forrotation check, amps and vibes*N-2006-2586, from OPS logs (5/7/06@1145): performed test run of 1-CH-P-1A1following pump work, amps initially at 9 amps with 12 PSIG discharge pressure*Engineering Transmittal

SE-97-025, Rod Drive Room Temperature MonitoringNorth Anna Power Station Units 1 & 2, Revision 0

Section 1R15: Operabiity Evaluations*Drawing 11715-FM-078A, "Service Water System Flow/Valve OperatingNumbers," Revision 35*Procedure

2-PT-75.2A, "Service Water Pump (2-SW-P-1A) Quarterly Test,"Revision 45*Procedure 2-PT-75.2A.1, "Service Water Pump (2-SW-P-1A) Head CurveVerification," Revision 21*ET: N-06-0031

• ET: SE 95-009

• Plant Drawing 11715-PSSK-107L.3, "Vertical Constraint 6"

RS-E15-153A-Q3Casing Cooling Pump House*Work Request WR 208706

Section 1R17: Permanent Plant ModificationsProcedures*VPAP-0301, Design Change Process, Revision 24*STD-GN-001, Instructions

DCP Preparation, Revision 34

• 0-DRP-01, Motor Operated Valve Operating Bands, Revision 13Self Assessment*ITC-SA-04-42, Design IssuesPlant Issues*N-2001-1407, "A" Main Feed Reg Valve Went Through Oscillation*N-2001-1704, "C" Main Feed Reg Valve Was Manually Overridden Due to ErraticOperation*N-2004-4127, 1-RS-MOV-100B Overthrusted/Overtorqued During Setup perDCP 04-103*N-2005-4550, Implementation of

DCP 04-126 for 2-CH-TCV-2143 was notPerformed in Accordance with the DCP

A-7AttachmentPlant Issue Generated as part of the Inspection*N-2006-3253, A Weakness in the Commercial Dedication Program has beenIdentified

Section 1R20:

Refueling and Other Outages*VPAP-2805, "Shutdown Risk Program"*Dominion

Memorandum dated 03/06/06, 2006 Outage Plan Safety Review NorthAnna Unit 1*1-OP-1.4, "Unit Startup from Mode 4 to Mode 3"

• 1-OP-1.7, "Unit Startup from Mode 3 to Mode 2 following Refueling"

• 1-OP-2.1, "Unit Startup from Mode 2 to Mode 1"

Section 1R22: Surveillance Testing*Part 9900: Technical Guidance*Information Notice 97-16, Preconditioning of Plant Structures, Systems, andComponents Before

ASME Code Inservice Testing or Technical Specification Surveillance Testing*Plant Issue N-2006-0864-E1, NRC inspector inquired if step 6.5.3 of 2-PT-71.1Qwas evaluated for preconditioning

Section 4OA5: Other Activities*Procedure

0-OP-4.35,

TN-32 Cask Loading and Handling, Revision 28*Procedure 0-OP-4.36, Cask Transport from Crane Bay to ISFSI, Revision 10

• Procedure C-HP-1032.010, Radiological Survey Records, Revision 5