IR 05000338/2007002

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April 26, 2007

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. 05000338/2007002, 05000339/2007002, AND 07200056/2007001 AND ANNUAL ASSESSMENT MEETING

SUMMARY

Dear Mr. Christian:

On March 31, 2007, the United States Nuclear Regulatory Commission (NRC) completed aninspection 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 April 23, 2007, with Mr. Dan Stoddard 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, two self-revealing findings of very low safetysignificance (Green) were identified. One of these was determined to involve a violation of NRC requirements. However, because of its very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A of the NRC Enforcement Policy. If you contest the 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 NuclearRegulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the North Anna Power Station.In 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 VEPCO 2NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).Sincerely,/RA/Eugene F. Guthrie, ChiefReactor Projects Branch 5 Division of Reactor ProjectsDocket Nos.:50-338, 50-339, 72-056License Nos.:NPF-4, NPF-7Enclosures:Inspection Reports 05000338/2007002, 05000339/2007002, and07200056/2007001 VEPCO 2NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).Sincerely,/RA/Eugene F. Guthrie, ChiefReactor Projects Branch 5 Division of Reactor ProjectsDocket Nos.:50-338, 50-339, 72-056License Nos.:NPF-4, NPF-7Enclosures:Inspection Reports 05000338/2007002, 05000339/2007002, and07200056/2007001X PUBLICLY AVAILABLE X NON-SENSITIVEADAMS: X YesACCESSION NUMBER:_________________________OFFICERII:DRPRII:DRPRII:DRPRII:DRSSIGNATURELXG1JTRGXG forRCC2NAMELGarnerJReeceGWilsonRChouDATE04/26/200704/26/200704/26/200704/26/20074/ /20074/ /20074/ /2007E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICIAL RECORD COPY DOCUMENT NAME: C:\FileNet\ML071160395.wpd VEPCO 3cc w/encls.:Chris L. Funderburk, Director Nuclear Licensing and Operations Support Virginia Electric and Power Company Electronic Mail DistributionDaniel G. StoddardSite 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 (See page 4)

VEPCO 4Report to David A. Christian from Eugene F. Guthrie dated April 26, 2007SUBJECT:NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTIONREPORT NOS. 05000338/2007002, 05000339/2007002, AND 07200056/2007001 AND ANNUAL ASSESSMENT MEETING SUMMARYDistribution w/encls.:S. Monarque, NRR L. Slack, RII RIDSNRRDIPMLIPB PUBLIC EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos.:50-338, 50-339, 72-056License Nos.:NPF-4, NPF-7 Report Nos.:05000338/2007002, 05000339/2007002, 07200056/2007001 Licensee:Virginia Electric and Power Company (VEPCO)

Facilities:North Anna Power Station, Units 1 & 2, and the North Anna Independent SpentFuel Storage InstallationLocation:1022 Haley DriveMineral, Virginia 23117Dates:January 1, 2007 - March 31, 2007 Inspectors:J. Reece, Senior Resident InspectorG. Wilson, Resident Inspector R. Chou, Reactor Inspector, Section 4OA5.1Approved by:E. Guthrie, Chief, Reactor Projects Branch 5Division of Reactor Projects EnclosureSUMMARY OF FINDINGSIR 05000338/2007-002, IR 05000339/2007-002; IR 07200056/2007001; 01/01/2007 -03/31/2007; North Anna Power Station Units 1 and 2 and North Anna Independent Spent Fuel Storage Installation. Maintenance Effectiveness and Surveillance Testing.The report covered a three-month period of inspection by the resident inspectors and a reactorinspector from the region. Two self-revealing findings were identified. One of which was determined to be a Non-cited Violation (NCV). The significance of most findings is indicated bytheir 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 commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.A.NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified for inadequate implementation of anon-quality procedure associated with the equipment reliability process. This led to a

'run-to-failure' classification for two different 7300 System cards which each resulted in a reactor trip on Unit 1 and 2.This self-revealing finding is greater than minor because it resulted in a perturbation inplant stability by causing a reactor trip. The finding was of very low safety significance because, although it caused a reactor trip, it did not increase the likelihood of a primary or secondary system loss of coolant accident initiator, did not contribute to a combination of a reactor trip and loss of mitigation equipment functions, and did not increase the likelihood of a fire or internal/external flood. The licensee entered the problem involving Units 1 and 2 into their corrective action program. This finding involves the safety-significant and risk significant decisions aspect of the human performance cross-cutting area because the licensee incorrectly determined that operators had sufficient time to take necessary actions to preclude a plant trip when the cards failed. (Section 1R12)

Cornerstone: Mitigating Systems

Green.

A self-revealing non-cited violation of Technical Specification (TS) 5.4.1.a wasidentified for a failure to adequately implement a surveillance procedure which resulted in the inoperability of the 2J Emergency Diesel Generator (EDG). The licensee restored the EDG to operable status and initiated actions to evaluate the problem and determine the appropriate corrective actions.This finding is more than minor due to its impact on the Mitigating Systems cornerstoneobjective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and its attribute of human performance. The finding is of very low safety significance because the 2J EDG was not out of service for longer than the allowed Technical Specification time. The cause of 3Enclosurethe finding involved the procedure compliance aspect of the human performancecross-cutting area because personnel failed to correctly perform a procedure step, which included a separate verification. (Section 1R22)

B.Licensee-Identified Violations

None.

Enclosure

REPORT DETAILS

Summary of Plant StatusUnit 1 and Unit 2 began the inspection period at 100 percent rated thermal power (RTP).Unit 1 remained at or near 100 percent RTP for the entire reporting period except for minorpower reductions to perform required periodic testing, and for an automatic reactor trip that occurred on January 3, 2007, as a result of a "B" steam generator low level coincident with a steam flow greater than feed flow mismatch which was caused by closure of the "B" main feed regulating valve (MFRV). Unit 1 returned to service and achieved 100 percent RTP on January 5, 2007.Unit 2 had a forced power reduction on February 27, 2007, to approximately 30 percent RTPdue to entry into Technical Specification (TS) 3.0.3 for the inoperability of both trains of the emergency core cooling system pump room exhaust air cleanup system. The unit returned to approximately 99 percent RTP on March 1, 2007, and started a slow power coastdown to a planned refueling outage which began on March 18, 2007. The unit remained off line through the end of the reporting period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection

a. Inspection Scope

On February 6, 2007, the inspectors reviewed the licensee's adverse weatherpreparations for emergent cold weather operations specified in Procedures 0-GOP-4.2,

"Extreme Cold Weather Operations," and 0-GOP-4.2A, "Extreme Cold Weather Daily Checks." The inspectors walked down the impacted areas to verify compliance with the procedural requirements and to verify that the specified actions provided the necessary protection for the structures, systems, or components.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

a. Inspection Scope

The inspectors conducted three equipment alignment partial walkdowns to evaluate theoperability 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 system descriptions, Updated Final Safety Analysis Report (UFSAR), system operating procedures, and TS to determine correct system lineups for the current plant conditions.

The inspectors performed walkdowns of the systems to verify that critical components 5Enclosurewere properly aligned and to identify any discrepancies which could affect operability ofthe redundant train or backup system.*Unit 1 1J Emergency Diesel Generator (EDG) during planned maintenance onthe 1H EDG;*Offsite circuit to Unit 2 2J 4160V bus during partial loss of offsite power to the 2H 4160V bus; and, *Unit 1 1H and 1J EDGs and Unit 2 2J EDG during planned maintenance on Unit2 2H EDG.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted tours of the eleven areas listed below and important toreactor safety 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, and features; and, (3) the fire barriers used to prevent fire damage or fire propagation.*Emergency Switchgear Room Unit 1 & 2 (fire zones 6-1a / ESR-1 and 6-2a /ESR-2);*Battery Room 1-1 Unit 1 and 2-1 Unit 2 (fire zones 7A-1 / BR1-I and 7A-2 /BR2-I);*Battery Room 1-IV Unit 1 and 2-IV Unit 2 (fire zones 7D-1/ BR1-IV and 7D-2 /BR2-IV);*Emergency Diesel Generator 2H and 2 J Unit 2 (fire zones 9A-2a / EDG-2H and9B-2a / EDG-2J);*Emergency Diesel Generator 1H and 1J Unit 1 (fire zones 9A-1a / EDG-1H and9B-1a / EDG-1J);*Auxiliary Building (includes Z-18 and Z-20) (fire zone 11a /);

  • Charging Pump Cubicle 2-1C (fire zone 11Fa / CPC-2C);
  • Casing Cooling Tank & Pump House Unit 1 and Unit 2 (fire zones Z-41-1 / CCT& PH-1 and Z-41-2 / CCT&PH-2);*Fuel Oil Pump Room - Motor Center Room (fire zone 10C / MCC);
  • Cable Tray Spreading Room Unit 1 (fire zone 4-1b / CSR-1) and Cable TraySpreading Room Unit 2 (fire zone 4-2b / CSR-2); and,*Normal Switchgear Room Unit 1 (fire zone 5-1 / NSR-1) and Normal SwitchgearRoom Unit 2 (fire zone 5-2 / NSR-2).

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors assessed the internal flooding vulnerability of the Unit 1 and 2 chargingpump cubicles, and the Unit 1 and 2 air conditioning fan rooms (ACFR) relative to the adjacent air conditioning chiller rooms to verify that the flood protection barriers and equipment were being maintained consistent with the UFSAR. The licensee's 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 also reviewed the maintenance history and current open work orders for the flood control components. The inspectors conducted a field survey of the selected areas to evaluate the adequacy of flood barriers, floor drains, sump level switches, and sump pumps to protect the equipment, as well as their overall material condition.

b. Findings

The inspectors identified issues related to design and preventative maintenance of thebackflow preventers installed in the charging pump cubicle floor drains and the ACFR floor drains. The issues are identified as an unresolved item (URI) pending additional information from the licensee. This URI is designated 05000338, 339/2007002-01, Backflow Preventer Design and Preventative Maintenance Evaluation.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed a licensed operator requalification simulator scenario on March16, 2007. Simulator Exercise Guide, SEG-8A, involved a failure of the charging flow control valve, a loss of the 'B' motor generator set, opening of moisture separator reheater safety valve, a trip of 1A charging pump with failure of the auto-start of 1B charging pump, and a steam line leak in containment on the 'B' steam generator.The inspectors observed crew performance in terms of communications; ability to taketimely 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 oversightand 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 instructors and reviewed with the operators.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the two 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 system engineers. 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.*The Station Blackout (SBO) Diesel Generator N-PM TER-2007-0020 associatedwith Work Order (WO) 767527-01; and,*Maintenance issues relating to 7300 System Cards and associated reactor tripsdocumented in Condition Reports CR004545 and CR006047.

b. Findings

Inadequate Implementation of a Non-quality Procedure Results in Reactor TripsIntroduction: A Green, self-revealing finding for inadequate implementation of anon-quality procedure was identified. Not implementing the procedure properly resulted in components, which could by themselves result in a reactor trip, being excluded from the preventive maintenance program.Description: On November 16, 2006, an automatic reactor trip occurred on Unit 2 due toB steam generator (SG) low level coincident with a steam flow greater than feed flow mismatch which resulted from closure of the B MFRV. The inspectors reviewed root cause evaluation (RCE) 000022, which concluded that age related failure of one or more transistors in a power supply circuit of a 7300 system isolator card impacted the steam flow input to the B SG water level control circuit. The inspectors also noted that both RCE000022 and the respective Condition Report CR004545 identified the card as

'run-to-failure' (RTF) with no preventative maintenance in accordance with the licensee's equipment reliability process.On January 3, 2007, an automatic reactor trip occurred on Unit 1 due to B SG low levelcoincident with a steam flow greater than feed flow mismatch which resulted from closure of the B MFRV. The inspectors reviewed RCE000029 which noted that an age related failure of a capacitor on the 7300 system final control card resulted in closure of the B MFRV. Further review by the inspectors determined that associated Condition 8EnclosureReport CR006047 identified the affected card as RTF with no preventative maintenanceunder the licensee's equipment reliability program.The inspectors reviewed the licensee's equipment reliability process, based on anindustry wide standard, and implemented by non-quality procedure ER-AA-10,

"Equipment Reliability Process," Revision 0. The first of six major process steps in this procedure consists of scoping and identification of critical components which includes in part the identification of critical, noncritical, RTF, and single point vulnerability (SPV)components. The inspectors also reviewed licensee procedural guidelines, ER-AA-PRS-1005, "Single Point Vulnerability Reviews," Revision 0, and ER-AA-PRS-1003, "Component Classifications," Revision 2, both of which are used to implement steps within procedure ER-AA-10. ER-AA-PRS-1005 defines SPV as a single component (electrical, control, or mechanical) that by failure would cause any of the following (partial list): *An immediate automatic reactor trip*A manual reactor trip based on:*A condition that could not be mitigated in sufficient time to prevent amanual reactor trip.*A condition that would initiate procedure directed actions that wouldcause the operators to trip the reactor.As noted above, both 7300 system cards involved in the unit trips were evaluated andclassified as RTF since they were not a critical or SPV component. The non-SPV component classification was based upon the assumption that the operators had sufficient time to mitigate the card failure. The definition of RTF within procedure ER-AA-10 states, "A Run-to-Failure Component is one for which the risks and consequences of failure are acceptable without any predictive or repetitive maintenance being performed and there is not a simple, cost-effective method to extend the useful life of the component. The component should be run until corrective maintenance is required." Thus, the inspectors independently concluded that the licensee failed to meet a standard established by the non-quality procedure ER-AA-10, in that, the affected 7300 system cards should have been evaluated as a SPV component and not classified as RTF. This failure resulted in a reactor trip each on Unit 1 and Unit 2.Analysis: The inspectors determined that the failure to adequately implementnon-quality procedure ER-AA-10 to identify the affected 7300 system cards as SPV components was a performance deficiency. The inspectors referenced Inspection Manual Chapter (IMC) 0612 and determined this finding was more than minor because it impacted the initiating event cornerstone objective to limit the likelihood of those events that upset plant stability and the related attribute of equipment reliability. The inspectors referenced IMC 0609 for the Significance Determination Process (SDP) and determined that the finding was of very low safety significance, Green, because it did not increase the likelihood of a primary or secondary system loss of coolant accident initiator, did not contribute to a combination of a reactor trip and loss of mitigation equipment functions, and did not increase the likelihood of a fire or internal/external flood. This issue is in the licensee's corrective action program as CR004545 (Unit 2) and CR006047 (Unit 1).

9EnclosureThis finding involves the safety-significant and risk significant decisions aspect of thehuman performance cross-cutting area because the licensee incorrectly determined that operators had sufficient time to take necessary actions to preclude a plant trip when the cards failed.Enforcement: No violation of regulatory requirements were identified. The findinginvolved a non-quality plant procedure and process. Therefore, this finding is identified as a Green finding FIN 05000338, 339/2007002-02, Inadequate Implementation of a Non-quality Procedure Results in Reactor Trips.

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 unforseen situation, 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 the licensee's safety monitor associated with the risk profile of Units 1 and 2.*Unplanned extension of 0-AAC-DG-0M (Station Blackout Diesel Generator)outage with following equipment unavailable: 2-HV-E-44, 2-HV-AC-7, 2-RH-P-14, 1-BLD-DR-M54-1, 2-BLD-DR-M54-14 in addition to a planned test 2-PT-14.3 (2-CH-P-1C);*Maintenance rule risk evaluation for unplanned entry into Procedure 0-AP-41,"Severe Weather Conditions," with the following risk significant equipment unavailable and procedures in progress: 2-CC-P-1B, 1-PT-36.9.1J, 1-PT-36.5.3B, 2-PT-30.4.4, switchyard and rack work, 1-BLD-DR-M54-1, 2-BLD-DR-M54-14, "C" Reserve Station Service Transformer (RSST on overhear lines;*Emergent work on the "B" RSST (FAUCT) with the following equipmentunavailable: 1-BLD-DR-M54-1, 2-BLD-M54-14, 1-FP-RST-1B, and 1-MS-PCV-101A;*Emergent work during orange risk condition due to inoperable backflowpreventer 1-DB-BFP-5, with the following equipment unavailable: 1-HV-E-4c, 1-CW-P-1B, and 2-CW-P-1C;*Emergent red risk condition due to inoperable backflow preventer 1-DB-BFP-6,with 1-CW-P-1B unavailable; and,*Planned maintenance work on 1-CW-P-1B with the following equipmentunavailable: 1-BLD-DR-M54-1, 2-EE-EG-2H, 1-SW-MOV-120A, and 1-SW-MOV-120B.

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 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 SDP. The inspectors' review included a verification that determinations of operability were made as specified by Procedure VPAP-1408,

"System Operability." *Condition Report CR006341, in review of 1-PT-64.8, flow test of the insiderecirculation spray pumps, it was determined that the current acceptance criteria were not correctly developed in accordance with Interval Three IST Program;*Condition Report CR006789, SR 3.0.3 was improperly applied to missedsurveillance of AFW check valves in CR006689 as the application of SR 3.0.3 is not applicable since this was a nonconforming condition;*Condition Report CR006590, 2-RS-P-1B IRS pump started during slave relaytesting (2-PT-36.5.3B), 2-RS-P-1B started when a step in the procedure was performed;*Condition Report CR007054, during 2H EDG surveillance test, the #1 controlside fuel pump control rack leakage increased to 30 drops per minute;*Condition Report CR007838, review of CR000070: basis for initial reasonableexpectation of continued operability of Train IV bottled air system following failure of Train III bottled air; and,*Condition Report CR007831, review of CR000069: basis for reasonableexpectation of continued operability of 1J EDG due to inspection cover with loose fasteners.

b. Findings

No findings of significance were identified.

1R19 Post 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) the 11Enclosureeffect of testing on the plant had been adequately addressed by control room and/orengineering 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-MPM-0701-04, "Maintenance Run Test Procedure of EmergencyDiesel Generator," Revision 13, per WO 733954-01 to replace section of outer radiator on 1H EDG;*Procedures PMT-LKT-MM-0001, "Post Maintenance External Leakage Test,"and 0-NAT-M-004, "System Pressure/Leak Test," Revision 4, per WOs 746382-01 and 764869-01 to replace 2" ball valves (1-QS-56-valve and 1-QS-52-valve);*Procedures 0-PT-82.11, "Quarterly Test of 0-AAC-DG-OM Alternate AC DieselGenerator (SBO Diesel) on D Transfer Bus," Revision 15, 0-PT-82.12, "Quarterly Test of 0-AAC-DG-OM. Alternate AC Diesel Generator (SBO Diesel) on E Transfer Bus," Revision 15, and 0-PT-82.13, "Quarterly Test of 0-AAC-DG-OM, Alternate AC Diesel Generator (SBO Diesel) on F Transfer Bus," Revision 14, per WOs 750921-01 and 742532-01;*Procedures 0-EPM-0103-01, "Battery Charger Inspection," Revision 16, and2-EPM-0108-06, "Testing of Station Battery Swing Charger 2C-II Alarms,"

Revision 3, per WOs 751130-01 and 751173-1;*Procedure PMT-LKT-MM-0001, "Post Maintenance External Leakage," per WOs769271-01, and 748592-01 to replace the relief valve; and,*Procedures 1-PT-130.4, "Valve Inservice Inspection for 2-RS-103 and2-RS-118," Revision 8, and PMT-LKT-MM-001, "Post Maintenance External Leakage Test," per WOs 741548-01 and 745268-01 for the recirculation spray casing cooling pump discharge valve ISI inspection.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities

.1 Refueling Outage

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan and contingency plans for the Unit 2refueling outage, which began on March 18, 2007, and continued through the end of the reporting period, to confirm that the licensee had appropriately considered risk, industry 12Enclosureexperience, and previous site-specific problems in developing and implementing a planthat assured maintenance of defense-in-depth. The inspectors used Inspection Procedure 71111.20, "Refueling and Outage Activities," to observe portions of the shutdown and cooldown 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 evaluatedefense-in-depth commensurate with the outage safety plan and compliance with the applicable TS when taking equipment out of service.*Installation and configuration of reactor coolant instruments to provide accurateindication and an accounting for instrument error.*Controls over the status and configuration of electrical systems and switchyard toensure that TS and outage safety plan requirements were met.*Licensee implementation of clearance activities to ensure equipment wasappropriately configured to safely support the work or testing.*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 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.

b. Findings

No findings of significance were identified.

.2 Other Outages

a. Inspection Scope

The inspectors evaluated the licensee's activities during a forced outage caused by aunit trip on January 3, 2007, when the "B" Steam Generator low level coincident with a steam flow greater than feed flow mismatch caused the closure of the "B" main feed regulating valve. The cause was the result of an age related failure of an isolator card.

The inspectors verified that appropriate risk consideration was given for schedules impacted by the emergent work and monitored startup activities to verify that TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant conditions.

b. Findings

Section 1R12 discusses related enforcement actions.

13Enclosure1R22Surveillance Testing

a. Inspection Scope

For the seven surveillance tests listed below, the inspectors examined the testprocedure, witnessed testing, and 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 the 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. The inspectors reviewed five in-service testing activities for a risk significant pump or valve as part of the surveillance activities.In-Service Tests:*2-PT-63.1B, "Quench Spray System - 'B' Subsystem," Revision 30*2-PT-71.3Q, "2-FW-P-3B Motor Driven AFW Pump and Valve Test," Revision 30

  • 1-PT-71.1 Q, "1-FW-P-2 Turbine Driven AFW Pump and Valve Test,"Revision 44*2-PT-14.3, " Charging Pump 2-CH-P-1C," Revision 40
  • 1-PT-57.1B, "Emergency Core Cooling Subsystem - Low Head safety InjectionPump (1-SI-P-1B)," Revision 45Other Surveillance Tests:*2-PT-82J, "2J Emergency Diesel Generator Slow Start Test," Revision 42*2-PT-83.4.1, "Degraded Voltage/Loss of Voltage and CDA Functional (ITSOperational) Test of CRDM Fans," Revision 4

b. Findings

Failure to Implement Procedure Results in Inoperability of 2J Emergency DieselGeneratorIntroduction: A self-revealing non-cited violation (NCV) of TS 5.4.1.a was identified for afailure to adequately implement a surveillance procedure which resulted in the inoperability of 2J EDG.

Description:

On March 18, 2007, during the implementation of control rod drivemechanism (CRDM) fan testing on Unit 2 in accordance with procedure 2-PT-83.4.1,

"Degraded Voltage/Loss of Voltage and CDA Functional (ITS Operational) Test of CRDM Fans," Attachment 1, step 4.2 instructed the licensee to lift wire, 2HVRD04X00 from terminal RD-11 located in emergency switchgear cubicle 25J2A. The following step, 4.3, instructed the licensee to verify that the D CRDM fan trips. However, the licensee went to the wrong cubicle, 25J2, and lifted a wire from terminal, RD-11, which affected the 2J EDG output breaker voltage restraint overcurrent relay and resulted in the inoperability of 2J EDG. The licensee did not identify the problem until they 14Enclosuredetermined that the CRDM fan failed to trip after the lead was lifted, and 2J EDG waslogged inoperable from 0845 to 1155 hours0.0134 days <br />0.321 hours <br />0.00191 weeks <br />4.394775e-4 months <br /> on March 18, 2007. The inspectors noted that the performance of the procedure step required separate verification by another individual; i.e., two individuals were involved in the failure to adequately implement the procedure.Analysis: The inspectors determined that the failure to adequately implement aprocedure as required by TS 5.4.1a constituted a performance deficiency since it resulted in the inoperability of an emergency diesel generator. In accordance with IMC 0612, the inspectors 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 prevent undesirable consequences and the related attribute of human performance. The inspectors evaluated this finding using IMC 0609, Appendix A and determined that it was of very low safety significance (Green), in that, it did not result in a loss of operability due to a design or qualification deficiency, did not represent an actual loss of safety function, did not result in a train being out of service longer than allowed by TSs, and was not potentially risk significant due to possible external events.The cause of the finding involved the procedure compliance aspect of the humanperformance cross-cutting area because personnel failed to correctly perform a procedure step, which included a separate verification.Enforcement: TS 5.4.1.a, requires in part that written procedures specified inRegulatory Guide 1.33, Appendix A, of which Part 8 stipulates procedures for surveillance tests, shall be implemented. Contrary to the above on March 18, 2007, step 4.2 of 2-PT-83.4.1 was inadequately implemented in that the licensee went to the wrong cubicle, 25J2, and lifted a wire from terminal, RD-11, which affected the 2J EDG output breaker voltage restraint overcurrent relay and resulted in the inoperability of 2J EDG. This finding is of very low safety significance or Green, is in the licensee's corrective action program as Condition Report CR008829, and is characterized as a NCV, consistent with Section VI.A of the NRC's Enforcement Policy: NCV 05000339/2007002-03, Failure to Implement Procedure Resulting in the Inoperability of 2J Emergency Diesel Generator.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed three temporary plant modifications to verify that themodifications did not affect system operability or availability as described by the TS and UFSAR. In addition, the inspectors verified that the installation of the temporary modifications 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 modifications reviewed were:

15Enclosure*Temporary Modification 1776, "the installation of three pneumatic jumpers from1-MS-TCV-1408A to 1-MS-TCV-1408C to provide cooldown function due to the inoperability of 1-MS-TCV-1408A;"*Temporary Modification 1777, "fire protection jumper to Unit 2 circulating waterscreen wash;" and,*Temporary Modification 1780, "Ground on B RSST feeder to 25B1 requiresreplacement of cable 2NN5BNH013. A temporary modification is required until the replacement cable can be procured and installed."

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES4AO1Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors reviewed the licensee's procedure for developing the data for theInitiating Events PI which are: (1) Unplanned Scrams ; (2) Scrams with Loss of Normal Heat Removal; and (3) Unplanned Power Changes (Transients per 7000 Critical Hours).

The inspectors examined data reported to the NRC for the period January, 2005, to December 2006. Procedural guidance for reporting PI information and records used by the licensee to identify potential PI occurrences were also reviewed for both units. The inspectors reviewed the licensee event reports, monthly operating reports, operating logs, inspection reports, corrective action programs documents, and maintenance rules records as part of the verification process. The inspection was conducted in accordance with NRC Inspection Procedure 71151, "Performance Indicator Verification." The applicable planning standards, 10 CFR 50.9 and NEI 99-02,"Regulatory Assessment Performance Indicator Guidelines," were used as reference criteria.

b. Findings

No findings of significance were identified.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 and Condition Report report summaries 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 forCondition Report CR006047, "Card failure for 1-FW-FCV-1488 caused valve to shut.

Manual operation could not restore level prior to a Rx trip for FF/SF mismatch and low steam generator level." The condition report was reviewed 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 condition report 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

There were no findings of significance identified. On January 3, 2007, the licenseeinitiated Condition Report CR006047 in response to a 7300 system card failure for "B" MFRV (1-FW-FCV-1488) which caused the valve to shut and a Unit 1 reactor trip. The licensee subsequently initiated a root cause evaluation that determined that the card failure was due to a shorted capacitor (C42). The inspectors reviewed the licensee's evaluation and discovered that the failed capacitor was previously identified by the licensee as requiring to be upgraded on all 7300 system driver cards in Plant Issue N-2003-1449-R7. The inspectors determined that the licensee had performed a single point vulnerability evaluation for 7300 system cards and designated only the final driver cards as "critical". The control cards, e.g. for 1-FW-FCV-1488, were not designated as critical but instead defined as run-to-failure per their equipment reliability program. The inspectors noted that the licensee relied on operator actions to maintain control of the plant due to the failure of non-driver cards (refer to Section 1R12 for discussion and a related finding associated with classification of the affected card). While upgrading the driver cards with the new capacitor C42, the licensee decided not to perform the capacitor refurbishment on the cards in stock, but to replace the capacitors on cards as they came out of the plant to the repair facility. The inspectors concluded that this was a vulnerability as the cards in stock that were not upgraded with the new capacitor could have been issued to the plant for installation into the 7300 system. These cards could have failed and challenge operation of the unit. The card that failed on January 3, 2007, was designated as a non-driver card and consequently did not get upgraded. The licensee subsequently replaced the failed card with an upgraded card and is currently re-evaluating their SPV evaluation. The licensee is planning additional correctiveactions. Additional documents reviewed are listed in the Attachment.4OA3Event Followup

.1 (Closed) Licensee Event Report (LER) 05000339/2006001-00:

Reactor Trip Due toSteam Generator Low Level Coincident With a Steam Flow Feed Flow Mismatch 17EnclosureOn November 16, 2006, an automatic reactor trip occurred on Unit 2 due to B SG lowlevel coincident with a steam flow greater than feed flow mismatch which resulted from closure of the B MFRV. The cause of the trip was age-related failure of the 7300 System card associated with "B" SG, Channel III, steam flow. The licensee documentedthis problem in Condition Report CR004545. Additional details and a finding relating tothis unit trip are documented in Section 1R12 of this report. This LER is closed.

.2 (Closed) LER 05000338/2007001-00:

Reactor Trip Due to Steam Generator Low LevelCoincident with a Steam Flow Feed Flow MismatchOn January 3, 2007, an automatic reactor trip occurred on Unit 1 due to B SG low levelcoincident with a steam flow greater than feed flow mismatch. This resulted from closure of the B MFRV due to age-related failure of a capacitor on the respective 7300 System control card. The licensee documented this problem in CR006047. Additional details and a finding relating to this unit trip are documented in Section 1R12 of this report. This LER is closed.

.3 Unit 1 Reactor Trip - January 3, 2007

a. Inspection Scope

The inspectors responded to a Unit 1 automatic reactor trip on January 3, 2007. The inspectors discussed the trip with operations, engineering, and licensee management personnel to gain an understanding of the event and assess followup actions. The inspectors reviewed operator actions taken in accordance with licensee procedures and reviewed unit and system indications to verify that actions and system responses were as expected. The inspectors discussed the trip with the licensee's root cause analysis team and assessed the team's actions to gather, review, and assess information leading up to and following the trip. The inspectors later reviewed the unit trip report and initial RCE to assess the detail of review, adequacy of the RCE and proposed corrective actions prior to unit restart. The licensee's investigation identified that the cause of the trip was failure of a 7300 system card associated with "B" MFRV. The inspectors also reviewed the initial licensee notifications to verify that the requirements specified in NUREG-1022, Event Reporting Guidelines, were met.

b. Findings

A related finding regarding this unit trip is documented in Section 1R12.

.4 Unit 2 Forced Power Reduction - February 27, 2007

a. Inspection Scope

The inspectors responded to a Unit 2 forced power reduction on February 27, 2007, dueto entry into TS 3.0.3 for the inoperability of both trains of the emergency core cooling system pump room exhaust air cleanup system. The inspectors reviewed operator actions taken in accordance with licensee procedures and reviewed unit and system 18Enclosureindications to verify that actions and system responses were as expected. Theinspectors also reviewed the initial licensee notifications to verify that the requirements specified in NUREG-1022, Event Reporting Guidelines, were met.

b. Findings

No findings of significance were identified.

.5 Unit 2 Partial Loss of Offsite Power - March 7, 2007

a. Inspection Scope

On March 7, 2007, the inspectors responded to a partial loss of offsite power on Unit 2involving the loss of the B RSST and resultant undervoltage on the 2H emergency bus.

The 2H EDG started as required to restore power to the affected bus, and operators responded in accordance with their procedures. The inspectors reviewed operator actions taken in accordance with licensee procedures and reviewed unit and system indications including 2H EDG operation to verify that actions and system responseswere as expected. The inspectors also reviewed the initial licensee notifications to verify that the requirements specified in NUREG-1022, Event Reporting Guidelines, were met.

b. Findings

No findings of significance were identified.4OA5Other Activities

.1 Independent Spent Fuel Storage Installation (ISFSI) (Inspection Procedure 60853)

a. Inspection Scope

The inspectors examined installation of the reinforcing steel and wood form work,observed the concrete pour, and reviewed documents for the ISFSI Cask Storage Pad. The inspectors examined reinforcing steel and concrete wood form work for ISFSI pad2, southeast section for an area of 21' - 6" X 82' - 0" to ensure that they were installed within cleanliness and tightness requirements, and that the licensee had measured the reinforcing steel diameter, spacing, splice length, and the concrete minimum protection coverage in accordance with the requirements of the design drawings and the American Concrete Institute. The inspectors reviewed the concrete pre-placement inspection checklist and quality inspection logs of the daily inspection reports performed by the licensee quality control personnel and field notes of the observations conducted by the independent quality testing contractor, including soil compaction and tests. The inspectors reviewed the procedures, specifications, and calculations for the concretepad construction activities. The inspectors also reviewed the licensee cold weather concrete activity protection with the requirements of American Concrete Institute.

19EnclosureThe inspectors witnessed placement of concrete for ISFSI pad 2, southeast section. The inspectors observed placement activities to verify that activities pertaining to concrete delivery time, flow distance, layer thickness and concrete consolidation or vibration conformed to industry standards established by the American Concrete Institute. Concrete batch tickets were examined to verify that the specified concrete mix was being delivered to the site, and that concrete placement activities were continuously monitored by the licensee and qualified contractors. The inspectors witnessed in-process testing and reviewed the results for slump, air content, temperature, unit weight, and molding of the concrete cylinders for the compressive strength testing, and also witnessed sample points to verify that concrete samples for the field testing and cylinders for the testing were obtained at the point of placement (end of pump line). The inspectors reviewed subsequent test results to verify that compressive strength testing was adequate, that the cylinders were molded in accordance with applicable American Society for Testing and Materials requirements, and that concrete field testing was performed by qualified inspectors from an independent testing company.The inspectors also reviewed records documenting inspection of the concrete batchplant and the concrete truck mixers performed by an independent engineering and consulting company. The consulting company verified that the batch plant and trucks were certified by Virginia Department of Transportation (VDOT). The licensee approved the batch plant and trucks to be certified by VDOT instead of National Ready Mixed Concrete Association.Activities were reviewed to determine if the consulting company's inspection orverification of the trucks and batch plant were performed in accordance with engineering requirements. The inspectors reviewed the concrete mix data to ensure that mix proportions for delivered concrete were selected based on trial concrete mix results, and that the trial mix met concrete strength requirements. Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Review of the Operation of an Independent Spent Fuel Storage Installation (InspectionProcedure 60855)

a. Inspection Scope

Inspectors reviewed the normal operations of the ISFSI. The inspectors walked downthe ISFSI pad to assess the material condition of the casks, the installation of security equipment, and the performance of the monitoring systems. In preparation for an upcoming cask loading the inspectors reviewed licensee cask loading and handling procedures and reviewed previous cask loading and ISFSI related plant issues and corrective actions status. The inspectors also reviewed bridge crane lubrication /

inspection work orders completion data and calibration data sheets for equipment that would be used during cask loading.

b. Findings

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

.1 Integrated Report ExitOn April 23, 2007, the inspectors presented the inspection results to Mr. Dan Stoddardand other members of the staff.

The licensee 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..2Annual Assessment Meeting SummarySubsequent to the end of this inspection period, on April 24, 2007, the NRC's Chief ofReactor Projects Branch 5 and the Resident Inspector assigned to the North Anna Power Station met with Virginia Electric and Power Company to discuss the NRC's Reactor Oversight Process (ROP) and the NRC's annual assessment of North Anna's safety performance for the period of January 1 through December 31, 2006. The major topics addressed were the NRC's assessment program, and the results of the North Anna assessment. Attendees included North Anna site management, members of the site staff, corporate management and two reporters.This meeting was open to the public. The presentation material used for the discussionand the list of attendees is available from the NRC's document system (ADAMS) as accession numbers ML071160004 and ML071160003, respectively. ADAMS is accessible from the NRC Web site at http://www/nrc.gov/reading-rm/adams.html (thePublic Electronic Reading Room).ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

W. Anthes, Assistant Manager, MaintenanceM Sartain, Director, 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
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, Plant Manager
J. Leberstien, Licensing Technical Advisor
T. Huber, Director, Site Engineering
T. Maddy, Manager, Nuclear Protection Services
M. Main, Component Engineer
C. McClain, Manager, Organizational Effectiveness
F. Mladen, Manager, Nuclear Site Services
J. Rayman, Emergency Planning Supervisor
H. Royal, Manager, Nuclear Training
G. Salomone, Licensing
M. Sartain, Manager, Nuclear Engineering
J. Scott, Supervisor, Nuclear Training (operations)
R. Sprouse, ISFSI Construction Supervisor
D. Stoddard, Site Vice President
M. Whalen, Licensing Specialist
R. Williams, Component Engineer

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSEDOpen05000338, 339/2007002-01URIBackflow Preventer Design and Preventative MaintenanceEvaluation (Section 1R06)

Opened and Closed

05000338, 339/2007002-02FINInadequate Implementation of a Non-quality ProcedureResults in Reactor Trips (Section 1R12)05000339/2007002-03NCVFailure to Follow Procedure Resulting in the Inoperabilityof 2J Emergency Diesel Generator (Section 1R22)

A-2AttachmentClosed05000339/2006001-00LERReactor Trip Due to Steam Generator Low LevelCoincident With a Steam Flow Feed Flow Mismatch

(Section 4OA3.1)05000338/2007001-00LERReactor Trip Due to Steam Generator Low LevelCoincident with a Steam Flow Feed Flow Mismatch

(Section 4OA3.2)DiscussedNone

LIST OF DOCUMENTS REVIEWED

==Section 1R12: Maintenance Effectiveness*Condition Report

006816, required parts for==
AAC Diesel maintenance notordered*Condition Report
006786, discolored oil found on outboard bearing of SBODiesel Generator during sampling*Condition Report
006879, while attempting to load SBO Diesel aftermaintenance, output voltage was approx 650V and expected to be 4250 -
4350V. Unable to adjust*Condition Report
006890, exceeded MRule unavailability hours for AAC systemdiesel generator*Condition Report
004545, 2-MS-FI-2484, "B" S/G CH III Steam Flow failed lowresulting in reactor trip*Condition Report
006047, NANN Card Failure for "B" MFRC caused valve to shutand U-1 to have RX trip*RCE000022, Reactor Trip Due to Failure of 02-MS-FM-2484A

Section 4OA2: Identification and Resolution of Problems*Plant Issue

N-2003-1449, U-2 reactor tripped after receiving "process rack powersupply failure" and "FW flow/STM flow mismatch" annunciator*Condition Report
CR003920, 2-EI-CB-58 multiple driver card failures
  • Condition Report
CR004545, 2-MS-FI-2484, "B" S/G CH III Steam Flow failedlow resulting in reactor trip*Work Orders
WO506895-01,
WO506893-01, WO506897-01

Section 4OA5: Other ActivitiesProcedures and Specifications*Dominion Procedure Number

0-WP-C05004, Revision 1, ISFSI Civil StructuresPad #2 Concrete Placement*Specification
NAI-0035, Revision 0, Installation Specification for ReinforcedConcrete ISFSI Facility Pad #2
A-3Attachment*Specification
NAI-0036, Revision 0, Specification for Excavation, Fill,Compaction, Testing, and Landscaping Dry Cask Independent Spent Fuel Storage InstallationOther Documents*Dominion Calculation
CE-1824, Revision 0, Design of ISFSI Pad #2*American Concrete Institute (ACI) Committee 306 Report 306.1-90, StandardSpecification for Cold Weather Concreting*ACI Committee 306 Report 306R-88, Cold Weather Concreting
  • Dominion Concrete Pre-Placement inspection Checklist for North Anna ISFSIPad #2 Project, dated January 29, 2007*Dominion Quality Inspection Logs (Inspection Reports)
  • Virginia Department of Transportation, Hydraulic Cement Plant InspectionReport, Dated April 4, 2006*Independent laboratory test reports by Froehling & Robertson, Inc.
  • Daily Field Observation Reports by Froehling & Roberton, Inc.
  • Drawing N-05004-0-1FC49A1, Rev. 2, Plans, Sections, & Details ISFSI (DryStorage) Facility #2, North Anna Power StationCondition Reports for NRC Identified Issues*CR006209, Response to NRC Inspector walkdown of protected equipmentregarding criteria and wording for protected eqpt signs*CR006789, SR 3.0.3 improperly applied for missed surveillance of AFW checkvalves*CR007215, Question raised by NRC inspector regarding EDG batterytemperature limits for battery operability*CR007349, NRC SR inspector questioned the classification of PI N-2005-1168as not being reportable under Part 21, related to CA005686*CR007831, 1J EDG inspection cover had 8 of 16 bolts either loose or only handtight, after notification by NRC inspector that one nut was loose*CR007890, NRC inspector identified a concern about the quality level of reviewbeing provided in SR/NSQ WOs that have work steps to perform activity in lieu of a procedure*CR008199, a small flash burn was noted during operation of 2-EE-EG-2H, EDGopposite control side engine exhaust system*CR008308, NRC raised concern about 2H EDG room components; doors notclosed or latched, conduit not snugged, oil seepage*CR008734, NRC inspector identified issue with flood wall inoperable coincidentwith Air Handler Room backflow preventer inoperable*CR008737, Resident Inspector questioned operability of backflow preventers forcharging pump cubicle *CR009157, NRC inspector raised questions regarding the analysis of failure inRCP thermal barrier and subsequent closing of the CC TVs*CR009208, NRC identified a programmatic concern in that the requirement totrack level 1 & 2 corrective action assignments to completion was not done for
RCE recommendation associated with PI N-2003-1449
A-4Attachment*CR009633, licensee employee entered U2 J diesel room without seeing postedsign which stated do not enter w/o operations permission, NRC resident advised me of the sign upon entering the room*CR009714, NRC resident questioned the difference in Run to Failure use inMRule and Equipment Reliability program
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