IR 05000334/2006005

IR 05000334-06-005 & 05000412-06-005; Firstenergy Nuclear Operating; 10/01/2006 - 12/31/2006; Beaver Valley Power Station, Units 1 & 2; Routine Integrated Report

ML070260053
Person / Time
Site:	Beaver Valley
Issue date:	01/24/2007
From:	Bellamy R NRC/RGN-I/DRP/PB7
To:	Lash J FirstEnergy Nuclear Operating Co
Bellamy R, Rgn-I/DRP/Br7/610-337-5200
References
IR-06-005
Download: ML070260053 (61)

Text

January 24, 2007Mr. James LashSite Vice President, Beaver Valley Power Station FirstEnergy Nuclear Operating Company Post Office Box 4 Shippingport, Pennsylvania 15077SUBJECT:BEAVER VALLEY POWER STATION - NRC INTEGRATED INSPECTIONREPORT 05000334/2006005 AND 05000412/2006005

Dear Mr. Lash:

On December 31, 2006, the United States Nuclear Regulatory Commission (NRC) completedan inspection at your Beaver Valley Power Station Units 1 and 2. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 18, 2007, with Mr. Peter Sena and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, no findings of significance were identified. However,licensee-identified violations which were determined to be of very low safety significance are listed in this report. NRC is treating these violations as non-cited violations (NCV) consistentwith Section VI.A.1 of the NRC Enforcement Policy because of the very low safety significance of the violations and because they are entered into your corrective action program. If you contest any of the findings 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 Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Beaver Valley.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and itsenclosures, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

J. Lash2We appreciate your cooperation. Please contact me at 610-337-5200 if you have anyquestions regarding this letter.

Sincerely,

/RA by Scott Barber Acting For/Ronald R. Bellamy, Ph.D., Chief Reactor Projects Branch 7 Division of Reactor ProjectsDocket Nos.:50-334, 50-412License Nos:DPR-66, NPF-73

Enclosures:

Inspection Report 05000334/2006005; 05000412/2006005w/Attachment: Supplemental Information

REGION IDocket Nos.50-334, 50-412License Nos.DPR-66, NPF-73 Report Nos.05000334/2006005 and 05000412/2006005 Licensee:FirstEnergy Nuclear Operating Company (FENOC)

Facility:Beaver Valley Power Station, Units 1 and 2 Location:Post Office Box 4Shippingport, PA 15077Dates: October 1, 2006 through December 31, 2006 Inspectors:P. Cataldo, Senior Resident InspectorD. Werkheiser, Resident Inspector T. Burns, Reactor Inspector A. DeFrancisco, Reactor Inspector J. Kulp, Reactor Inspector T. Moslak, Health Physicist A. Rosebrook, Project Engineer A. Ziedonis, Reactor InspectorApproved by:R. Bellamy, Ph.D., ChiefReactor Projects Branch 7 Division of Reactor Projects Enclosure iiTABLE of

SUMMARY OF FINDINGS

IR 05000334/2006005, IR 05000412/2006005; 10/01/2006 - 12/31/2006; Beaver Valley PowerStation, Units 1 & 2; Routine Integrated Report.The report covered a 3-month period of inspection by resident inspectors, regional reactorinspectors, and a regional health physics inspector. No findings of significance were identified.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3 dated July 2000.A.

NRC-Identified and Self-Revealing Findings

No findings of significance were identified.

B.Licensee-Identified Violations

Three violations of very low safety significance, which were identified by the licensee,have been 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 corrective actions are listed in Section 4OA7 of this report.

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near 100 percent power throughout the inspection period.

Unit 2 began the inspection period at 100 percent power. On October 2, the unit wastaken off-line for a planned refueling outage (Section 1R20). The unit was defueled on October 11 with all fuel assemblies transferred to the spent fuel pool. Fuel assemblies were reloaded into the reactor vessel on October 21. The unit returned on-line on November 12. On November 17, a loss of feedwater heating transient occurred, and the unit was down-powered to approximately 40 percent (Section 4OA3). Following feedwater heater tuning, the unit realized a 3 percent power uprate and returned to full-power on November 19 (Section 40A5). The unit continued to operate at or near full-power for the remainder of the inspection period.1.

REACTOR SAFETY

===Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection (71111.01 - 2 samples).1Seasonal Site Inspection (1 sample)

a. Inspection Scope

The inspectors reviewed the Beaver Valley Power Station (BVPS) design features andFENOC's implementation of procedures to protect risk significant mitigating systems===

from cold weather conditions and high winds. The inspectors walked down risk significant plant areas for several days in November and December 2006 and assessed FENOC's protection activities for cold weather conditions. The inspectors were sensitive to outside instrument line conditions and the potential for unheated ventilation.

The walkdown included the emergency diesel generator rooms, low head safety injection and service/river water systems. The inspectors also reviewed 1OST-45.11, "Cold Weather Protection Verification," Rev. 16 and 2OST-45.11, "Cold Weather Protection Verification," Rev. 17. Other documents that were reviewed are listed in the attachment.

b. Findings

No findings of significance were identified..2System Inspection (1 sample)

a. Inspection Scope

The inspectors reviewed the readiness of the Unit 2 emergency diesel generators forextreme weather conditions, specifically, cold temperatures, high winds, and other 2Enclosurerelevant severe weather events. The inspection verified that the indicated equipment, itsinstrumentation, and supporting structures were configured in accordance with FENOC's procedures and that adequate controls were in place to ensure functionality of the system. The inspectors reviewed licensee procedures and walked down the system.

Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04).1Partial System Walkdowns (71111.04 - 3 samples)

a. Inspection Scope

The inspectors performed partial equipment alignment inspections, during conditions ofincreased safety significance, including when redundant equipment was unavailable during maintenance or adverse conditions. The partial alignment inspections were also completed after equipment was recently returned to service after significant maintenance. The inspectors performed partial walkdowns of the following systems, including associated electrical distribution components and control room panels, to verifythe equipment was aligned to perform its intended safety functions:*Unit 2 'A' Service Water system on October 19, 2006;*Unit 1 'A' River Water System on October 24, 2006, following restoration from apump maintenance outage period; and *Unit 1 'B' Emergency Diesel Generator on December 20, 2006, while it was aprotected train.

b. Findings

No findings of significance were identified..2Complete System Walkdown (71111.04S - 1 sample)

a. Inspection Scope

The inspectors completed a detailed review of the alignment and condition of the Unit 2125VDC System. The inspectors conducted a walkdown of the system to verify that the critical portions, such as batteries, switches, breakers, and motor control centers (MCC)were correctly aligned in accordance with procedures, and to identify any discrepancies that may have had an effect on operability.The inspectors also conducted a review of outstanding maintenance work orders toverify that the deficiencies did not significantly affect the 125VDC system function. In addition, the inspectors reviewed the condition report database to verify that equipment 3Enclosurealignment problems were being identified and appropriately resolved. Documentsreviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05 - 7 samples)Quarterly Sample Review (71111.05Q)

a. Inspection Scope

The inspectors reviewed the conditions of the fire areas listed below, to verifycompliance with criteria delineated in Administrative Procedure 1/2-ADM-1900, "Fire Protection," Rev. 14. This review included FENOC's control of transient combustibles and ignition sources; material condition of fire protection equipment including fire detection systems, water-based fire suppression systems, gaseous fire suppression systems, manual firefighting equipment and capability, passive fire protection features, and the adequacy of compensatory measures for any fire protection impairments.

Documents reviewed are listed in the Attachment:* Unit 2 Primary Reactor Containment (Fire Area RC-1);*Unit 1 Turbine Building (Fire Zone TB-1);

• Unit 2 Turbine Building (Fire Area TB-1);

• Unit 2 West Cable Vault (Fire Area CV-1;)

• Unit 1 'A' Charging Pump Cubicle (Fire Area PA-1f);

• Unit 1 'B' Charging Pump Cubicle (Fire Area PA-1g); and

• Unit 1 'C' Charging Pump Cubicle (Fire Area PA-1h).

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06 - 1 samples)Internal Flooding Inspection

a. Inspection Scope

The inspectors reviewed flood protection measures for equipment in the Unit 2Containment during concurrent outage activities involving reactor coolant draindown and reactor vessel head bolt de-tensioning. This review was conducted to evaluate FENOC's protection of the enclosed safety-related systems from internal flooding conditions. The inspectors performed a walkdown of the area, reviewed the UFSAR, related internal flooding evaluations, and other related documents. The inspectors examined the as-found equipment and conditions to ensure that they remained 4Enclosureconsistent with those indicated in the design basis documentation, flooding mitigationdocuments, and risk analysis assumptions. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07 - 1 sample)

a. Inspection Scope

The inspectors reviewed a thermal performance test associated with the Unit 1 'A'charging pump lube oil cooler conducted December 15 - 21, 2006, in accordance with 1BVT-2.30.7, "Charging Pump Lube Oil Cooler [1CH-7A,B, or C] Heat Exchanger Thermal Performance Testing," Rev. 0. The review included an assessment of the testing methodology and verified consistency with Electric Power Research Institute document NP-7552, "Heat Exchanger Performance Monitoring Guidelines," December 1991, and Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment." The inspectors reviewed inspection results, related condition reports and lube oil cooler leak test results against applicable acceptance criteria.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection (71111.08P - 4 samples)

a. Inspection Scope

The inspector assessed the inservice inspection (ISI) activities using the criteriaspecified in the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI. The inspector reviewed documentation and interviewed personnel to verify that the activities were performed in accordance with the ASME requirements. The sample selection was based on the inspection procedure objectives and risk priority of those components and systems where degradation would result in a significant increase in risk of core damage. Because Temporary Instruction 2515/150, Reactor Pressure Vessel Head and VesselHead Penetration Nozzles (NRC Order EA-03-009), had been previously completed at Beaver Valley Unit 2, the inspector incorporated the upper head penetration examinations as samples for ISI activities.Temporary Instruction 2515/152, Reactor Pressure Vessel Lower Head PenetrationNozzles (NRC Bulletin 2003-02), had also been previously completed during U2's past 5Enclosureoutage. During the current outage, FENOC performed under head visual examinationson the bottom mounted penetrations and did not observe boric acid leakage. Also, during this outage, FENOC mitigated the pressurizer nozzle welds to preventprimary water stress-corrosion cracking (PWSCC) throughwall cracking in the reactor coolant system (RCS) pressure boundary. Mitigation activities included automatic weld overlays on the surge, spray, safety and relief valve nozzles.The inspector interviewed staff and reviewed evaluations for defects found duringnon-destructive examinations (NDE) that were to be left in service. The inspector also reviewed plans for repair of indications not to be left in service. Specifically, the inspector reviewed the pressurizer surge line nozzle weld overlay flaw indication evaluation containing both acceptable and unacceptable flaws and compared the recommendations to the ASME Section XI criteria. For the flaws discovered in the reactor head penetrations, the inspector observed that FENOC performed confirmatory liquid penetrant (LP) examinations to check for surface-breaking flaws and reviewed the LP examination results reports (BOP-PT-06-023/024/025). The inspector also verified that no boric acid leakage had been observed on the upper surface of the reactor head near the specific penetrations of concern. These specific activities were directly observed by the inspector:

• Manual ultrasonic examinations of the pressurizer surge nozzle weld overlay;*Automatic welding of the pressurizer safety/relief valve nozzles ; and

• Recordings of the visual examination standard for the upper head base metalvisuals and the visual examinations for the base metal surrounding the three penetrations containing flaws (found during ultrasonic testing).The inspector interviewed the boric acid corrosion control program owner and sampled the photographic database of all examined areas to verify that visual inspections emphasized locations where boric acid leaks can cause degradation of safety significant components. The inspector also reviewed a sample of items on the mode hold list, as well as the procedures being used for visual inspection for evidence of boric acidleakage. The inspector confirmed that sampled condition reports were assigned corrective actions consistent with the requirements of the ASME Code and 10 CFR 50, Appendix B, Criterion XVI. Specifically, the inspector reviewed the following evaluations:*CR 06-7743/2RHS-E21B 'B' Residual Heat Removal Heat Exchanger;*CR 06-7109/2RCS SG21B Steam Generator Blowdown Isolation; and

• CR 06-8271/2RCS-44 Loop A Bypass Flow Isolation.The inspector reviewed nondestructive examinations NDE certifications for inspectorsperforming the above listed examinations, as well as ASME Welder Maintenance Logs for the contracted staff used to perform the overlay weld activities on the pressurizer and the upper reactor head penetration J-groove weld repairs.

6EnclosureIn addition, the following steam generator tube inspection activities were discussed withonsite personnel:*Selection of the examination scope;*Comparison of the size, number and locations of detected flaws from the currentoutage to the predictions in the operational assessment;*Probe and equipment qualification; and

• Foreign object search and retrieval (FOSAR)/secondary side inspections.The inspector confirmed that FENOC performed steam generator testing activities anddocumented the results in accordance with Electric Power Research Institute (EPRI)guidelines and site procedures. The inspector also reviewed a sample of condition reports to assess FENOC'seffectiveness in problem identification and resolution and determined that they are identifying ISI problems at an appropriate threshold and entering them into the corrective action program. The inspector noted the effective use of industry operating experience during the reactor head upper penetration eddy current examinations, as well as the pressurizer heater coupling visual examinations.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)Resident Inspector Quarterly Review (71111.11Q - 2 samples)

a. Inspection Scope

The inspectors reviewed one sample of a Unit 1 & 2 lesson plan for licensed-operatorrequalification training, which involved Improved Technical Specification (ITS)implementation and interpretation (BV1/2 ITS Draft, Rev. 5). The inspectors also observed Unit 2 licensed-operator annual requalification examinations conducted on the plant-reference simulator on November 30, 2006. The inspectors evaluated licensed operator performance regarding command and control, implementation of normal, annunciator response, abnormal, and emergency operating procedures, communications, technical specification review and compliance, and emergency plan implementation. The inspectors evaluated the licensee staff training personnel to verify that deficiencies in operator performance were identified, and that conditions adverse to quality were entered into the corrective action program for resolution. The inspectors reviewed simulator physical fidelity to verify that the simulator appropriately modeled the plant control room. The inspectors verified that the training evaluators adequately addressed that the applicable training objectives had been achieved. Documents reviewed during the inspection are listed in the Attachment.

b. Findings

7EnclosureNo findings of significance were identified.

1R12 Maintenance Rule Implementation (71111.12)Routine Maintenance Effectiveness Inspection (71111.12Q - 2 samples)

a. Inspection Scope

The inspectors evaluated Maintenance Rule (MR) implementation for the issues listedbelow. The inspectors evaluated specific attributes, such as MR scoping, characterization of failed structures, systems, and components (SSCs), MR risk characterization of SSCs, SSC performance criteria and goals, and appropriateness of corrective actions. The inspectors verified that the issues were addressed as required by 10 CFR 50.65 and the licensee's program for MR implementation. For the selected SSCs, the inspectors evaluated whether performance was properly dispositioned for MR category (a)(1) and (a)(2) performance monitoring. MR System Basis Documents were also reviewed, as appropriate. Documents reviewed are listed in the Attachment.*CR 06-06303, "Extent of Condition of CR 06-04920, Motor Pinion Key Failure2HVC-MOD201D"*CR 06-05068, "Broken Tubing Found During Work On TCV-1MS-106B3"

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessment and Emergent Work Control (71111.13 - 6 samples)

a. Inspection Scope

The inspectors reviewed the scheduling and control of six activities, and evaluatedthe effect on overall plant risk. This review was conducted to ensure compliance with applicable criteria contained in 10 CFR 50.65(a)(4). Documents reviewed during the inspection are listed in the Attachment. The inspectors reviewed the planned or emergent work for the following activities:*Unit 2 unplanned risk on October 1, 2006, following the identification ofscaffolding interference associated with Unit 2 Main Steam Isolation Valves.

(Sections 1R15, 4OA7). *Unit 2 planned shutdown "yellow" risk during reactor vessel head boltde-tensioning and concurrent reactor coolant system draindown on October 6 and 7, 2006.*Unit 2 planned "yellow" risk October 16-19, 2006 to perform planned2R12-related maintenance activities on the 'A' train Emergency Bus, (AE Bus).

8EnclosureInspectors reviewed the performance and adequacy of the shutdown riskassessment, including the management of resultant risk, implementation of work controls and preservation of decay heat removal.*Unit 1 planned "yellow" risk during solid state protection system (SSPS) cardchange-outs while performing system surveillance testing on November 16, 2006.*Unit 2 risk and duration due to #10 cylinder fuel injector failure and repair for the#1 emergency diesel generator on November 22, 2006.*Unit 2 risk on November 30 through December 1, 2006 during 'A' quench sprayflow indicating switch calibration.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15 - 6 samples)

a. Inspection Scope

The inspectors evaluated the technical adequacy of selected operability determinations(OD), Basis for Continued Operations (BCO), or operability assessments, to verify that determinations of operability were justified, as appropriate. In addition, the inspectors verified that TS limiting conditions for operation (LCO) requirements and UFSAR design basis requirements were properly addressed. Documents reviewed are listed in the

. This inspection activity represents six samples of the following issues:*The inspectors reviewed the OD documented in CR 06-06553, associated withthe licensing basis for Unit 2 steam generator overfill during a steam generator tube rupture event. The inspectors focused on the operability aspects of the main steam piping due to the potential for steam generator overfill and the effects of the introduction of water in the main steam piping, and potential bypass of containment. The inspectors reviewed licensee calculations to verify their conclusions that the stresses caused by the introduction of water into sections of main steam piping were bounded by the existing capability of the system supports and associated stress calculations. The inspectors also reviewed the associated 50.59 evaluation.*The inspectors reviewed the operability aspects associated with erectedscaffolding that potentially interfered with the operation of Unit 2 main steam isolation valves (MSIVs), as detailed in CR 06-7046. The inspectors noted that upon discovery, the MSIVs ("A" and "B") were declared inoperable, TS 3.0.3 was entered, the impeding portions of the scaffolding were removed, and the MSIVs declared operable upon exiting the applicable TS. The inspectors reviewed the licensee's reportability determinations, as well as engineering assessments that 9Enclosureconcluded only one MSIV would have potentially been prevented from fullyclosing upon demand. Performance issues associated with this event, but separate from the operability aspects reviewed under this section were determined to be a licensee-identified finding, therefore, the enforcement aspects of this finding is described in section 40A7.*The inspectors reviewed the operability aspects documented in CR 06-7130,associated with a Unit 1 broken conduit connector for 1VS-F-4A, Supplementary Leak Collection and Release System (SLCRS) fan.*The inspectors reviewed the OD documented in CRs 06-7444/7644/9399,associated with Unit 1 and Unit 2 motor-operated valve (MOV) motor pinion key failures. The inspectors assessed the adequacy and acceptability of FENOC's conclusion that other selected MOVs were operable. The inspector reviewed system configurations of affected MOV's for system interfacing conflicts. *The inspectors reviewed the operability aspects of a 10 CFR 21 (Part 21) issuedocumented in CR 06-7917, associated with a manufacturing problem with Areva-supplied, ASCO hrydromotor actuator pumps and pump kits. This affects one Unit 2 control room damper and one Unit 2 EDG damper. The affected dampers were declared inoperable and system interfacing operability conflicts with Unit 1 were assessed. However, a temporary modification (TMOD) was performed to hold the EDG damper open to support swapping electrical trains.

The inspectors assessed the adequacy and acceptability of the TMOD to support and maintain EDG operability (section 1R23).*The inspectors reviewed the operability aspects and extent of conditionassociated with Unit 2 #2-1 emergency diesel generator (EDG) #10 fuel injector failure discovered during the performance of the monthly surveillance run, 2OST-36.1. The 2-1 EDG fuel injectors had been replaced during the recent

2R12 outage.

The failure and preliminary analysis is documented in CR 06-10449 and CR 06-10398.

b. Findings

No findings of significance were identified.

10Enclosure1R17 Permanent Plant Modifications (71111.17).1Annual Review (71111.17A - 1 sample)

a. Inspection Scope

The inspectors evaluated the design basis impact of the modifications listed below. This modification was also needed to support the Unit 2 power uprate. The inspectors reviewed the adequacy of the associated 10 CFR 50.59 screening, verified that attributes and parameters within the design documentation were consistent with required licensing and design bases, as well as credited codes and standards, and walked down the systems to verify that changes described in the package were appropriately implemented. The inspectors also verified the post-modification testing was satisfactorily accomplished to ensure the system and components operated consistent with their intended safety function. Documents reviewed are listed in the

.*Unit 2 ECP-03-0213, 'A' High Head Safety Injection (HHSI) Pump RotatingAssembly

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19

- 5 samples)

a. Inspection Scope

The inspectors reviewed the following activities to determine whether the post-maintenance tests (PMT) adequately demonstrated that the safety-related function of the equipment was satisfied given the scope of the work specified, and that operability of the system was restored. In addition, the inspectors evaluated the applicable acceptance criteria to verify consistency with the associated design and licensing bases, as well as TS requirements. The inspectors also verified that conditions adverse to quality were entered into the corrective action program for resolution. Documents reviewed during the inspection are listed in the Attachment. The following five maintenance activities and associated PMTs were evaluated:*2OST-36.1, "Emergency Diesel Generator [2EGS*EG2-1] Monthly Test" Rev. 48,performed on October 22 following troubleshooting and repairs on emergency diesel generator #2-1 air start distributor and voltage regulator.

• WO 200151306 retest completed on October 18, following repairs to correcthigh friction (slow closure times) for the Unit 2 'C' main steam isolation valve (2MSS-AOV101C).

11Enclosure*2MSP-9.4M, "Containment Sump (2DAS-Tk204) Inspection" Rev. 6, performedon November 9 after installation of a new containment sump during 2R12.*WO 200239958 post-weld inspections on November 13 after repairs associatedwith 2RCS-272 during outage 2R12.*WO 200241542 post-installation checks and testing instructions followingreplacement of #10 fuel injector for the Unit 2 #1 emergency diesel generator on November 22 and 23.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities (71111.20 - 1 sample).1Unit 2 Refueling Outage (2R12)

a. Inspection Scope

The inspectors observed selected Unit 2 outage activities to determine whethershutdown safety functions (e.g. reactor decay heat removal, spent fool pool cooling, and containment integrity) were properly maintained as required by TS and plant procedures. The inspectors evaluated specific performance attributes including operator performance, communications, and instrumentation accuracy. The inspectors reviewed procedures and/or observed selected activities associated with the Unit 2 refueling outage. The inspectors verified activities were performed in accordance with procedures and verified required acceptance criteria were met. The inspectors also verified that conditions adverse to quality identified during performance of selected outage activities were identified as required by the licensee's corrective action program.

Documents reviewed are listed in the Attachment. The inspectors also evaluated the following activities:*Pre-Outage Shutdown Safety Review;*Reactor plant shutdown and cooldown, including evaluation of cooldown rates;

• Initial mode 4, as-found boric acid walkdown inside containment;

• Containment closure contingencies and procedures;

• Reactor coolant system draindown to support refueling operations;

• Refueling operations;

• Spent fuel pool cooling operations;

• Maintenance of decay heat removal flowpaths;

• Coordination of electrical bus work and minimization of shutdown risk;

• High head safety injection full flow test;

• Containment sump installation and inspection;

• Pressurizer weld overlay operations;

• Reactor vessel head inspection and penetration repair;

• Final containment walkdown and closeout inspection; 12Enclosure*Control rod testing;*Initial criticality;

• Reactor startup;

• Low power reactor physics testing;

• Plant startup and heatup, including evaluation of heatup rates; and

• Reviewed the digital video documenting the core reload and verified the fuelassembly placement was consistent with the reload map.The inspectors also observed selected management review activities associated withrestart readiness of Unit 2, following completion of the 2R12 refueling activities. The restart readiness review meeting was accomplished as required by NOBP-OM-4010, "Restart Readiness for Plant Outages" Rev. 4 on November 8, 2006. The purpose of the review, in part, was to assure to station management that the plant's material condition, programs/processes, and staff members are ready for startup and safe, reliable operation after completion of outage activities.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22 - 6 samples)

a. Inspection Scope

The inspectors observed pre-job test briefings, observed selected test evolutions, andreviewed the following completed Operation Surveillance Test (OST) and Maintenance Surveillance (MSP) packages. The reviews verified that the equipment or systems were being tested as required by TS, the UFSAR, and procedural requirements. Documents reviewed are listed in the Attachment. The following six activities were reviewed:*1BVT-1.21.2, "Trevitest Method For Main Steam Safety Valve Setpoint Check,"Rev. 12, for SV-1MS-103C during 1POAC2, on August 24, 2006;*2BVT1.1.1, "Rod Drop Time Measurement and RPI Verification", Rev. 11;

• 2BVT1.3.1, "Narrow Range RTD Cross Calibration", Rev. 5;

• 2BVT1.47.5, "Type 'C' Leak Test", Rev. 10 for Unit 2 containment isolation valve2CVS-93;*2OST-6.2A, "Computer Generated Reactor Coolant System Water InventoryBalance", Rev.25; and*2OST-11.14B, "HHSI Full Flow Test," Rev. 22.

b. Findings

No findings of significance were identified.

13Enclosure1R23Temporary Plant Modifications (71111.23 - 2 samples)

a. Inspection Scope

The inspectors reviewed the following temporary modifications (TM) based on risksignificance. The TM and associated 10CFR50.59 screening were reviewed against the system design basis documentation, including the UFSAR and the TS. The inspectors verified the TMs were implemented in accordance with Administrative (ADM) Procedure, 1/2-ADM-2028, "Temporary Modifications," Rev. 6. Documents reviewed are listed inthe Attachment.*TMOD 2-06-06, associated with ventilation exhaust damper 2HVD-MOD21A forthe Unit 2 #1 Emergency Diesel Generator (EDG). Inspectors walked down the system to verify that the TMOD described was appropriately implemented, the safety function of the damper would be maintained, and the EDG operability would not be challenged.*TMOD 2-08-06, associated with the Unit 2 containment sump narrow range levelsensor. One element of the sensor string had failed and was subsequently jumpered out. For this activity, the inspectors walked down the area to verify actual system configuration and reviewed modifications to the sensor. The inspector verified that post-modification testing was satisfactorily accomplished.

b. Findings

No findings of significance were identified.

===Cornerstone: Emergency Preparedness [EP]1EP6Drill Evaluation (71114.06 - 1 sample)

a. Inspection Scope

The inspectors observed a Unit 2 licensed-operator annual simulator evaluationconducted on November 30, 2006. Senior licensed-operator performance regarding===

event classifications were specifically evaluated. The inspector evaluated the simulator-based scenario that involved multiple equipment failures, and plant conditions that would have warranted emergency plan activation, emergency facility activation, and escalation to the event classification of Alert. The licensee planned to credit this evolution toward Emergency Preparedness Drill/Exercise Performance (DEP) Indicators, therefore, the inspectors reviewed the applicable event notifications to determine whether they were appropriately credited, and properly evaluated consistent with Nuclear Energy Institute (NEI) 99-02, Rev. 4, "Regulatory Assessment Performance Indicator Guideline." The inspectors reviewed licensee evaluator worksheets regarding the performance indicator acceptability, and reviewed other crew and operator evaluations to ensure adverse conditions were appropriately entered into the Corrective Action Program. Other documents utilized in this inspection include the following:

14Enclosure*1/2-ADM-1111, "NRC EPP Performance Indicator Instructions," Rev. 2;*EPP/I-1B, "Recognition and Classification of Emergency Conditions," Rev. 10;

• 1/2-EPP-I-3, "Alert," Rev. 22;

• 1/2-EPP-I-4, "Site Area Emergency," Rev. 22; and

• 1/2-ADM-1111.F01, Rev. 0, "Emergency Preparedness Performance IndicatorsClassifications/Notifications/Pars.

b. Findings

No findings of significance were identified.2.RADIATION SAFETYCornerstone: Occupational Radiation Safety2OS1Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

(9 Samples)During the period October 2 - 6, 2006, the inspector conducted the following activities toverify that the licensee was properly implementing physical, administrative, and engineering controls for access to locked high radiation areas, and other radiologically controlled areas during the Unit 2 refueling outage. Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, relevant TSs, and the licensee's procedures. Plant Walkdown and RWP Reviews*During the Unit 2 refueling outage, the inspector identified exposure significantwork activities being conducted in the Reactor Building. Specific work activities included removal of insulation and installation of temporary shielding on the reactor vessel head and pressurizer components, i.e. spray line, relief valves, and piping, in preparation for conducting metallurgical inspections and performing weld overlays. Other in-containment activities included scaffolding installation, equipment mobilization, and support activities for modifying the containment sump. The inspector reviewed radiation survey maps and radiation work permits (RWP) associated with these activities to determine if the radiological controls were acceptable. *The inspector toured accessible radiological controlled areas in the Unit 2containment and with the assistance of a radiation protection supervisor, the inspector performed independent surveys of selected areas to confirm the accuracy of survey maps and the adequacy of postings. *In evaluating RWPs, the inspector reviewed electronic dosimeter dose/dose ratealarm setpoints to determine if the setpoints were consistent with the survey 15Enclosureindications and plant policy. The inspector verified that the workers wereknowledgeable of the actions to be taken when the dosimeter alarms or malfunctions for tasks being conducted under selected RWPs. Work reviewed included RWP 206-5048, Pressurizer Weld Overlay (Tasks 1 & 2), RWP 206-5026, reactor vessel external head inspection (Task 1), and RWP 206-5027, reactor vessel under head inspection (Task 1).*The inspector reviewed selected RWPs and ALARA plans, associated airbornemonitoring instrumentation, and engineering controls (e.g., portable ventilation systems) for potential airborne radioactivity areas and contaminated areas in the Unit 2 reactor building to determine if the controls were adequate. Additionally, the inspector reviewed Personnel Contamination Event (PCE) reports for outage and non-outage tasks, potentially resulting in internal exposures, and confirmed that no worker received an internal dose in excess of 50 mrem, for work activities performed at Unit 1 or Unit 2 for 2006 to date. Problem Identification and Resolution*The inspector reviewed elements of the licensee's corrective action programrelated to controlling access to radiological controlled areas, since the last inspection of this area, to determine if problems were being entered into the program for resolution. Details of this review are contained in Section

4OA2 of

this report.Jobs-In-Progress*The inspector observed aspects of various ongoing activities to confirm thatradiological controls, such as required surveys, area postings, job coverage, and pre-job RWP briefings were conducted; personnel dosimetry was properly worn; and that workers were knowledgeable of work area radiological conditions. The inspector attended various pre-job RWP briefings including pressurizer insulation removal, pressurizer temporary shielding installation, reactor head insulation removal, and reactor vessel under-head inspection preparations. High Risk Significant-LHRA and VHRA Controls*Keys to locked high radiation areas (LHRA) and very high radiation areas(VHRA) for Unit 2 were inventoried, and accessible LHRAs and VHRAs in the reactor building were verified to be properly posted and secured during Unit 2 plant tours.*The inspector discussed with radiation protection supervision the adequacy ofphysical and administrative controls for performing work in high radiation areas, including spent fuel transfers and in-core detector movement. The inspector verified that any changes to relevant procedures did not substantially reduce the effectiveness and level of worker protection and evaluated the adequacy of pre-requisite communications and authorizations.

16EnclosureRadiation Worker Performance*The inspector observed radiation worker and radiation protection technicianperformance during containment equipment mobilization and preparations made for performing pressurizer weld overlay tasks. The inspector determined that the individuals were aware of current radiological conditions, access controls, andthat the skill level of the workers was sufficient with respect to the potential radiological hazards and the task performed. The inspector reviewed condition reports related to radiation worker and radiation protection technician errors, and personnel contamination event reports to determine if an observable pattern traceable to a common cause was evident.

b. Findings

No findings of significance were identified. 2OS2ALARA Planning and Controls (71121.02)

a. Inspection Scope

(5 Samples)During the period October 2 - 6, 2006, the inspector conducted the following activitiesto verify that the licensee was properly implementing operational, engineering, and administrative controls to maintain personnel exposure as low as is reasonablyachievable (ALARA) for tasks conducted during the Unit 2 refueling outage.

Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and the licensee's procedures. The Problem Identification and Resolution (PI&R) sample referenced below is redundant with the PI&R sample contained in paragraph 2OS1 and is not included in the sample count.Radiological Work PlanningThe inspector reviewed pertinent information regarding site cumulative exposure history,current exposure trends for 2006, and the dose estimates for the Unit 2 refueling outage to assess current ALARA performance and outage exposure challenges. The inspector determined that the site's 3-year rolling average collective exposure placed the site in the third quartile ranking for U. S. pressurized water reactor power plants. The inspector reviewed the ALARA Plans to limit exposure for dose intensive tasksscheduled during the Unit 2 outage, including pressurizer weld overlays, reactor building sump modification, scaffolding installation/removal, steam generator eddy current inspection support, and reactor disassembly/reassembly.The inspector reviewed the 2R12 refueling outage daily dose summary reports, detailingworker estimated and actual exposures, through October 5, 2006, for outage-related tasks.

17EnclosureThe inspector evaluated the effectiveness of exposure mitigation requirements specifiedin RWPs and ALARA Plans, by comparing actual, collective dose received with estimated dose for top-of-pressurizer and surge line weld overlay preparations. The inspector reviewed, in detail, the effectiveness of temporary shielding installations for pressurizer tasks by comparing before and after dose rates for shielding packages06-063 through 06-071. The inspector evaluated the departmental interfaces between radiation protection,engineering, operations, maintenance crafts, and contractors to identify missing ALARA program elements and interface communications issues. The evaluation was accomplished by attending a site ALARA committee meeting on 10/05/2006; interviewing the Manager Radiation Protection, the Manager - Pressurizer Weld Overlay Project, the Supervisor - Fleet Performance Monitoring; reviewing recent ALARA committee meeting minutes; and reviewing a Nuclear Quality Assessment field observation report. The inspector determined if work activity planning included the placement of activatedcomponents away from occupied work areas, system flushes to reduce piping source terms, and operational considerations, e.g., filling the steam generators and pressurizer during dose intensive tasks, to further limit dose. The inspector reviewed personnel contamination event (PCE) reports for selectedpersonnel who became contaminated while performing outage-related tasks, and evaluated the effectiveness of the licensee's methods for controlling loose surface contamination and airborne radioactivity.Verification of Dose Estimates and Exposure Tracking SystemsThe inspector reviewed the basis for the annual site, collective exposure estimate for2006, the actual, collective exposure received to date during normal plant operation and during the recent Unit 1 outage and the Unit 2 outage dose projection. The inspector reviewed the licensee's methods for re-evaluating exposure estimatesand re-planning work when emergent work or expanded job scope was encountered.

The inspector attended an ALARA committee meeting held to re-evaluate projected outage dose, based on the most current survey data, following completion of the reactor coolant system clean-up; reviewed recent actions of the committee in monitoring and controlling dose allocations; and interviewed site staff regarding actions to be taken when actual dose approached estimated dose. The inspector reviewed the licensee's exposure tracking system (HIS-20) to determinewhether the level of detail, exposure report timeliness and dissemination was sufficient to support the control of collective exposures. Included in this evaluation were departmental dose compilations, specific RWP dose summaries, and individual exposure records. Job Site Inspection and ALARA Control 18EnclosureThe inspector observed activities being performed in support of various outage projects,including installation of temporary shielding on pressurizer components/piping, cutting of containment sump grating, reactor head insulation removal, and scaffolding construction in containment. The inspector attended pre-job ALARA briefings for selected tasks, verified that job coverage and contamination controls were implemented, and that personnel properly wore dosimetry and were knowledgeable of work area radiological conditions. Source Term Reduction and ControlThe inspector reviewed the status and historical trends for the Unit 2 source term. Through review of recent survey maps and interviews with the Manager Radiation Protection, the inspector evaluated recent source term measurements and control strategies. Specific strategies being employed at Unit 2 included shutdown chemistry controls, system flushes, use of macro-porous resin, and temporary shielding. Declared Pregnant WorkersThe inspector reviewed the procedural controls for managing declared pregnant workers(DPW) and the exposure records associated with a current DPW to determine if the required administrative controls were being implemented. Problem Identification and ResolutionThe inspector reviewed elements of the licensee's corrective action program related toimplementing the ALARA program to determine if problems were being entered into the program for timely resolution. Condition reports related to dose/dose rate alarms, programmatic dose challenges, and effectiveness in predicting and controlling worker dose were reviewed. Details of this review are contained in Section

4OA2 of this report.

b. Findings

No findings of significance were identified.

19Enclosure2OS3Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

a. Inspection Scope

(9 Samples)During the period December 11 - 14, 2006, the inspector conducted the followingactivities to evaluate the operability and accuracy of radiation monitoring instrumentation and the adequacy of the respiratory protection program for issuing self-contained breathing apparatus (SCBA) to emergency response personnel. Implementation of these programs was reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and the licensee's procedures. *The inspector reviewed the operating procedures and current sourceactivities/dose rate characterizations for the two

(2) Shepherd Model 89-400 calibrators (Nos. 9139 and 9109) and the Shepherd Model 81 panoramic calibrator. The inspector reviewed the calibration records for the RadCal Electrometer 2026C and associated ion chambers used in calibrating the Shepherd calibrators. *The inspector reviewed the calibration records for selected survey meters,dosimeters, and contamination monitors including portable neutron survey instruments (PNR-4), small article monitors (SAM-11), portal contamination monitors (SPM-906), portable ion chambers (RO-2 & RO-20), electronic dosimeters(DMC-2000), hand-held contamination friskers (RM-14), and whole body counting systems (FastScan and AccuScan II).*The inspector observed a technician performing a calibration of a portable ionchamber (RO-2, Serial No. 6266) and confirmed that procedural requirements were met. The inspector also observed a technician perform daily functional checks on personnel contamination monitors located at the control point (SPM-906, Serial Nos. 030, 104, 026).*The inspector reviewed current calibration data for selected area monitorslocated in the Unit 1 decontamination building (RM-RM-205), Unit 1 auxiliary building (RM-RM-209), Unit 1 sample room (RM-RM-212), Unit 1 drum handling area (RM-RM-208), and various Unit 2 auxiliary building monitors (2RMP-DAU-206/207/208).*The inspector reviewed Part 61 contamination sampling results for Unit 1 andUnit 2 to determine if the calibration sources were representative of the radioisotopes found in the plant source term. Whole body counting system records were reviewed to determine if Part 61 data was addressed to ensure that hard-to-detect radioisotopes were given proper dosimetric consideration.*The inspector reviewed electronic dose and dose rate alarm reports for 2006, todate, and compared actual dose/dose rates to programmed set points to determine if the dosimeter appropriately responded to the radiation field experienced.

20EnclosureRespiratory Protection ProgramThe inspector evaluated the adequacy of the respiratory protection program regardingthe maintenance and issuance of self-contained breathing apparatus (SCBA) to emergency response personnel. *Training and qualification records were reviewed for all control room operatorsfrom the operating shifts at each unit and for selected radiation protection technicians who would wear SCBAs in the event of an emergency. *The inspector, with the assistance of a respiratory protection technician,functionally tested and inspected six

(6) SCBAs, staged for use in the Unit 2 auxiliary fire brigade room. *The inspector verified that the appropriate number of SCBAs were staged, andhad been inspected weekly, in various plant areas, including the Unit 1 fire brigade room; controlled area hallway; water treatment building; and radiation technician shift area, and the Unit 2 fire van; controlled building equipment room; and pump house. The inspector confirmed that eyeglass inserts for licensed operators were readily available for use in the control room. Maintenance and test records were reviewed for selected SCBAs. The sample results forbreathing air, used to refill the SCBA tanks, were reviewed to confirm that air quality met CGA-G-7.1-1997 Grade D standards.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

[OA]4OA1Performance Indicator (PI) Verification (71151 - 4 samples)

a. Inspection Scope

Cornerstone: Mitigating Systems (2 samples)The inspectors sampled FENOC submittals for the one PI listed below for Unit 1 andUnit 2. The inspectors reviewed data from fourth quarter 2004 through the third quarter 2006. To verify the accuracy of the PI data reported during these periods, PI definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Indicator Guideline," Revision 4, were used to verify the reporting basis for each data element.*Safety System Functional Failure The inspectors reviewed portions of the operations logs and raw PI data developed frommonthly operating reports and discussed the methods for compiling and reporting the 21EnclosurePIs with cognizant licensing and engineering personnel. The inspectors comparedgraphical representations from the most recent PI report to the raw data to verify that the data was correctly reflected in the report. Documents reviewed during this inspection are listed in the Attachment.Cornerstone: Occupational Exposure Radiation Safety (1 sample)*Occupational Exposure Control Effectiveness The inspector reviewed implementation of the licensee's Occupational Exposure ControlEffectiveness Performance Indicator (PI) Program. Specifically, the inspector reviewed condition reports, and associated documents, for occurrences involving locked high radiation areas, very high radiation areas, and unplanned exposures against the criteria specified in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 4, to verify that all occurrences that met the NEI criteria were identified and reported as performance indicators. This review covered the period from October 1, 2005 through September 30, 2006. Cornerstone: Public Radiation Safety (1 sample)*RETS/ODCM Radiological Effluent Occurrences The inspector reviewed relevant effluent release reports for the period October 1, 2005through September 30, 2006, for issues related to the public radiation safety performance indicator. This indicator measures radiological effluent releaseoccurrences that exceed 1.5 mrem/qtr whole body or 5.0 mrem/qtr organ dose for liquid effluents; 5 mrads/qtr gamma air dose, 10 mrad/qtr beta air dose, and 7.5 mrads/qtr for organ dose for gaseous effluents. The inspector reviewed the following documents to ensure the licensee met allrequirements of the performance indicator:*monthly projected dose assessment results due to radioactive liquid andgaseous effluent releases;*quarterly projected dose assessment results due to radioactive liquid andgaseous effluent releases; and*dose assessment procedures.

b. Findings

No findings of significance were identified.4OA2Problem Identification and Resolution (PI&R) (71152 - 3 samples).1 Daily Review of Problem Identification and Resolution aInspection Scope 22EnclosureAs 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 followup, the inspectors performed a daily screening of items entered into FENOC's corrective action program. This review was accomplished by reviewing summary lists of each condition report (CR), attending screening meetings, and accessing FENOC's computerized CR database.

b. Findings

No findings of significance were identified..2Semi-Annual Trend Review (1 sample)

a. Inspection Scope

The inspectors reviewed site trending results for January through June, 2006, todetermine if trending was appropriately performed and evaluated by FENOC. This review covered the site trending program under FENOCs Integrated Performance Assessment process, and included a sample of self-assessments from the several organizations at Beaver Valley. This review verifies that existing trends were (1)appropriately captured and scoped by applicable departments,

(2) consistent with the inspectors' assessment from the daily CR and inspection module reviews (Section 40A2.1,

===.4 through .6), and

(3) not indicative of a more significant safety concern.===

Additionally, the inspectors verified the performance of site trending against NOP-LP-2001, Rev. 13, "Condition Report Process," and NOBP-LP-2018, Rev. 01, "Integrated Performance Assessment /Trending." The inspectors also reviewed quarterly Quality Assurance reports and issues captured in the Activity Tracking database to identify issues and trends to evaluate during the inspection.

b. Findings

No findings of significance were identified. However, an adverse trend that involvedscaffolding program implementation was evident from previous integrated performance assessments (IPA) as well as a review of CRs over the course of the assessment period and beyond (See IPA BV-SA-06-005, and CR05-08203). Plant processes such as IPAs, the corrective action program, management review of CRs (daily, following management meeting), internal and external Operating Experience, are all available and could have been used to identify this trend involving the implementation of the scaffolding program.

The inspector did note, however, that during the current inspection report period, a fleet-wide self-assessment was performed to evaluate the health of the site scaffolding program, and the benefits of this assessment, e.g., evaluation of corrective actions, were not part of this trend review..3Annual Sample Review (2 samples)Repetitive Leaks in Fire Water, River Water, and Service Water System Piping

a. Inspection Scope

The inspectors reviewed FENOC's actions in response to repetitive minor leaks in threesystems: the Fire Protection system, Unit 1 safety-related River Water system, and Unit 2 safety-related Service Water system. These three water systems are all supplied directly by the Ohio River, and have experienced repetitive minor leaks due to microbiologically influenced corrosion (MIC). The inspectors reviewed FENOC's identification of these problems; the related evaluations and operability determinations; the extent-of-condition review; the corrective actions specified; and their prioritization.

The inspectors walked down accessible portions of the systems and interviewed applicable system engineers.

b. Findings

No findings of significance were identified. However, while FENOC has identified andcharacterized the MIC problem, has taken steps to reduce the rate of MIC, and uses samples to monitor the corrosion rate, the problem itself remains for large bore piping.

(Small bore piping has been replaced using material highly resistant to MIC.) The consequences identified in this inspection have not resulted in loss of system safety functions. Review of The Operator Workaround Program

a. Inspection Scope

The inspectors reviewed the cumulative effects of the existing operator work-arounds,the list of operator burdens, existing operator aids and disabled alarms, and the list of open main control room deficiencies. This review was performed to identify any effect on emergency operating procedure operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel were identifying, assessing, and reviewing OWAs as specified in administrative procedure BVBP-OPS-0002, "Operator Work-Arounds, Operator Burdens, and Control Room Deficiencies" Rev. 11.The inspector reviewed FENOC's process to identify, prioritize and resolve Main ControlRoom Distractions to minimize operator burden. The inspector reviewed the system used to track these operator work-arounds and burdens and recent licensee self assessments of the program. The inspector toured the control room, and discussed the following items with the operators to ensure the items were being addressed on a schedule consistent with their relative safety significance: *Burden 200228554 and 200338555, "Stuck open check valve 1DG-P-2A and2B." Impact on results of RCS Inventory Balance Surveillance.*Burden 2001157437, "QS-P-1A high vibrations." Impact is increased monitoringrequirements for operators.

24Enclosure*Burden 200223265, "Test Operator for MOV-1RH-605." Impact is increasedmonitoring and possible need for manual operations. Condition not present during troubleshooting efforts.*Burden 200233635, "Fire Detector in Unit 2 West Cable Vault not communicatingwith XL3." Impact is additional monitoring until problem is identified and

corrected.

b. Findings

and AssessmentNo findings of significance were identified. At the time of the inspection, FENOCcurrently has no issues classified as operator work-arounds and relatively few operator burdens. These operator burdens were determined to have a minimal impact on the ability of the operator to promptly and appropriately respond to an event. The operators interviewed were aware of the status of the active operator burdens for their unit.The tracking system in place (SAP) appeared to be effective at ensuring operators andmanagement were aware of operator work-arounds and burdens and ensuring these items were addressed in a timely fashion. The inspector also found that the recommendations of the Self Assessment conducted in July 2005 had been implemented into the latest program revision.

.4 Power Uprate Inspection Module PI&R Review (1 sample)

a. Inspection Scope

The inspector reviewed a sample of condition reports and resulting corrective actionsrelating to the erosion-corrosion/flow-accelerated-corrosion (EC/FAC) program which identified EC/FAC conditions discovered during the current operating cycle. The inspector verified that the conditions and other deficiencies identified were reported, characterized, evaluated and appropriately dispositioned and entered into the corrective action program.

b. Findings

No findings of significance were identified..5Access Controls and ALARA Planning and Controls (1 sample)

a. Inspection Scope

The inspector reviewed twenty-six

(26) Condition Reports, a Nuclear Oversight FieldObservation report, and recent site ALARA committee meeting minutes to evaluate the threshold for identifying, evaluating, and resolving problems in implementing radiological controls. This review was conducted against the criteria contained in 10 CFR 20, TSs, and the licensee's procedures.

b. Findings

25EnclosureNo findings of significance were identified..6Radiation Monitoring Instrumentation and Protective EquipmentThe inspector reviewed selected Condition Reports (CR), Nuclear Quality AssessmentQuarterly reports, and field observation reports to evaluate the licensee's threshold for identifying, evaluating, and resolving problems in implementing the radiation monitoring instrumentation and respiratory protection programs. Included in this review were CR's related to radiation worker and radiation protection technician errors to determine if an observation traceable to a common cause was evident. This review was conducted against the criteria contained in 10 CFR 20, Technical Specifications, and the licensee'sprocedures.

b. Findings

No findings of significance were identified.4OA3Followup of Events and Notices of Enforcement Discretion (71153).1Unit 2 Loss of 'A' Train Feedwater Heating on November 17 On November 17, Unit 2 was at 97 percent power. At 0256 hours0.00296 days <br />0.0711 hours <br />4.232804e-4 weeks <br />9.7408e-5 months <br />, planned actions werebeing taken to return the 'A' 4 th point feedwater heater to service. It became apparent tothe control room operators, due to numerous feedwater heater alarms and lowering reactor coolant temperature, that a feedwater heater level transient was occurring. The level transient caused extraction steam (ie, feedwater heating) to isolate for the entire 'A' train feedwater heaters and two of six 'B' feedwater heaters. Operators took immediate action to manually reduce main turbine load and commenced borating the reactor in accordance with Abnormal Operating Procedure 51.1, "Emergency Shutdown", Rev. 11.

Lowering reactor coolant temperature caused a reactivity excursion and resulted in a momentary reactor power increase (102 percent peak for 1 second as calculated from delta temperature). Operators stabilized reactor power at 37 percent power, consistent and conservative with limitations established for no feedwater heating (40 percent power limit). The inspectors reviewed applicable operating and alarm response procedures, technical specifications, plant process computer indications, and control room shift logs to evaluate the adequacy of FENOC's response to these events. Appropriate TS limiting conditions for operation (LCOs) were entered. The inspectors also verified the events were entered into the corrective action program to resolve identified adverse conditions.

.2 Unit 2 Main Turbine Governor Valve Calibration on November 29On November 29, the inspector observed portions of the licensee's implementation ofnew partial arc curves for the main turbine governor valves GV1 and GV4.

This activity was performed under work order 200241441, and briefed as an infrequently performed test or evolution (IPTE). This activity involved input of new programming curves into the turbine governor control system. The inspector verified this IPTE had appropriate 26Enclosurepersonnel involved with the test, appropriate termination criteria, communications, andsupervision, including adequate controls in place to ensure appropriate implementation.

The inspector verified that the governor valves responded as expected and desired upon system restoration, and no significant issues were identified by the inspector..3Unit 1 Loss of Safety Parameter Display System (SPDS) displays in Control Room onDecember 3-5On December 3, the Shift Technical Advisor (STA) identified that the Unit 1 SPDSdisplays (there are two displays for Unit 1) were not receiving sensible data. The SPDS displays readily assessable information for emergency preparedness. The system was successfully rebooted according to procedure 1OM-5C.4.A, yet the SPDS failed to indicate properly. It was subsequently determined that a hardware failure existed with a projected outage time of two days. CR 06-10848 and Notification 600350762 documented the condition. The STA and control room operators verified that redundant information was available via the main control boards and plant process computer.

NUREG-1022, Rev. 2 was reviewed for reportability guidance. Due to the outage duration, the licensee conservatively determined this failure to be a loss of emergency preparedness capability pursuant to 10 CFR 50.72(b)(3)(xiii) and reported as Event Notification #43030..4(Closed) Licensee Event Report (LER) 05000344/2006-002-00: Unit ShutdownCompleted as Required by Plant Technical Specification for Failed Solid State Protection System Memory Card.On May 26, 2006, Beaver Valley Power Station (BVPS) Unit 1 identified a failure of auniversal logic card during performance of 1MSP-1.05-I, Solid State Protection System (SSPS) Train 'B' Bi-Monthly Test. The surveillance test indicated unsatisfactory results while performing the Memories Function Test. Technical Specifications required a plant shutdown to Mode 3. The Unit was placed in Mode 3 as required. The failure would not have prevented the SSPS from performing its safety function. The failed SSPS card was replaced and all post-maintenance testing was completed satisfactory. The root cause of this failure was indeterminate, but most probably determined to be a poor connection in the SSPS testing circuit which affected pin #4 of Universal Logic card A412. Corrective actions included replacing the failed card, post mortem testing by FENOC's Beta Labs and Westinghouse, visual inspections of the card rack connector for damage, and submittal of an operating experience report to the industry. The inspectors reviewed this LER and no findings were identified. The licensee has documented this event in their corrective action program under CR 06-6090. This LER is closed.

.5 (Closed) LER 05000344/2006-003-00: Inadvertent Technical SpecificationNon-Compliance Due To Inoperable Containment Isolation Valve.On July 22, 2006, Beaver Valley Power Station (BVPS) Unit 1 initiated a work activity toreplace a manual isolation valve in the pressurizer liquid sample line outside of

containment. The clearance intended to close and de-energize the outside containment 27Enclosureisolation valve (TV-1SS-100A2), which is normally open, fail closed, air operated valve. The clearance activity isolated the air supply to the valve at approximately 1315 hours0.0152 days <br />0.365 hours <br />0.00217 weeks <br />5.003575e-4 months <br />, however, the clearance did not provide adequate instructions to bleed off trapped air in the valve actuator. As a result, the valve remained open and could not have been closed remotely. At approximately 2310 hours0.0267 days <br />0.642 hours <br />0.00382 weeks <br />8.78955e-4 months <br />, an oncoming Reactor Operator identified that TV-1SS-100A2 was indicating open with a clearance tag posted on it.

The valve was placed in the closed position at 2351 hours0.0272 days <br />0.653 hours <br />0.00389 weeks <br />8.945555e-4 months <br />.This resulted in FENOC not being in compliance with Technical Specification ActionStatement (TSAS) 3.6.3.1 for an inoperable containment isolation valve. The TSAS requires, in part, that the affected penetration flow path to be isolated by the use of either one closed and deactivated automatic valve, closed manual valve, blind flange or check valve with flow through the valve secured, otherwise be in at least Hot Standby within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

FENOC did not comply with this requirement because TV-1SS-100A2 was not closed and de-energized for approximately 10.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The cause of the event was determined to be Human Performance errors which occurred in the development of the work package (Inattention to Detail) and during the clearance posting (Self Checks and Peer Checks). Corrective actions included immediately closing and de-energizing TV-1SS-100A2 to restore TS compliance, reviewing this event with all FENOC Operations Department personnel, and the development of a repetitive administrative task to require Operations Supervision/Management to perform field observations that focus on the use of human performance tools during clearance activities. The LER was reviewed by the inspectors and no new findings were identified. This finding constitutes a violation of NRC Requirements. The enforcement aspects of this finding are discussed in section 40A7 of this report. This LER is closed..6(Closed) LER 05000344/2006-004-00: Reactor Trip Due to a Failed Universal logicBoard in Solid State Protection System.On September 07, 2006, Beaver Valley Power Station (BVPS) Unit 1 experienced anunexpected reactor trip at 2157 due to the opening of the "B" Reactor Trip Breaker.

This was determined to have been caused by the failure of universal logic card A312B output gate in the Solid State Protection System (SSPS). This failure produced an invalid SSPS trip signal to trip the breaker. The root cause of this failure was a manufacturing defect on the integrated circuit card Z9 that was not identified by pre/post manufacturer testing. The licensee conducted a detailed root cause analysis, and along with Westinghouse, investigated the generic implications of this failure. Corrective actions included replacing the failed card, post-failure testing by FENOC's Beta Labs and Westinghouse, and development of a SSPS board replacement strategy. The inspectors reviewed this LER and no findings were identified. The licensee has documented this event in their corrective action program under CR 06-6090. This LER is closed.

.7 (Closed) LER 05000344/2006-005-00: Failure to Comply with Technical Specification toDe-Energize Safety Injection Flow Path Valves.

28EnclosureOn September 8, 2006, an Operations Supervisor discovered a discrepancy betweenthe plant shutdown procedure and the TS Basis for 3.5.4. This discrepancy had resulted in two Emergency Core Cooling System (ECCS) High Head Safety Injection (HHSI) Valves not being isolated as required by TS 3.5.4, from August 25 to August 29, 2006, while the plant was in Modes 4, 5, or 6. The TS Bases state for an HHSI valve to be isolated it shall be closed and de-energized. The shutdown procedure had been recently revised and incorrectly removed the instructions to de-energize the HHSI valves. The procedure was revised after approval of the 2005 Extended Power Uprate (EPU) License Amendment Request which was granted in July 2006.The HHSI valves are required to be isolated to prevent a potential unanalyzed coldoverpressure condition which could be caused by an inadvertent safety injection (SI)event. With the HHSI flow valves being closed, but not de-energized, they would still open upon receipt of an SI signal. The risk significance of the event was considered to be low because automatic SI signals were blocked, 2 of 3 HHSI pumps were made inoperable, and 2 power-operated relief valves (PORVs) were available during the majority of the exposure period. This line up is bounded by the current low temperature over-pressure design basis analysis. Corrective Actions included revising the incorrect procedures, training in Improved Standard Technical Specifications and Basis information, and an independent SRO review of TS compliance for all procedure changes made or being planned from the EPU. The LER was reviewed by the inspectors and no new findings were identified. This finding constitutes a violation of NRC Requirements. The enforcement aspects of this finding are discussed in section 40A7 of this report. The licensee has documented this event in their corrective action program under CR 06-6114. This LER is closed.

29Enclosure4OA5Other Activities.1Power Uprate, Inspection Procedure 71004 Unit 2 Power Uprate and 3-percent Power Ascension

a. Inspection Scope

The inspectors observed selected plant testing and other power ascension activitiesduring the implementation of the 3% phase (2689MWt to 2770 MWt) of a planned 3-phase extended power uprate totaling approximately 8% power. Inspectors observed and/or reviewed selected plant changes and testing prior to the power ascension that began on November 19, 2006. The inspectors observed control room and in-plant activities during the ascension to the new 100% power level, and walked down plant systems to ensure adverse conditions were both identified, and if warranted, entered into the corrective action program for resolution.The inspectors also reviewed operator actions, applicable procedure changes, andreviewed selected plant design changes and other inspection activities conducted under the normal baseline inspection program, to ensure an adequate sample of risk-significant attributes required by the governing procedure were evaluated.

This included changes to plant emergency operating procedures, as well as associated operator briefings and training to address those actions resulting from a revised steam generator tube rupture analysis. Specific inspections already completed and credited in past NRC inspection reports, as well as those credited in the current report can be found in the Attachment.

b. Findings

No findings of significance were identified.

Erosion-Corrosion and Flow-Accelerated Corrosion (EC/FAC)

a. Inspection Scope

The objectives of this inspection were to determine whether licensee activities relative toerosion-corrosion/flow-accelerated-corrosion (EC/FAC) monitoring and maintenance were being accomplished in accordance with 10 CFR 50.65, the Maintenance Rule, licensee commitments to implement Generic Letter 89-08, "Erosion/Corrosion Induced Pipe Wall Thinning," and licensee approved procedures. The inspector reviewed the EC/FAC program to determine whether Beaver Valley has taken required action to detect adverse effects (wall thinning) on systems and components as a result of operational changes related to Extended Power Uprate (EPU), such as increased flow in primary or secondary systems, including their interfacing systems. The inspector noted through documentation review that responsibility for the implementation of the FENOC EC/FAC program is delegated by controlled procedure to the Nuclear Engineering Services organization. The Assigned Erosion/Corrosion engineer has overall 30Enclosureresponsibilities concerning erosion/corrosion activities and is delegated responsibility forthe overall program effort.The inspector reviewed implementation of a long term EC/FAC monitoring program todetermine whether it was consistent with GL 89-08 and the guidelines in Electric Power Research Institute (EPRI) Report NSAC-202L-R2. Also, the inspector reviewed procedures and administrative controls to determine whether those procedures and controls ensure the structural integrity of high energy (single phase and two phase)carbon steel systems. The inspector reviewed the established EC/FAC program to determine whether the degradation of piping and components is described in the procedures, and the examination activities are managed, maintained and documented.The inspector reviewed the program to determine whether it was well defined andincluded systematic methods for predicting which systems and specific locations within those systems are susceptible to EC/FAC. In particular, the inspector reviewed those steps taken to identify specific locations that were most likely to be adversely affected by a change (increase) in operating variables (temperature, flow) as a result of increased power levels. Also, the inspector reviewed the licensee EC/FAC activity to determine status and effective utilization of the industry sponsored predictive program (CHECKWORKS) to verify the selection of the most susceptible locations for inspection and additional locations based on unique operating conditions and industry experience.

The inspector noted the inspection results are compared to the locations predicted as most susceptible to high wear to verify the program predictive accuracy. The inspector reviewed a portion of the inspection data and analysis of the most susceptible piping components to determine whether the results were clearly documented. Also, the inspector reviewed how inspection data was trended to determine EC/FAC wear rates and identify the future inspection locations. The inspector reviewed condition reports which identified wall thinning in piping during the current outage which was replaced based on predictive analysis of remaining life.The inspector performed a documentation review to determine if examination activitieswere performed in accordance with the ASME Boiler and Pressure Vessel Code requirements. The inspector reviewed the EC/FAC program to determine whether it contained specific guidance for actions, such as additional inspection (extent of condition), engineering evaluation and repair or replacement of those components when wall thinning is detected. The inspector reviewed the inspection procedures to determine whether repair or replacement of components determined or predicted to wear below minimum wall thickness requirements was to be performed in accordance with the ASME Section XI program or the original design code requirements.

Additionally, the licensee's method of performing ultrasonic testing (UT) of carbon steel for material thickness measurement was reviewed and found to be described in site approved procedures. Personnel conducting the non-destructive examinations were documented as qualified to perform wall thickness measurements. The inspector selected portions of the feedwater heater vents and drains and theextraction steam systems for a detailed review of the licensee's EC/FAC monitoring activities and effectiveness. The sample selection was based on the inspection 31Enclosureprocedure objectives and risk priority of those components and systems whereaccelerated wear rates were predicted to cause wall thinning. The inspector performed a "walkdown" of portions of the selected systems (piping and components) to verify the as-built configuration matched the plant specific EC/FAC program isometric drawings.

The inspector reviewed five EC/FAC program component isometrics and fifteen specific locations within the selected systems, which had been predicted to be susceptible to wear during the initial EC/FAC program evaluations using the CHECKWORKS predictive model. The inspector also reviewed selected locations in these systems that had been identified as susceptible to a projected increase in EC/FAC wear rates using the higher EPU operational variables with the CHECKWORKS model. The inspector determined that the potential increase in wear rates was recognized and these locations were incorporated into the program data base for future inspection sample selection.The inspector reviewed the specified acceptance criteria for required wall thickness todetermine that sufficient margin above the applicable code limits was provided to permit an evaluation and determination of appropriate corrective actions.

b. Findings

No findings of significance were identified..2Temporary Instruction (TI) 2515/166 - Pressurized Water Reactor Containment SumpBlockage

a. Inspection Scope

The inspectors performed the inspection in accordance with Temporary Instruction (TI)2515/166. The TI was developed to support the NRC review of licensee activities in response to NRC Generic Letter (GL) 2004-02, "Potential Impact of Debris Blockage on Emergency Sump Recirculation at Pressurized Water Reactors (PWR)." Specifically, the inspectors verified implementation of the modifications and procedure changes committed to in the GL response. The inspectors reviewed a sample of the licensing and design documents to verify that they were either updated or in the process of being updated to reflect the modifications. A sample of material specifications, testing and surveillance procedures, and calculations were reviewed to verify that they were updated to reflect the effects of the modification, and the new requirements for the containment sumps and debris generation sources. The inspectors performed a walkdown of the strainer installation to verify it was performed in accordance with the approved design change package. Finally, the inspectors verified that there were no choke-points that could prevent water from reaching the recirculation sump during a design basis accident.

b.Evaluation of Inspection RequirementsThe TI requested the inspectors to evaluate and answer the following questions:1. Did the licensee implement the plant modifications and procedure changescommitted to in their GL 2004-02 response?The inspectors verified that actions implemented by the licensee as described inresponse to Generic Letter 2004-02 were partially complete as it related to the installation of the sump screen and the potential for clogging of downstream component due to debris bypass. FENOC installed a significantly larger strainer with an integral temporary strainer, which satisfies the current design basis.

FENOC will modify the recirculation spray system (RSS) pump start signal and replace two high pressure safety injection (HPSI) throttle valves during the next refueling outage to complete the actions identified in their GL response. The inspectors found that procedures to programmatically control potential debris generation sources were updated. 2. Has the licensee updated its licensing basis to reflect the corrective actionstaken in response to GL 2004-02? The inspectors verified that the interim changes to the facility, as described in theUFSAR and identified in the licensee's GL 2004-02 response, were reviewed and documented in accordance with 10 CFR 50.59. FENOC intends to submit a license amendment in March 2007 to address the changes to RSS. The TI will remain open to allow for the review of portions of the GL response that havenot been completed. Specifically, FENOC has not completed the modification of the high pressure safety injection throttle valves and has not implemented the revised recirculation spray system pump start signal setpoint. Therefore, the inspection will be considered partially complete until the final modifications are reviewed. FENOC has an approved extension to complete these items during their next refueling outage in the Spring of 2008.

c. Findings

No findings of significance were identified..3Temporary Instruction (TI) - 2515/169, Mitigating System Performance Index Verification

a. Inspection Scope

The objective of TI 2515/169 was to verify that the licensee had correctly implementedthe Mitigating Systems Performance Index (MSPI) guidance for voluntarily reporting unavailability and unreliability of the monitored safety systems. On a sampling basis, the inspector validated the accuracy of the unavailability and unreliability input data used for both the 12-quarter period of baseline performance and for the first reported results 33Enclosure(second calendar quarter 2006). Specific attributes examined by the inspectors for thisTI included: surveillance activities which, when performed, do not render the train unavailable for greater than 15 minutes; surveillance activities which, when performed, do not render the train unavailable due to credit for prompt operator recovery actions; and for each MSPI system, on a sampling basis, the inspectors independently confirmed the accuracy of baseline planned unavailability, actual planned and unplanned unavailability, and the accuracy of the failure data (demand, run, and load, as appropriate) for the monitored components.During portions of this inspection, the inspector was accompanied by an observer fromthe State of Ohio Emergency Management Agency.

b. Findings and Observations

No findings of significance were identified. In accordance with the reportingrequirements of TI 2515/169, the following are the results of five areas specifically reviewed by the inspector to verify the accuracy of FENOC's MSPI data for Beaver Valley Unit 1 and Unit 2:(1)The inspector reviewed calculations of baseline planned unavailability hours toensure that FENOC correctly determined baseline data for the MSPI indices and properly translated the data to the consolidated data entry (CDE) input sheet and electronic entry. The inspector noted that the licensee utilized correct critical hour data and was consistent with the value independently calculated by the inspector.The inspector also reviewed MSPI monitoring of the cooling water systems (riverwater and service water) to determine if FENOC correctly accounted for planned and unplanned unavailability resulting from cascading support system inoperability. The inspector did not identify any significant issues in this area.(2)The inspector reviewed multiple documents, including main control room logs,condition reports, notifications, work orders, and completed surveillance tests to verify the accuracy and completeness of the reported actual unavailability data for the MSPI systems. The inspector did not identify any significant errors in this data.(3)The inspector reviewed a sample of Beaver Valley's unreliability data to confirmthat FENOC accurately classified valve and breaker demand failures, emergency diesel generator failures to start, load, or run, and pump demand failures and failures to run. The inspector did not identify any errors in the reported unreliability data. (4)The inspector reviewed the reported MSPI data to verify that the data wasaccurate. The inspector did not identify any significant errors which would have resulted in a change to the indicated index colors.

34Enclosure(5)The inspector reviewed Beaver Valley Unit 1 & Unit 2 MSPI basis documentsand associated appendices. The inspector did not identify any significant errors that would result in a change to MSPI system boundaries, an addition of a monitored component, or a change in the reported index color.4OA6Management Meetings.1Access Control / ALARA Planning and ControlThe inspector presented the inspection results of Sections 2OS1 and 2OS2 toMr. Richard Mende, former Director of Site Operations, and other members of FENOC staff, at the conclusion of the inspection on October 6, 2006. The licensee acknowledged the conclusions and observations presented. No proprietary information is presented in this report..2Inservice InspectionThe inspector presented the inspection results of Section 1R08 to Mr. James Lash, SiteVice President, and other members of FENOC staff, at the conclusion of the inspection on October 26, 2006. The licensee acknowledged the conclusions and observations presented. No proprietary information is presented in this report..3Radiation Monitoring Instrumentation and Protective EquipmentThe inspector presented the inspection results of Section 2OS3 to Mr. Peter Sena,former Director of Design Engineering, and other members of FENOC staff, at the conclusion of the inspection on December 14, 2006. The licensee acknowledged the conclusions and observations presented. No proprietary information is presented in this report..4Quarterly Inspection Report ExitOn January 18, 2007, the inspectors presented the normal baseline inspection results toMr. Peter Sena, newly appointed Director of Site Operations, and other members of the licensee staff. The licensee acknowledged the conclusions and observations presented.

The inspectors confirmed that proprietary information was not retained at the conclusion of the inspection period.

35Enclosure4OA7Licensee-Identified ViolationsThe following violations of very low safety significance (Green) were identified by thelicensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violations (NCVs).*10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires in part, thatconditions adverse to quality be promptly identified and corrected. Contrary to the above, on October 1, 2006, the licensee identified that scaffolding had been constructed around the Unit 2 "A" and "B" main steam isolation valves (MSIVs)over a two day period, September 29 and 30, 2006, that potentially would have prevented the MSIVs from fully closing, when needed and required during accident conditions.The licensee subsequently removed the obstructing portions of the scaffolding,entered and exited the appropriate technical specifications, as required, and restored the operability of the MSIVs. This finding is more than minor, because if left uncorrected, a delay in prompt identification of an adverse condition such as this scaffolding interference with safety-significant MSIVs, would have led to a more significant safety concern. This issue was entered into the corrective action program as condition report CR-06-7046, "Scaffold Interference With Operation Of 2MSS-AOV101A And 2MSS-AOV101B." This finding was determined to be of very low safety significance (Green), based on the risk significance results from a Phase 3 risk analysis, and compromised the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. This analysis was performed using the Beaver Valley Unit 2 Standardized Plant Analysis Risk (SPAR) model, Rev. 3.31, and SAPHIRE version 7.26, dated October 18, 2005. *Technical Specification 3.6.3.1 states, in part, for an inoperable containmentisolation valve, the affected penetration flow path shall be isolated by the use of one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured, otherwise be in at least Hot Standby within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Contrary to the above, on July 22, 2006, BVPS did not comply with this requirement because TV-1SS-100A2 was not closed and de-energized for approximately 10.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> while TV-1SS-100A2, an automatic containment isolation valve, was inoperable. This finding is more than minor because it affects the configuration control attribute of the associated Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding screens to very low safety significance (Green) using IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings at Power," because the finding did not represent an actual open pathway in containment. This finding was identified by the licensee, entered into their 36corrective action program as CR 06-04438 and the required reports were madeto the NRC.*Technical Specification 3.5.4.1.2 states, in part, when cold leg temperature isless than 350F, the boron injection tank flow path shall be isolated and power removed from the inlet and outlet valves. Contrary to the above, from 10:35 a.m.

on August 25, 2006 until 2:31 am on August 29, 2006, BVPS did not comply with this requirement because two HHSI valves were closed but not de-energized.

This finding is more than minor because it affects the configuration control attribute of the associated Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The finding screens to very low safety significance (Green) using IMC 0609, Appendix G, "Shutdown Operation Significance Determination Process." This finding was identified by the licensee, entered into their corrective action program as CR 16-6114 and the required reports were made to the NRC.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

G. AlbertiSteam Generator Program OwnerS. BakerSite, Radiation Protection Manager

R. BolognaOperations Manager

R. BoyleSystem Engineer

G. CaccianiStaff Nuclear Engineer

D. CananSupervisor, Respiratory Protection

J. ClarkRadiation Protection Health Services Technician

G. DavieManager, Training

J. FontaineSupervisor, ALARA

K. FrederickSenior Consultant

L. FreelandDirector Performance Improvement

J. FreundSupervisor, Rad Operations Support

D. GrabskiISI Coordinator

R. HansenManager, Nuclear Oversight

T. HeimelNDE Level III

C. HrelecSenior Radiation Protection Technician

D. JonesIST Program Engineer

H. KahlDesign Engineering

K. KimmerleSupervisor, Portable Instruments

T. KeloskyProduction Supervisor

J. LashSite Vice President

J. LebdaRadiation Protection Services Supervisor

E. LoehleinAlloy 600 Program Owner

A. LonnettAdministrator, RETS/REMP program

J. LutzUnit 2 Supervisor

M. ManolerasDesign Manager

J. MauckCompliance Engineer

R. MendeDirector, Site Operations

J. MeyersSystem Engineer

T. MahoneySenior Radiation Protection Technician

C. MillerSenior Radiation Protection Technician

L. MillerFire Protection Engineer / Marshall

J. MillerFire Protection Engineer / Marshall

R. MooreRadiation Protection Supervisor

R. MooreEPIX Data Processor, FENOC

R. PattisonSenior Radiation Protection Technician

R. PucciSenior Nuclear Specialist, ALARA Coordinator

A. RyanProduction Manager

R. SacchetRadiological Analyst, Emergency Management Agency (Ohio)

P. SenaDirector Engineering

A-2AttachmentAttachment

B. SepelakSupervisor, Regulatory Compliance

J. SippManager, Chemistry

R. SnowdenElectrical Maintenance Supervisor

T. SockaciDesign Engineer

B. SommersOperations Surveillance Manager

H. SzklinskiNuclear Quality Assessor

K. TiefenthalUnit 2 Shift Manager

P. VakharaSystems Engineer, Area Radiation Monitoring Systems

J. WestVentilation Systems Engineer

J. WhiteQuality Control

W. WilliamsBACC Program Owner

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Open/Closed05000334/2006002-00LERUnit Shutdown Completed as Required by Plant TechnicalSpecification for Failed Solid State Protection System

Memory Card (Section 4OA3.

4)05000334/2006003-00LERInadvertent Technical Specification Non-Compliance DueTo Inoperable Containment Isolation Valve (Section

4OA3.5)05000334/2006004-00LERReactor Trip Due to a Failed Universal logic Board in SolidState Protection System (Section 4OA3.

6)05000334/2006005-00LERFailure to Comply with Technical Specification toDe-Energize Safety Injection Flow Path Valves

(Section 4OA3.

7)

Section 1R01:

Adverse Weather ProtectionProcedures1OST-45.11, Rev. 16, Cold Weather Protection Verification2OST-45.11, Rev. 17, Cold Weather Protection Verification