IR 05000424/2006004

IR 05000424-06-004, 05000425-06-004, on 07/01/2006 - 09/30/2006, Vogtle Electric, Units 1 and 2; Identification and Resolution of Problems, Event Followup

ML063040015
Person / Time
Site:	Vogtle
Issue date:	10/30/2006
From:	Scott Shaeffer NRC/RGN-II/DRP/RPB2
To:	Grissette D Southern Nuclear Operating Co
References
IR-06-004
Download: ML063040015 (26)

Text

October 30, 2006Southern Nuclear Operating Company, Inc.ATTN:Mr. D. E. Grissette, Vice President - Vogtle ProjectP. O. Box 1295 Birmingham, AL 35201-1295SUBJECT:VOGTLE ELECTRIC GENERATING PLANT - NRC INTEGRATED INSPECTIONREPORT 05000424/2006004 AND 05000425/2006004

Dear Mr. Grissette:

On September 30, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed aninspection at your Vogtle Electric Generating Plant, Units 1 and 2. The enclosed integrated inspection report documents the inspection results, which were discussed on October 6, 2006, with Mr. Tom Tynan 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. This report documents one NRC-identified finding of very low safety significance (Green) whichwas determined to involve a violation of NRC requirements and one self-revealing finding.

However, because the violation is of very low safety significance and because it is entered into your corrective action program, the NRC is treating this violation as a non-cited violation (NCV)

consistent with Section VI.A of the NRC Enforcement Policy. If you contest this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Vogtle Electric Generating Plant.

2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, 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 the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/Scott M. Shaeffer, ChiefReactor Projects Branch 2 Division of Reactor ProjectsDocket Nos.: 50-424, 50-425License Nos.: NPF-68, NPF-81

Enclosure:

Inspection Report 05000424/2006004 and 05000425/2006004 w/Attachment: Supplemental Information

REGION IIDocket Nos.: 50-424, 50-425 License Nos.: NPF-68, NPF-81 Report Nos.:05000424/2006004 and 05000425/2006004 Licensee:Southern Nuclear Operating Company, Inc.

Facility:Vogtle Electric Generating Plant, Units 1 and 2 Location:Waynesboro, GA 30830 Dates:July 1, 2006 through September 30, 2006 Inspectors:G. McCoy, Senior Resident InspectorP. O'Bryan, Acting Senior Resident Inspector B. Anderson, Resident Inspector R. Taylor, Reactor Inspector (Section 1R07)

J. Rivera-Ortiz, Reactor Inspector (Section 1R07)

M. Scott, Senior Reactor Inspector (Section 1R12)

E. Michel, Reactor Inspector (Section 1R12)Accompanying Personnel: M. Lewis, Coop Approved by:Scott M. Shaeffer, ChiefReactor Projects Branch 2 Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000424/2006-004, 05000425/2006-004; 07/01/2006 - 09/30/2006; Vogtle ElectricGenerating Plant, Units 1 and 2; Identification and Resolution of Problems, Event Followup.The report covered a three-month period of inspection by three resident inspectors and fourregional reactor inspectors. One Green non-cited violation (NCV) and one Green finding were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified for inadequate work instructions andpoor work practices associated with the installation of a surge arrestor design change on the Unit 2 loop 4 reactor coolant pump (RCP). This condition resulted in short circuiting in the surge arrestor cable which resulted in a trip of the loop 4 RCP and subsequent reactor trip.The inspectors determined that the cause of this finding was related to the workpractices aspect of the human performance cross-cutting area because the work instructions did not contain adequate detail to properly install the surge arrestor cable. This finding is greater than minor because it affected the human performance and procedure quality attributes of the Initiating Event cornerstone in that the installed loop 4 surge arrestor cable was incorrect in type and size and was incorrectly installed. The finding was determined to be of very low safety significance (Green) because it did not increase the likelihood that mitigation equipment or functions would not be available. (Section 4OA3)

Cornerstone: Mitigating Systems

Green.

The inspectors identified an NCV of 10CFR50, Appendix B, Criterion XVI,for a failure to promptly identify and correct a condition adverse to quality. During an environmental qualification (EQ) self-assessment in June, 2005, the licensee discovered that two Rosemount differential pressure transmitters with potentially damaged environmental seals between the electronics and the pressure sensing sections of the instrument. This violation has been entered in the licensee corrective action program as CR 2006109187The finding is of more than minor significance because it affects the equipmentavailability and reliability attribute of the Mitigating Systems cornerstone objective in that the damaged seals reduced the reliability of safety-related systems. The NRC Region II Senior Reactor Analyst (SRA) determined that the Phase 2 significance evaluation process does not properly address this finding. Therefore, a Phase 3 significance determination evaluation was performed. The dominant accident 3sequence involved a Medium Break Loss of Coolant Accident followed by the failureof three channels of the Engineered Safety Features Actuation System, one due to a failed EQ seal and the other two via random failure. The Phase 3 results were that the finding was of very low safety significance (Green) since only one pressurizer pressure transmitter was affected. (Section 4OA2.2)

B.Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant StatusUnit 1 started the inspection period at full rated thermal power (RTP). The unit operated atessentially full RTP until September 18 when the reactor was shutdown for a planned refueling outage. Unit 2 operated at essentially full RTP until August 27 when the unit tripped due to a trip of theloop 4 RCP. The unit was restarted on September 1 and attained full RTP on September 2.

The unit operated at full RTP for the remainder of this report period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R04Equipment Alignmenta.Inspection ScopePartial Walkdowns. The inspectors performed partial walkdowns of the following threesystems to verify correct system alignment. The inspectors checked for correct valve and electrical power alignments by comparing positions of valves, switches, and breakers to the procedures and drawings listed in the Attachment. Additionally, the inspectors reviewed the condition report (CR) database to verify that equipment alignment problems were being identified and appropriately resolved.Unit 1 train B control room emergency filtration system (CREFS) during Unit 1 trainA CREFS maintenance.Unit 1 train A nuclear service cooling water (NSCW) system during NSCW pumpnumber 1 maintenance.Unit 1 train B residual heat removal (RHR) system with the A RHR train out ofservice for planned maintenance.Complete System Walkdown. The inspectors performed a complete walkdown of theUnit 1 auxiliary feedwater (AFW) system. The inspectors performed a detailed check of valve positions, electrical breaker positions, and operating switch positions to evaluate the operability of the redundant trains or components by comparing the required position in the system operating procedure to the actual position. The inspectors also interviewed personnel, reviewed control room logs and CRs to verify that alignment and equipment discrepancies were being identified and appropriately resolved. The documents reviewed are listed in the Attachment.b.FindingsNo findings of significance were identified.

51R05Fire Protectiona.Inspection ScopeThe inspectors walked down the following nine plant areas to verify the licensee wascontrolling combustible materials and ignition sources as required by procedures 92015-C, Use, Control, and Storage of Flammable/Combustible Materials, and 92020-C, Control of Ignition Sources. The inspectors assessed the observable condition of fire detection, suppression, and protection systems and reviewed the licensee's fire protection Limiting Condition for Operation log and CR database to verify that the corrective actions for degraded equipment were identified and appropriately prioritized.

The inspectors also reviewed the licensee's fire protection program to verify the requirements of Updated Final Safety Analysis Report (UFSAR) Section 9.5.1, FireProtection Program, and Appendix 9A, Fire Hazards Analysis, were met. Documents reviewed are listed in the Attachment.Unit 1 control building level A west penetration roomsUnit 1 rod control switchgear and motor generator roomsUnit 2 north main steam valve houseUnit 1 A and C battery and switchgear roomsUnit 2 control building level B east penetration roomsUnit 2 A and C battery and switchgear roomsUnit 1 auxiliary component cooling water (ACCW) pump roomsUnit 2 containment buildingUnit 1 containment buildingb.FindingsNo findings of significance were identified.

1R06 Flood Protection Measuresa.Inspection ScopeInternal Flood Review.

The inspectors reviewed the UFSAR and Individual PlantExamination and walked down the following three areas which contained risk-significant structures, systems and components (SSCs) below flood level to verify flood barriers were in place. Motor controllers and terminal boxes that could become potentially submerged were inspected to ensure that the sealing gasket material was intact and undamaged. The inspectors reviewed selected licensee alarm response procedures to verify alarm setpoints and setpoints for sump pump operation were consistent with the UFSAR, the setpoint index, and Technical Specifications (TS).*Unit 2 train A motor driven AFW pump room*Unit 2 train B motor driven AFW pump room

• Unit 2 turbine driven AFW pump roomExternal Flood Review. The inspectors reviewed the licensee's external floodingmitigation procedures and equipment to verify they were consistent with the licensee's 6design requirements and risk analysis assumptions. The inspectors discussed externalflooding preparation with engineering personnel to verify preparation and compensatory measures met the licensee's design requirements and risk analysis assumptions. The inspectors checked selected external drain systems to verify the drains would function properly. The inspectors reviewed a sampling of CRs to verify the licensee was identifying and correcting problems associated with flood detection and protection of SSCs . Documents reviewed are listed in the Attachment.b.FindingsNo findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

Biennial Program Inspection. The inspectors reviewed inspection records, test results,maintenance work orders, and other documentation listed in the Attachment to ensure that heat exchanger (HX) deficiencies that could mask or degrade performance were identified and corrected. The three risk significant heat exchangers reviewed were the Component Cooling Water (CCW) HXs, Emergency Diesel Generator (EDG) jacket water HXs, and Containment Spray (CS) pump motor coolers. The inspectors reviewed completed HX inspection and cleaning procedures, inspectionfrequency, and tube plugging maps. In addition, the inspectors reviewed eddy current test reports for the selected HXs. These documents were reviewed to determine that:

1) selected heat exchanger test methodology was consistent with NRC Generic Letter 89-13 (Service Water System Problems Affecting Safety-Related Equipment)commitments; 2) test conditions were appropriately considered; 3) test or inspection criteria were appropriate and met; 4) test frequency was appropriate; 5) as-found results were appropriately dispositioned such that the final condition was acceptable; and 6)test results considered test instrument inaccuracies and differences.The inspectors also reviewed the general health of the Nuclear Service Cooling Water(NSCW) system. The inspectors reviewed design basis documents and system health reports and had discussions with the NSCW system engineer to verify the design basis was being maintained and to verify adequate NSCW system performance under current preventive maintenance, inspections, and test frequencies.CRs were reviewed for potential common cause problems and problems which couldaffect system performance to confirm that the licensee was entering problems into the corrective action program and initiating appropriate corrective actions. In addition, the inspectors conducted a walk down of selected HXs and major components for the NSCW system to assess general material condition and to identify any degraded conditions of selected components.b.FindingsNo findings of significance were identified.

71R11Licensed Operator Requalificationa.Inspection ScopeThe inspectors evaluated operator performance during licensed operator simulatortraining described on simulator exercise guide V-RQ-SE-06502. The simulator scenario covered operator actions resulting from a loss of coolant accident inside the containment building. Procedures reviewed are listed in the Attachment. The inspectors specifically assessed the following areas:Correct use of the abnormal and emergency operating proceduresAbility to identify and implement appropriate actions in accordance with therequirements of the TSsClarity and formality of communications in accordance with procedure 10000-C,Conduct of OperationsProper control board manipulations including critical operator actionsQuality of supervisory command and controlEffectiveness of post-evaluation critiqueb.FindingsNo findings of significance were identified.

1R12 Maintenance Effectivenessa.Inspection ScopeTriennial Periodic Evaluation.

The inspectors reviewed the licensee's Maintenance Rule(MR) periodic assessment, Plant Vogtle Units 1 and 2 Maintenance Rule Periodic Assessment Nov 14-18, 2005 while on-site the week of July 17, 2006. This report was issued to satisfy paragraph (a)(3) of 10 CFR 50.65, and covered the 24 month period ending November, 2005. The inspection was to determine the effectiveness of the assessment and that it was issued in accordance with the time requirement of the MR and included an evaluation of: balancing reliability and unavailability, (a)(1) activities, (a)(2) activities, and use of industry operating experience. To verify compliance with 10 CFR 50.65, the inspectors reviewed selected MR activities covered by the assessment period for the following maintenance rule component and attendant systems: RHR, Containment Penetration Conductor Electrical Protection, Reactor Coolant System(RCS), Condensate and Feed, and Process Protection and Control System. Documents reviewed are listed in the Attachment. During the inspection, the inspectors reviewed selected plant work order data,assessments, modifications, the site guidance implementing procedures, discussed and reviewed relevant CRs, reviewed generic operations event data, Maintenance Rule Implementation Monthly Status Reports, system health reports, and discussed issueswith system engineers. Operational event information was evaluated by the inspectors in its use in MR functions. The inspectors selected corrective action documents on systems recently removed from 10 CFR 50.65 a(1) status and those in a(2) status for some period to assess the justification for their status. The inspectors toured and 8inspected repaired components. The documents were compared to the site's MRprogram criteria, and the MR a(1) evaluations and rule related data bases. Resident Inspector Quarterly Review. The inspectors reviewed two equipment problemsto evaluate the effectiveness of the licensee's handling of equipment performance problems and to verify the licensee's maintenance efforts met the requirements of 10 CFR 50.65 and licensee procedure 50028-C, Engineering Maintenance Rule Implementation. The reviews included adequacy of the licensee's failure characterization, establishment of performance criteria or 50.65 (a)(1) performance goals, and adequacy of corrective actions. Other documents reviewed during this inspection included control room logs, system health reports, the MR database, and maintenance work orders (MWOs). Also, the inspectors interviewed system engineers and the MR coordinator to assess the accuracy of identified performance deficiencies and extent of condition. Documents reviewed are listed in the Attachment.CR 2006108358, Unit 2 component cooling water pump #1 high bearing temperatureCR 2006108333, Unit 2 atmospheric relief valve 2PV-3000 failed stroke timeb.FindingsNo findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluationa.Inspection ScopeThe inspectors reviewed the following six risk significant and emergent MWOs to verifyplant risk was properly assessed by the licensee prior to conducting the activities.

The inspectors reviewed risk assessments and risk management controls implemented for these activities to verify they were completed in accordance with procedure 00354-C, Maintenance Scheduling, and 10 CFR 50.65(a)(4). The inspectors also reviewed the CR database to verify that maintenance risk assessment problems were being identified at the appropriate level, entered into the corrective action program, and appropriately resolved.Unit 1 train A NSCW pump outages Unit 2 loops 1, 2, and 4 bypass feedwater regulating valve (BFRV) I/P transducerreplacement Unit 2 solid state protection system (SSPS) and reactor trip breaker (RTB) testingwith anticipated transient without scram mitigation system actuation circuitry (AMSAC) bypassed Unit 1 train A RHR outage Unit 2 RCP #4 motor repairsUnit 1 and Unit 2 operations during peak grid loading conditionsb. FindingsNo findings of significance were identified.

91R15Operability Evaluationsa.Inspection ScopeThe inspectors reviewed the following five evaluations to verify they met therequirements of Nuclear Management Procedure (NMP)-GM-002, Corrective Action Program, and NMP-GM-002-001, Corrective Action Program Instructions. This included a review of the technical adequacy of the evaluations, the adequacy of compensatory measures, and the impact on continued plant operation.CR 2006107422, Unit 2 A EDG jacket cooling water leakageCR 2005104189, Unit 1 pressure transmitters 1PT-6161 and 1PT-6163environmental seal damageCR 2005111462, Units 1 and 2 safety injection accumulators uncertainty calculationCR 2006108668, Unit 1 pressurizer pressure control system use of back-up heatersCR 2006110015, Unit 1 train B EDG fuel oil strainer high differential pressureb.FindingsNo findings of significance were identified.

1R19 Post-Maintenance Testinga.Inspection ScopeThe inspectors either observed post-maintenance testing or reviewed the test results forthe following five maintenance activities to verify that the testing met the requirements of

procedure 29401-C, Work Order Functional Tests, for ensuring equipment operability and functional capability was restored. The inspectors also reviewed the test procedures to verify the acceptance criteria was sufficient to meet the TS operability requirements.

MWO 20600132, Unit 2 loop 4 (BFRV) (2LV5242) I/P transducer replacementMWO 20402576, Unit 2 loop 1 atmospheric relief valve (ARV) (2PV3000) systemoutage MWO 20615005, Unit 2 loop 3 main feedwater regulating valve (MFRV) feedbackpotentiometer replacementMWO 10302403, Unit 1 NSCW pump # 6 motor refurbishmentMWO 10604707, Replace transmitter 1FT0132b.FindingsNo findings of significance were identified.

101R20Refueling and Outage Activitiesa.Inspection ScopeUnit 2 Forced Outage. The inspectors performed the following inspection activitiesdescribed below for the Unit 2 forced outage that began on August 27, 2006, when the loop 4 RCP tripped causing a reactor trip. An electrical fault in the surge arrestor cabling was determined to be the cause of the failure and was repaired prior to restart.

Documents reviewed are listed in the Attachment.*Reviewed RCS pressure, level, and temperature instruments to verify that theinstruments provided accurate indication and that allowances were made for instrumentation errors.*Reviewed the status and configuration of electrical systems to verify that thosesystems met TS requirements and the licensee's outage risk control plan.*Reviewed selected control room operations to verify that the licensee was controllingreactivity in accordance with the technical specifications.*Reviewed the outage risk plan to verify that activities, systems, and/or componentswhich could cause unexpected reactivity changes were identified in the outage risk plan and were controlled.Unit 1 Refueling Outage. The inspectors performed the following inspection activitiesdescribed below for the Unit 1 refueling outage that began on September 17, 2006.*Reviewed the outage risk plan to verify that activities, systems, and/or components,which could cause unexpected reactivity changes, were identified in the outage risk plan and were controlled.*Reviewed the licensee's plans for changing plant configurations to verify that TSs,license conditions, and other requirements, commitments, and administrative procedure prerequisites were met prior to changing plant configurations.*Reviewed selected control room operations to verify that the licensee was controllingreactivity in accordance with the TSs.*Reviewed the status and configuration of electrical systems to verify that thosesystems met TS requirements and the licensee's outage risk control plan.*Observed decay heat removal parameters to verify that the system was properlyfunctioning and providing cooling to the core.*Reviewed RCS pressure, level, and temperature instruments to verify that theinstruments provided accurate indication and that allowances were made for instrumentation errors.The inspectors confirmed that, when the licensee removed equipment from service, thelicensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TSs, and that configuration changes due to emergent work and unexpected conditions were controlled in accordance with the outage risk control plan.b.FindingsNo findings of significance were identified.

111R22Surveillance Testinga.Inspection ScopeThe inspectors reviewed the following seven surveillance test procedures and eitherobserved the testing or reviewed test results to verify that testing was conducted in accordance with the procedures and that the acceptance criteria adequately demonstrated that the equipment was operable. Additionally, the inspectors reviewed the CR database to verify that the licensee had adequately identified and implemented appropriate corrective actions for surveillance test problems. Documents reviewed are listed in the Attachment.Surveillance Tests24565-2, RCP 2 Train A, Reactor Trip Relays Underfrequency (281 A),Undervoltage (227 A), Timing (262R A) Trip Actuating Device Operational Test and Channel Calibration28820-C, 2AD1CB Battery Charger Load Test28210-C, Main Steamline Code Safety Valve Setpoint VerificationIn-Service Tests14808-1, Train B Centrifugal Charging Pump and Check Valve Inservice Test andResponse Time14830-1, Quarterly Check Valve Inservice Test (Auxiliary Feedwater)14804-1, Safety Injection Pump Inservice and Response Time TestContainment Isolation Valve Tests14349-1, Containment Penetration No. 49, Excess Letdown and Seal Water LeakoffLocal Leak Rate Testb.FindingsNo findings of significance were identified.

1R23 Temporary Plant Modificationsa.Inspection ScopeThe inspectors evaluated the following Temporary Modifications (TM) and associated 10CFR 50.59 screening against the system design basis documentation and UFSAR to

verify that the modification did not adversely affect the safety functions of important safety systems. Additionally, the inspectors reviewed licensee procedure 00307-C, Temporary Modifications, to assess if the modification was properly developed and implemented.*TM 2061013201, Temporary change to the operation of Unit 2 feedwater systemallowing MFRVs and BFRVs to be open at full power operation*TM 2061300501, Temporary change to the Unit 2 feedwater system for replacementof MFRV feedback potentiometers 12b.FindingsNo findings of significance were identified.1EP6Drill Evaluationa.Inspection ScopeThe inspectors reviewed the facility activation exercise guide and observed the followingemergency response activity to verify the licensee was properly classifying emergency events, making the required notifications, and making appropriate protective action recommendations in accordance with procedures 91001-C, Emergency Classifications, and 91305-C, Protective Action Guidelines.On August 2, the licensee conducted a simulator exercise involving a loss of reactorcoolant and containment breach.b.FindingsNo findings of significance were identified.4.OTHER ACTIVITIES4OA1Performance Indicator (PI) Verificationa.Inspection ScopeThe inspectors sampled licensee submittals for the PI listed below during the periodfrom January 1, 2005 to June 30, 2006 for Unit 1 and Unit 2. The inspectors verified the licensee's basis in reporting each data element using the PI definition and guidance contained in: procedures 00163-C, NRC Performance Indicator and Monthly Operating Report Preparation and Submittal, and 50025-C, Reporting of Mitigating System Performance Indicator Unavailability; and Nuclear Energy Institute (NEI) 99-02, Revision 4, Regulatory Assessment Indicator Guideline.Mitigating Systems CornerstoneSafety System Functional Failuresb.FindingsNo findings of significance were identified.4OA2Identification and Resolution of Problems.1Daily Screening of Corrective Action ItemsAs required by Inspection Procedure 71152, Identification and Resolution of Problems,and in order to help identify repetitive equipment failures or specific human performance 13issues for follow-up, the inspectors performed a daily screening of items entered into thelicensee's corrective action program. This review was accomplished by either attending daily screening meetings that briefly discussed major CRs, or accessing the licensee's computerized corrective action database and reviewing each CR that was initiated..2Annual Sample Reviewa.Inspection ScopeThe inspectors performed a detailed review of the following CR to verify the full extent ofthe issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors evaluated the CR against the licensee's corrective action program as delineated in licensee procedure NMP-GM-002, Corrective Action Program, and 10 CFR 50, appendix B.

CR 2005104189, Rosemount transmitters with degraded environmental sealsb. FindingsIntroduction. The inspectors identified a Green NCV of 10CFR50, Appendix B, CriterionXVI, for a failure to promptly identify and correct a condition adverse to quality. During an environmental qualification (EQ) self-assessment in June, 2005, the licensee discovered that two Rosemount differential pressure transmitters with potentially damaged environmental seals between the electronics and the pressure sensing sections of the instrument.Description. Vendor technical guidance cautions against rotating the electronicsenclosure relative to the body of the transmitter because doing so may damage the sealant which protects the electronics enclosure from potential adverse environmental conditions, such as a steam filled environment. The licensee also discovered that their installation and calibration procedures for the transmitters did not include a precaution against rotating the electronics section relative to the pressure sensing section, and that several transmitters were potentially affected by this condition. The licensee developed a plan to inspect the transmitters as the 18 month calibration came due. In December 2005, a safety-related instrument, Unit 2 pressurizer pressure instrument (2PT-0455),

was discovered to have a potentially damaged seal. In July 2006, inspectors questioned the licensee's timeliness in the identification of the full scope of the problem in that several accessible safety-related instruments had yet to be inspected. The licensee subsequently completed all the inspections on August 9, 2006, and discovered that two additional safety-related transmitters were installed incorrectly. These two instruments were the Unit 1 pressurizer pressure instrument (1PT-0456) and the Unit 1 auxiliary feedwater flow to loop 1 steam generator (1FT-5152). Because these transmitters were installed in EQ required applications, the licensee declared these transmitters inoperable until they were replaced. Inspectors concluded that the extent-of-condition investigation was not timely in that over fourteen months elapsed between the time that the licensee became aware of the potential problem with the transmitter installation and the time that all the transmitters were inspected and corrected.

14Analysis. The finding is of more than minor significance because it affects theequipment availability and reliability attribute of the Mitigating Systems cornerstone objective in that the damaged seals reduced the reliability of safety-related systems.

The NRC Region II Senior Reactor Analyst (SRA) determined that the Phase 2 significance evaluation process does not properly address this finding. Therefore, a Phase 3 significance determination evaluation was performed. The dominant accident sequence involved a Medium Break Loss of Coolant Accident followed by the failure of three channels of the Engineered Safety Features Actuation System, one due to a failed EQ seal and the other two via random failure. The Phase 3 results were that the finding was of very low safety significance (Green) since only one pressurizer pressure transmitter was affected.Enforcement. 10 CFR 50, Appendix B, Criterion XVI requires in part that conditionsadverse to quality, such as equipment deficiencies, be promptly identified and corrected.

Contrary to the above, the licensee did not promptly identify the complete population of transmitters affected by a known deficiency. Specifically, two safety-related transmitters (1-PT-0456 and 1-FT-5152) were found to be inoperable with potentially damaged environmental seals more than fourteen months after the installation deficiency was identified. Because the finding is of very low safety significance and has been entered in the licensee corrective action program as CR 2006109187, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000424/2006004-01, Failure to Promptly Identify Instruments with Environmental Qualification Deficiencies. 4OA3Event Followupa. Inspection ScopeUnit 2 Forced Shutdown. On August 27, 2006, the Unit 2 reactor automatically trippedfrom 100% RTP due to tripping of the loop 4 RCP. The inspectors reviewed the licensee's event review report and associated CR 2006109233 which included the corrective action plan. The inspectors also interviewed responsible operations and maintenance department personnel. The licensee was also conducting a root cause analysis that had not been completed at the time of this report. During the licensee's event investigation, they confirmed that the initiating event was the unexpected loss of the loop 4 RCP.b.FindingsIntroduction. A Green self-revealing finding was identified for inadequate workinstructions and poor work practices associated with the installation of a surge arrestor design change on the Unit 2 loop 4 RCP. This condition resulted in short circuiting in the surge arrestor cable which resulted in a trip of the loop 4 RCP and subsequent reactor trip.Description. On October 14, 2005, surge arrestors were installed on the loop 4 RCP aspart of design change package (DCP) 98-VAN0064 to replace the surge capacitors due to failures that had occurred on other large frame pump motors. The DCP stated that a shielded, stranding class B, 15kV surge arrestor cable was appropriate for this 15application. Contrary to the DCP, a shielded, stranding class B, 5kV cable was installed. The workers performing the cable installation did not question the differences between the cable being installed and the cable identified in the DCP work instructions. This was a missed opportunity to identify the error in cable size.The licensee determined that the work instructions in the DCP were inadequate whichresulted in the installation of an incorrect type and size cable. The cable in the DCP should have been an unshielded, stranding class H (or greater), 15kV cable. The licensee also determined that the surge arrestor cable was improperly installed in the RCP motor termination box. Cable shielding was discovered in contact with termination lugs and a current transformer wire was found in contact with the surge arrestor cable.

Because of the improper installation, conditions were created that resulted in an electrical short circuit and subsequent trip of the loop 4 RCP.Analysis. The inspectors determined that the cause of this finding was related to thework practices aspect of the human performance cross-cutting area because the personnel work practices did not support human performance to prevent errors in material acquisition or to prevent the failure to comply with the DCP. This finding is greater than minor because it affected the human performance and procedure quality attributes of the Initiating Event Cornerstone in that the installed loop 4 surge arrestor cable was incorrect in type and size and was incorrectly installed. The finding was determined to be of very low safety significance (Green) because it did not increase the likelihood that mitigation equipment or functions would not be available.Enforcement. The inspectors determined that the finding did not represent a violation ofregulatory requirements because it only involved non-safety related plant equipment.

This finding will be tracked as FIN 05000425/2006004-02, Poor Workmanship and Inadequate Work Instructions for Maintenance on the Unit 2 Loop 4 Reactor Coolant Pump Resulted in a Reactor Trip.4OA6Meetings, Including ExitOn October 6, 2006, the resident inspectors presented the inspection results to Mr. T.Tynan and other members of his staff, who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

R. Brown, Training and Emergency Preparedness Manager

C. Buck, Chemistry Manager

R. Dedrickson, Assistant General Manager - Operations

K. Dyar, Security Manager

I. Kochery, Health Physics Manager

J. Robinson, Operations Manager

S. Swanson, Engineering Support Manager

T. Tynan, Nuclear Plant General Manager

J. Williams, Assistant General Manager - Plant Support

NRC personnel

S. Shaeffer, Chief, Region II Reactor Project Branch 2

LIST OF ITEMS

OPENED AND CLOSEDOpened and

Closed

05000424/2006004-01NCVFailure to Promptly Identify Instruments withEnvironmental Qualification Deficiencies (Section

4OA2)05000425/2006004-02FINPoor Workmanship and Inadequate WorkInstructions for Maintenance on the Unit 2 Loop 4

Reactor Coolant Pump Resulted in a Reactor Trip

(Section 4OA3)

Section 1R04: Equipment AlignmentProcedures11301-1,

CBCR Normal HVAC and Emergency Filtration System Alignment54054-1, Control Room Emergency Filtration System Performance Test