IR 05000390/2007004

IR 05000390-07-004, 05000391-07-004, on 07/01/2007 - 09/30/2007; Watts Bar, Units 1 & 2; Maintenance Effectiveness and Problem Identification and Resolution

ML073020588
Person / Time
Site:	Watts Bar
Issue date:	10/29/2007
From:	Monk R Reactor Projects Region 2 Branch 6
To:	Campbell W Tennessee Valley Authority
References
IR-07-004
Download: ML073020588 (21)

Text

October 29, 2007Tennessee Valley AuthorityATTN:Mr. William R. Campbell, Jr.Chief Nuclear Officer and Executive Vice President6A Lookout Place1101 Market StreetChattanooga, TN 37402-2801SUBJECT: WATTS BAR NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT05000390/2007004 AND 05000391/2007004

Dear Mr. Campbell:

On September 30, 2007, the United States Nuclear Regulatory Commission (NRC) completedan inspection at your Watts Bar Nuclear Plant, Units 1 and 2. The enclosed integratedinspection report documents the inspection results which were discussed on October 5, 2007,with Mr. M. Lorek 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 interviewedpersonnel. This report documents two NRC-identified findings of very low safety significance (Green) whichwere determined to involve violations of NRC requirements. However, because of their very lowsafety significance and because they are entered into your corrective action program, the NRCis treating these findings as non-cited violations (NCVs) consistent with Section VI.A of the NRCEnforcement Policy. If you contest any NCV in this report, you should provide a response within30 days of the date of this inspection report, with the basis for your denial, to the NuclearRegulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, UnitedStates Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC ResidentInspector at the Watts Bar facility.

TVA2In accordance with 10 Code of Federal Regulations (CFR) 2.390 of the NRC's "Rules ofPractice," a copy of this letter, its enclosure, and your response (if any) will be availableelectronically for public inspection in the NRC Public Document Room or from the PubliclyAvailable Records (PARS) component of NRC's document system (ADAMS). ADAMS isaccessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the PublicElectronic Reading Room).

Sincerely,

/RA/Robert L. Monk, Acting Chief Reactor Projects Branch 6Division of Reactor ProjectsDocket Nos.:50-390, 50-391License No.:NPF-90 and Construction Permit No.:CPPR-92

Enclosure:

NRC Inspection Report 05000390/2007004, 05000391/2007004 w/Attachment: Supplemental Information

REGION IIDocket Nos:50-390, 50-391License Nos:NPF-90 and Construction Permit CPPR-92Report Nos:05000390/2007004, 05000391/2007004Licensee:Tennessee Valley Authority (TVA)Facility:Watts Bar Nucl ear Plant, Units 1 and 2Location:Spring City, TN 37381Dates:July 1, 2007 - September 30, 2007Inspectors:R. Monk, Senior Resident InspectorM. Pribish, Resident InspectorJ. Baptist, Senior Project Engineer (Section 1R04.2, 1R07.1)A. Rogers, Reactor Inspector (Section 1R07.2)T. Nazario, Project Engineer (Section 1R06)Approved by:R. Monk, Acting Chief Reactor Projects Branch 6Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000390/2007-004, 05000391/2007-004; 07/01/2007 - 09/30/2007; Watts Bar, Units1 & 2; Maintenance Effectiveness and Problem Identification and Resolution.The report covered a three-month period of routine inspection by resident inspectors,project engineers and an announced inspection by a regional reactor inspector. TwoNRC-identified Green findings, which are non-cited violations (NCVs), were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red)using Inspection Manual Chapter (IMC) 0609, Significance Determination Process(SDP). The NRC's program for overseeing the safe operation of commercial nuclearpower reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4,dated December 2006.A.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and anassociated non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, CorrectiveAction, was identified. The licensee failed to correct, in a timely manner, aprocedural deficiency associated with the setup of HFA relays. As a result, the B-train safety injection pump (SIP) was inoperable in excess of the time limitsprescribed by the associated technical specification limiting condition for operation. The licensee has entered the issue into their corrective action program and revisedthe associated maintenance procedure.The finding is more than minor because it is associated with the equipmentperformance attribute of the Mitigating Systems cornerstone and adversely affects the cornerstone objective of ensuring the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable consequences. Thefinding was determined to be of very low safety significance because of the durationthat the B Train SIP was unavailable and the availability of the A Train SIP. Thefinding directly involved the cross-cutting area of Problem Identification andResolution under the appropriate and timely corrective actions aspect of theCorrective Action Program component; in that, prior to subsequent maintenance onsafety-related equipment, the licensee failed to revise a maintenance instruction thathad been previously determined to be inadequate (P.1(d)). (Section 1R12)

Green.

The inspectors identified a finding of very low safety significance and anassociated non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, CorrectiveAction, was identified. The licensee failed to identify incorrect as-found nozzle ringsettings on safety injection relief valves. The as-found settings were significantlyincorrect as to effect the proper reseat pressure for the relief valves. The licenseehas identified a long-standing condition of safety injection relief valves failing toreseat while the Safety Injection Pumps (SIPs) are running. Failure of the reliefvalves to reseat has required the licensee to reduce the assumed margin in the peakcladding temperature by 120° Fahrenheit. The licensee has entered the failure to 3Enclosureidentify nozzle ring configuration control into the corrective action program forresolution. The finding is more than minor because it is associated with the equipmentperformance attribute of the Mitigating Systems cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability ofsystems that respond to initiating events and, if left uncorrected, could have a moresignificant impact on core peak cladding temperature. The inspectors evaluated thisfinding using IMC 0609, Appendix A, and determined it to be of very low safetysignificance (Green). The finding directly involved the cross-cutting area of ProblemIdentification and Resolution under the implementation and institutionalizing ofOperating Experience aspect of the Operating Experience component; in that, thelicensee failed to properly implement and institutionalize operating experiencethrough changes to station procedures (P.2(b)).(Section 4OA2.3)

B.Licensee-Identified Violations

None.

Enclosure

REPORT DETAILS

Summary of Plant StatusUnit 1 operated at or near 100 percent power for the entire inspection period. Unit 2remained in a suspended construction status.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R04Equipment Alignment.1Partial Walkdowns

a. Inspection Scope

The inspectors performed a partial walkdown of the following three systems to verify theoperability of redundant or diverse trains and components when safety equipment wasinoperable. The inspectors attempted to identify any discrepancies that could impact thefunction of the system, and, therefore, potentially increase risk. The inspectors reviewedapplicable operating procedures, walked down control systems components, andverified that selected breakers, valves, and support equipment were in the correctposition to support system operation. The inspectors also verified that the licensee hadproperly identified and resolved equipment alignment problems that could causeinitiating events or impact the capability of mitigating system s or barrier s and enteredthem into the corrective action program. Documents reviewed are listed in theattachment.*Auxiliary air system during the "D" station air compre ssor component outage*"B" boric acid pump flowpath while the "A" boric acid pump was out of service formaintenance* A Train emergency gas treatment system (EGTS) during the B Train EGTScomponent outage

b. Findings

No findings of significance were identified..2Semiannual Complete System Walkdown

a. Inspection Scope

The inspectors conducted one detailed walkdown/review of the alignment and conditionof the standby diesel generator system to verify proper equipment alignment and toidentify any discrepancies that could impact the function of the system and increase risk. The inspectors utilized licensee procedures, as well as licensing and design documents,when verifying that the system alignment was correct. During the walkdown, theinspectors also verified, as appropriate, that:

(1) valves were correctly positioned and did 5Enclosurenot exhibit leakage that would impact the function(s) of any valve;

(2) electrical powerwas available as required;

(3) major portions of the system and components werecorrectly labeled, cooled, ventilated, etc.;

(4) hangers and supports were correctlyinstalled and functional;

(5) essential support systems we re operational;

(6) ancillaryequipment or debris did not interfere with system performance;

(7) tagging clearanceswere appropriate; and

(8) valves were locked as required by the licensee's locked valveprogram. Pending design and equipment issues were reviewed to determine if theidentified deficiencies significantly impacted the system's functions. Items included inthis review were the operator workaround list, the temporary modification list, systemhealth reports, and outstanding maintenance work requests/work orders (WOs). Inaddition, the inspectors reviewed the licensee's corrective action program (CAP) toensure that the licensee was identifying equipment alignment problems and that theywere properly addressed for resolution. Specific documents reviewed are listed in theattachment to this report.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted a tour of the twelve areas listed below to assess the materialcondition and operational status of fire protection features. The inspectors verified thatcombustibles and ignition sources, were controlled in accordance with the licensee'sadministrative procedures; fire detection and suppression equipment was available foruse; that passive fire barriers were maintained in good material condition; and thatcompensatory measures for out-of-service, degraded, or inoperable fire protectionequipment were implemented in accordance with the licensee's fire plan. Documentsreviewed are listed in the attachment. *Auxiliary instrument room*1A-A emergency diesel generator (EDG)*2A-A EDG*1B-B EDG*2B-B EDG*A Train emergency raw cooling water (ERCW) pump area*B Train ERCW pump area*A Train high pressure fire protection (HPFP) pump area*B Train HPFP pump area*A Train ERCW strainer area*B Train ERCW strainer area*ERCW traveling screen area

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures.1Internal Flooding

a. Inspection Scope

The inspectors reviewed internal flood protection measures for the intake pumpingstation (IPS). The inspectors walked down the IPS to observe material condition of itsflooding protection features such as doors, floor drains, sump level switches, and sumppumps. The IPS flood protection features were examined to verify that they wereinstalled and maintained consistent with plant design basis. The inspectors alsoreviewed selected problem evaluations reports (PERs) written during calendar year 2006through September 2007 with respect to flood-related items. In addition, the inspectorsreviewed the licensee's CAP to ensure that the licensee was identifying flood-relatedproblems and that they were properly addressed for resolution. Documents reviewedare listed in the attachment to this report.

b. Findings

No findings of significance were identified..2External Flooding

a. Inspection Scope

The inspectors reviewed licensee flood analysis documents to identify design featuresimportant to external flood protection and areas that can be affected by flooding; designflood levels; and protection features for areas containing safety-related equipment, suchas level switches and sumps. The inspectors also walked down the yard drainagesystem to verify that catch basins were free of blockage and could function as designed. The inspectors interviewed cognizant licensee personnel about site flood protectionmeasures and plant drainage plans. The inspectors also reviewed the licensee's CAPfor documents with respect to flood-related items identified in PERs written duringcalendar year 2006 through September 2007. Documents reviewed are listed in theattachment.

b. Findings

No findings of significance were identified.

7Enclosure1R07Heat Sink Performance.1Annual Review

a. Inspection Scope

The inspectors reviewed the licensee's program for maintenance and testing of tworisk-important heat exchangers in the residual heat removal (RHR) system. Theinspectors reviewed two heat exchangers because of the post-accident risk significanceof the RHR system. Specifically, the review included the program for testing andanalysis of the 1A and 1B RHR heat exchangers. The inspectors observed the physicalcondition of the heat exchangers and performed a review of the data obtained fromperiodic Eddy Current examination. This data was compared with baseline data toensure that the licensee was adequately detecting degradation prior to loss of heatremoval capabilities below des ign requirement s, that the inspection results wereappropriately categorized against pre-established engineering acceptance criteriaincluding the impact of tubes plugged on the heat exchanger performance, and that thelicensee had developed adequate acceptance criteria for bio-fouling controls. Specificdocuments reviewed are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

.2 Biennial Review

a. Inspection Scope

The inspectors reviewed inspection records, test results, maintenance WOs, and otherdocumentation to ensure heat exchanger deficiencies that could mask or degradeperformance were identified and corrected. Risk-significant heat exchangers reviewedincluded the component cooling water heat exchangers along with the EDG intercooler,jacket water, and lube oil heat exchangers. The inspectors reviewed heat exchanger inspection and cleaning completed procedures,inspection frequency, and tube plugging maps. In addition, the inspectors reviewedEddy Current test reports for the EDG intercooler heat exchanger. The inspectorsreviewed to determine that:

(1) selected heat exchanger test methodology wasconsistent with NRC Generic Letter 89-13, Service Water System Problems AffectingSafety-Related Equipment, commitments;

(2) test conditions were appropriatelyconsidered;

(3) test or inspection criteria were appropriate and met;

(4) test frequencywas appropriate;

(5) as-found results were appropriately dispositioned such that the finalcondition was acceptable; and

(6) test results considered test instrument inaccuraciesand differences.

The inspectors also reviewed the general health of the ERCW system via review ofdesign basis documents, system health reports, and discussions with the ERCW system 8Enclosureengineer. These documents were reviewed to verify the design basis was beingmaintained and to verify adequate ERCW system performance under current preventivemaintenance, inspections, and frequencies. The inspectors also walked down theERCW intake structure and observed a chemical treatment to the ERCW backup to theauxiliary feedwater (AFW) system.PERs were reviewed for potential common-cause problems and problems which couldaffect system performance, to confirm that the licensee was entering problems into theCAP and initiating appropriate corrective actions. In addition, the inspectors conducteda walkdown of all selected heat exchangers and major components for the ERCWsystem to assess general material condition and to identify any degraded conditions ofselected components. Specific documents reviewed are listed in the attachment to thisreport.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

On July 31, 2007, the inspectors observed the as-found simulator evaluations for Group1 per 3-OT-SRT-E2-3, Main Steam Line Break Design Basis, Revision 2. The rapidreactor coolant system (RCS) cooldown and safety injection initiation led to a Notificationof Unusual Event emergency action level classification.The inspectors specifically evaluated the following attributes related to the operatingcrew performance:*Clarity and formality of communication*Ability to take timely action to safely control the unit*Prioritization, interpretation, and verification of alarms*Correct use and implementation of abnormal operating instructions andemergency operating instructions*Timely and appropriate emergency action level declarations per emergency planimplementing procedures*Control board operation and manipulation, including high-risk operator actions*Command and control provided by the unit supervisor and shift managerThe inspectors also attended the post-evolution critique to assess the effectiveness ofthe licensee evaluators and to verify that licensee-identified issues were comparable toissues identified by the inspector.

b. Findings

No findings of significance were identified.

9Enclosure1R12Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the two samples listed below for items such as:

(1) appropriatework practices;

(2) identifying and addressing common cause failures;

(3) scoping inaccordance with 10 CFR 50.65(b) of the maintenance rule (MR);

(4) characterizingreliability issues for performance;

(5) trending key parameters for conditi on monitoring;(6) charging unavailability for performance;

(7) classification and reclassification inaccordance with 10 CFR 50.65(a)(1) or (a)(2); and

(8) appropriateness of performancecriteria for structures, systems, and components (SSCs)/functions classified as (a)(2)and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified as (a)(1). In addition, the inspectors specifically reviewed events whereineffective equipment maintenance has resulted in invalid automatic actuations ofEngineered Safeguards Systems affecting the operating units. Documents reviewed arelisted in the Attachment. Items reviewed included the following:*PER 126359, Repetitive Failures of Shutdown Board Room Chiller TemperatureControl Valves*PER 125404, 1B Safety Injection Pump Failed to Start

b. Findings

Introduction:

The inspectors identified a Green NCV for the failure to comply with 10CFR 50, Appendix B, Criterion XVI, Corrective Action, which resulted in the failure of the1B SIP to start on demand.Description: On September 22, 2006, the 1B-B 6.9 kV shutdown board normal feederbreaker failed its post-maintenance test (PMT) due to the 30RX latching relay in thebreaker's control circuit. The relay had just been replaced due to an ongoing effort toreplace aging relays. Prior to replacing the relay, licensee procedure MaintenanceInstruction (MI) 57.029, HFA Relay Maintenance, was used to test the relay's latchingmechanism, as well as, to make any necessary adjustments to the relay's contact gapand wipe. Troubleshooting revealed that the relay's normally open contact 1-2 was notclosing when the relay was electrically operated to the latched position. The licenseeentered the condition into their CAP as PER 111386, and determined that MI-57.029should have identified the problem prior to installation. The licensee determined arevision to MI-57.029 was needed so the problem would not recur. The plannedprocedure revision would add an electrical bench test of the relay with closed contactresistance measurements to verify contact continuity with the relay in the latchedposition. The original due date for the procedure revision was June 4, 2007, but waslater extended to August 6, 2007.On May 26, 2007, when called upon to fill a cold leg accumulator, the 1B SIP failed tostart because its associated 6.9 kV supply breaker failed to shut. Troubleshootingrevealed that the breaker failed to shut due to the 30RX latching relay in the breaker'scontrol circuit. The relay's normally open contact 9-10 had intermittent electrical 10Enclosurecontinuity when the relay was in the latched position. The inspectors performed a workhistory search which revealed that the relay had been replaced as part of a plannedcomponent outage on the 1B SIP on March 6, 2007. Prior to installation, the 1B SIP30RX relay was set up and tested using the same revision of MI-57.029 that wasassociated with the September 2006 PMT failure. In addition, the inspector's review ofthe completed MI-57.029 paperwork for the 1B SIP revealed that a procedural step toclean the relay contacts with a flexible burnishing tool had been inappropriately marked"N/A." A review of the 1B SIP operating history revealed that between the relayreplacement on March 3, 2007, and the failure on May 26, 2007, the pump did have onesuccessful start on April 27, 2007.Through discussions with the licensee, the inspectors determined that the September2006 and May 2007 relay failures were not identical. The September 2006 failure wasdue to latch mechanism interference. The May 2007 failure was due to poor contactelectrical continuity. The inspectors also determined that the prompt implementation ofthe planned procedure revision to MI-57.029 could have prevented the May 2007 failuresince the revision would direct verification of proper contact continuity with the relay inthe latched state.Analysis: The finding is more than minor because it is associated with the equipmentperformance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems thatrespond to initiating events. The inspectors evaluated this finding using IMC 0609,Appendix A, and determined that a Phase 2 of the significance determination process(SDP) was required since the finding represented an actual loss of safety function of asingle train for greater than its technical specification allowed outage time. The resultsof the Phase 2 SDP required further evaluation by a regional Senior Reactor Analyst(SRA). A Phase 3 SDP risk analysis was performed for the non-recoverable loss of the1B safety injection pump for an exposure period of 14.5 days using the NRC's risk modelfor Watts Bar. The evaluation determined that the risk increase was Green, less than1E-6 /year. The factors which influenced the risk were the short exposure time and theavailability of additional mitigating equipment. The finding directly involved thecross-cutting area of Problem Identification and Resolution under the appropriate andtimely corrective actions aspect of the Corrective Action Program component; in that,prior to subsequent maintenance on safety-related equipment, the licensee failed torevise a maintenance instruction that had been previously determined to be inadequate(P.1(d)).Enforcement: 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, states, in part,that measures shall be established to assure that conditions adverse to quality, such asfailures, malfunctions, deficiencies, defective material and equipment, andnon-conformances are promptly identified and corrected. Contrary to the above, the 1BSIP 30RX latching relay was replaced on March 6, 2007, using a maintenanceinstruction that had previously been determined to be inadequate. The proceduralcondition was not corrected until July 27, 2007. Because this finding is of very lowsafety significance and because it was entered into the licensee's CAP as PERs111368, 125404 and 131704, this violation is being treated as an NCV, consistent with 11EnclosureSection VI.A of the NRC Enforcement Policy: NCV 05000390/2007004-01, Failure toPromptly Correct an Identified Procedural Deficiency Prior to Subsequent Maintenance.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

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

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

(2) the management of risk;

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

(4) that maintenance risk assessments and emergent work problems wereadequately identified and resolved. The inspectors verified that the licensee wascomplying with the requirements of 10 CFR 50.65 (a)(4); SPP-7.0, Work Control andOutage Management; SPP-7.1, Work Control Process; and TI-124, Equipment to PlantRisk Matrix. *Emergent work on the failed refueling water storage tank (RWST) transmitter,Channel I*Emergent work on the B Train electric boardroom chiller with B Train main control room chiller degraded and functional testing of B Train solid stateprotection system*Maintenance risk associated with the B Train shutdown boardroom chillercomponent outage*Emergent work on B Train rod position indication system with the redundant trainout of service

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed four operability evaluations affecting risk-signific ant mitigatingsystems, listed below, to assess, as appropriate:

(1) the technical adequacy of theevaluations;

(2) whether continued system operability was warranted;

(3) whether otherexisting degraded conditions were considered as compensating measures;

(4) whetherthe compensatory measures, if involved, were in place, would work as intended, andwere appropriately controlled;

(5) where continued operability was consideredunjustified, the impact on TS Limiting Conditions for Operation (LCOs) and the risksignificance in accordance with the SDP. The inspectors verified that the operabilityevaluations were performed in accordance with SPP-3.1, Corrective Action Program.

12Enclosure*PER 124435, Component cooling system heat exchange overall heat transfercoefficient*PER 127222, B-A ERCW pump motor winding high temperature alarm*PER 100385, One of four 1B-B DG inlet air dampers failed to open*PER 125669, Safety injection pump discharge relief valve(s) lifting and remainingopen during pump operation

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed five post-maintenance test (PMT) procedures and/or testactivities, as appropriate, for selected risk-significant mitigating systems to assesswhether:

(1) the effect of testing on the plant had been adequately addressed by controlroom and/or engineering personnel;

(2) testing was adequate for the maintenanceperformed;

(3) acceptance criteria were clear and adequately demonstrated operationalreadiness consistent with design and licensing basis documents;

(4) test instrumentationhad current calibrations, range, and accuracy consistent with the application;

(5) testswere performed as written with applicable prerequisites satisfied;

(6) jumpers installed orleads lifted were properly controlled;

(7) test equipment was removed following testing;and

(8) equipment was returned to the status required to perform its safety function. Theinspectors verified that these activities were performed in accordance with SPP-8.0,Testing Programs; SPP-6.3, Pre-/Post-Maintenance Testing; and SPP-7.1, Work ControlProcess. *WO 07-815133-000, A Train SDBR chiller temperature control valve will notcontrol in auto*WO 07-818889-000, RWST level, Channel I transmitter replacement*WO 07-817168-000, CCS and AFW pump space cooler 1B ERCW supply valvetroubleshoot and repair*WOs 06-821498-000 and 06-821507-000, Containment purge isolation valvequick exhausters 1-EXH-030-0057 and 1-EXH-030-001*WO 07-816670-001, Install tornado bypass hand switch for the 1A-A EDGexhaust fan 2A

b. Findings

No findings of significance were identified.

13Enclosure1R22Surveillance Testing

a. Inspection Scope

The inspectors witnessed six surveillance tests and/or reviewed test data of selectedrisk-significant structures, systems or components (SSCs), listed below, to assess, asappropriate, whether:

(1) the SSCs met the requirements of the TS;

(2) the UFSAR; (3)SPP-8.0, Testi ng Programs;

(4) SPP-8.2, Surveillance Test Program; and

(5) SPP-9.1,ASME Section XI. The inspectors also determined whether the testing effectivelydemonstrated that the SSCs were operationally ready and capable of performing theirintended safety functions. *WO 07-813472-000, 1-SI-63-901A, Safety Injection Pump 1A-A QuarterlyPerformance Test**WO 06-820597-000, 1-SI-90-14, 18-month Channel Calibration Test ofContainment Building Lower Compartment Particulate Rad Monitor Loop 1-LPR-90-106A***WO 07-812992-000, 1-SI-99-10-A, 31-day Functional Test of SSPS A Train andReactor Trip Breaker A*WO 07-813096-000, 0-SI-236-43, 125 Vdc Vital Battery III 18-month Service Testand 125 Vdc Vital Battery Charger III Test*WO 07-813652-000, 1-SI-63-901B, Safety Injection Pump 1B-B QuarterlyPerformance Test**WO 813595-000, 1-SI-3-902, Turbine-driven AFW Pump Quarterly PerformanceTest**This procedure included inservice testing requirements.**This procedure included reactor coolant system leakage detection testing requirements.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES 4OA1Performance Indicator (PI) Verifications

a. Inspection Scope

Licensee records were reviewed to determine whether the submitted PI statistics werecalculated in accordance with the guidance contained in Nuclear Energy Institute 99-02,Regulatory Assessment Performance Indicator Guideline, Revision 4.

14EnclosureMitigating Systems CornerstoneThe inspectors verified the accuracy of the data for the five mitigating systemperformance indicators (MSPIs), listed below, which was reported to the NRC. Theinspectors reviewed data from July 1, 2006, through June 30, 2007. The inspectorsreviewed the licensee's MSPI basis document, main control room operator logs,corrective action program documents, maintenance rule records, maintenance work orders and operability deter minations. *MSPI - Emergency AC Power System*MSPI - High Pressure Injection System*MSPI - Heat Removal System*MSPI - Residual Heat Removal System*MSPI - Cooling Water Systems

b. Findings

No findings of significance were identified.4OA2Identification and Resolution of Problems.1Review of Items Entered into the Corrective Action ProgramAs required by Inspection Procedure 71152, Identification and Resolution of Problems,and in order to help identify repetitive equipment failures or specific human performanceissues for follow-up, the inspectors performed a daily screening of items entered into thelicensee's corrective action program (CAP). This review was accomplished by reviewingdaily PER summary reports and attending daily PER review meetings..2Annual Sample Review of Operator Workarounds

a. Inspection Scope

The inspectors reviewed the operator workaround program to verify that workaroundswere identified at an appropriate threshold, were entered into the corrective actionprogram, and that corrective actions were proposed or implemented. Specifically, theinspectors reviewed the licensee's workaround list and repair schedules, conductedtours and interviewed operators about required compensatory actions. Additionally, theinspectors looked for undocumented workarounds, reviewed appropriate system healthdocuments, and reviewed PERs related to items on the workaround list.

b. Findings and Observations

No findings of significance were identified.

15Enclosure.3Annual Sample: Failure of Safety Injection Relief Valves to Reseat After Actuation

a. Inspection Scope

The inspectors reviewed a longstanding equipment issue associated with the lifting ofrelief valve(s) in the safety injection system during SIP operation. Several related PERs,corrective action documents, and causal analyses were reviewed in detail to ensure thatthe full extent of the described issues were identified, thorough evaluations wereperformed, and appropriate corrective actions were specified, prioritized, and completed. The inspectors also evaluated licensee actions against the requirements of thelicensee's corrective action program as specified in SPP-3.1, Corrective Action Program,and 10 CFR 50, Appendix B .BackgroundPER 85969 was written on July 17, 2005, in response to one or more of the threedischarge relief valves lifting and not reseating when 1A SIP was started for a routinesurveillance test. The relief valve(s) continued to relieve until the 1A SIP was secured. Flow from the relief valves, which are outside containment, is piped to the pressure relieftank (PRT) inside containment. On this particular event, the flowrate was determined tobe approximately 23 gpm based on a change in PRT level. The root cause analysis(Kepner-Tregoe methodology) determined that the most likely cause was relief valvesetpoint drift. It is noteworthy that setpoint drift, due to overtravel of the valve onpressure spikes, had been determined to be the apparent cause in a previous PER13915, dated July 22, 2001, resulting in a 30 gpm leakrate to the PRT. The principlecorrective action for that PER was to replace the stainless steel valve springs withinconel valve springs and a travel stop limit. In September 2006, the valves associated with PER 85959 were removed and tested todetermine their lift pressure. The as-found testing of the removed relief valves did notindicate a drift problem. Following the determination that setpoint drift was not the rootcause, gas voids in the system were elevated to the most likely cause. Correctiveactions associated with this cause include ultrasonic measurements to detect voids inthe system and an engineering study by MPR Associates, Inc. The engineering studydetermined that 1.2 to 3.0 cubic feet of gas in the system could cause a pressuretransient on safety injection pump starts that would exceed normal relief valve setpressure. Ultrasonic measurements, performed by the licensee, have found 0.32 cubicfeet of gas in the system and the licensee has speculated that more could exist. Basedon the belief that there is sufficient gas in the system to cause the reliefs to lift, a designchange is planned for the upcoming outage in the Spring of 2008 to install additionalsystem vents. b. Assessment and ObservationsCorrective actions to this point have focused on relief valve setpoint. Based oninterviews with plant personnel, inspectors have found no efforts focused on thereason(s) that the reliefs frequently fail to reseat. Significant industry operating 16Enclosureexperience and generic communications from both the NRC (IN 92-64) and the industryexist on the importance of these settings. An extensive review of maintenance WOsrevealed that, on at least five occasions, nozzle ring as-found settings were incorrect. Two were insignificantly incorrect such that the reseating would not likely have beenaffected. However, three were significantly incorrect to the point of affecting reseatpressure. No PERs could be found documenting this condition. The licensee has nowwritten PER 130590 to investigate configuration control issues related to nozzle ringsettings for these valves. Also related to relief valve failure to reseat with the SIPs running is that the flow thatshould go to the reactor core is being bypassed to the PRT. The licensee hasrecognized this problem and has, by analysis, determined that a bounding flowrate of 30gpm would penalize peak cladding temperature by 120°F. The licensee madenotification to the NRC pursuant to 10 CFR 50.46. The assumption is that one valvewould not leak more than what has been observed. However, the licensee has neverdetermined specifically which valve or valves fail to reseat. Neither does the licenseehave any trending data on pressure transients due to pump starts that would allow anycorrelation with measurements of gas voids taken by ultrasonic measurements. Hence,there is some degree of speculation that gas voids are the root cause of the spuriousrelief valve lifts.It is apparent in the review of corrective action efforts dating back to 1995 that thelicensee has expended a great deal of effort resolving this issue. However, it is alsoapparent that these efforts have been somewhat sporadic and lacked a clear plan thatsystematically collected, trended, and analyzed available data to resolve the issue.Documents reviewed are listed in the attachment.

c. Findings

Introduction:

The inspectors identified a Green NCV of 10 CFR 50, Appendix B, CriterionXVI, Corrective Action, regarding the failure of safety injection relief valves to reseat asrequired.Discussion: Review of the performance of the safety injection relief valves indicates a long-standing issue of failing to reseat after safety injection pump starts. This issuedates back to 1995 and has continued to intermittently occur to the present time. Anumber of corrective actions have been performed by the licensee without success. Themaintenance history of these valves indicates that, on at least three occasions, theas-found settings of the relief valve nozzle rings were significantly out of tolerance. These settings are critical to the proper reseating of the relief valve as evidenced bynumerous industry events related to improper nozzle ring settings. The licensee hasdocumented the data in the appropriate maintenance procedures but failed to identifythe out-of-tolerance condition as a condition adverse to quality. Hence, no actions havebeen taken to determine and correct configuration control of these settings.Analysis: The finding is more than minor because it is associated with the equipmentperformance attribute of the Mitigating Systems cornerstone and adversely affects the 17Enclosure cornerstone objective to ensure the availability, reliability, and capability of systems thatrespond to initiating events and, if left uncorrected, could have a more significant impacton core peak cladding temperature. The inspectors evaluated this finding using IMC0609, Appendix A, and determined it to be of very low safety significance (Green). Thefinding directly involved the cross-cutting area of Problem Identification and Resolutionunder the implementation and institutionalizing of Operating Experience aspect of theOperating Experience component; in that, the licensee failed to properly implement andinstitutionalize operating experience through changes to station procedures (P.2(b)).Enforcement: 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, states, in part,that measures shall be established to assure that conditions adverse to quality, such asfailures, malfunctions, deficiencies, defective material and equipment andnon-conformances are promptly identified and corrected. Contrary to the above, thelicensee failed to enter a number of occurrences into the CAP where configurationcontrol of the nozzle rings was not maintained. Because this finding is of very low safetysignificance and because it was entered into the licensee's CAP as PER 130590, thisviolation is being treated as an NCV, consistent with Section VI.A of the NRCEnforcement Policy: NCV 05000390/2007004-02, Failure to Promptly Correct theFailure of Safety Injection Relief Valves to Reseat after Actuation.4OA6Meetings, including ExitThe inspectors presented the inspection results to Mr. M. Lorek and other members oflicensee management at the conclusion of the inspection on October 5, 2007. Theinspectors asked the licensee whether any materials examined during the inspectionshould be considered proprietary. No proprietary information was identified.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

J. Hinman, Manager of Projects

A. Hinson, Site Engineering Manager

M. Lorek, Plant Manager

K. Lovell, Maintenance and Modifications Manager

M. McFadden, Site Nuclear Assurance Manager

P. Sawyer, Radiation Protection Manager

A. Scales, Operations Manager

M. Skaggs, Site Vice President

J. Smith, Licensing and Industry Affairs Manager

S. Smith, Operations Superintendent

W. Thompson, Training Manager

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

050000390/2007004-01NCVFailure to Promptly Correct an Identified ProceduralDeficiency Prior to Subsequent Maintenance(Section 1R12)05000390/2007004-02NCVFailure to Promptly Correct the Failure of SafetyInjection Relief Valves to Reseat after Actuation(Section 4OA2.3)

Closed

None

Discussed

None

Attachment

Section 1R04: Equipment Alignment*TVAN System Description Document N3-82-4002, Standby Diesel Generator System*0-SI-82-17-A, 184 Day Fast Start and Load Test

DG 1A-A Rev. 13 dated 8/28/07*0-SI-82-17-A, 184 Day Fast Start and Load Test DG 1A-A Rev. 12 dated 4/09/07*TVA Drawing Series 1-47W839*TVA Drawing Series 1-47W880*TVA Drawing Series 1-47W881*DCN 52233, EDG exhaust fan bypass switch*WO 07-816670-000*PER

120005, Diesel building ventilation during tornado warning*PER

124355, Diesel generator 1B heat exchanger thermal performance testing*PER

127383, DG transmitter gasket*SOI-62.05, Boric Acid Batching, Transfer, and Storage, Rev 38*TVA Drawing 47W610-62-6*TVA Drawing 47W610-65-1

Section 1R05: Fire Protection*SPP-10.0, Control of Fire Protection Impairments*SPP-10.10, Control of Transient Combustibles*SPP-10.11, Control of Ignition Sources (Hot Work)Section 1R06: Flood Protection Measures*Updated Final Safety Analysis Report (UFSAR) Sections 2.4.14, 3.4*Abnormal Operating Instruction (AOI)-7.01, Maximum Probable Flood, Revision 16*Individual Plant Examination, Watts Bar Internal Flood Analysis Section E.1.5.2.1, IntakePumping Station, Revision 0*Individual Plant Examination for External Events - High Winds, Floods, and otherExternal Events, Attachment 5 Section 5.6*WB-DC-20-28, Intake Pumping Station Watertight Doors at Elevation 722.0, Revision 4*WB-DC-20-31, Plant Drainage, Revision 3*WB-DC-40-64, Design Basis Events Design Criteria, Section 4.4-Design Basis Flood,Revision 11*WB-DC-20-19, Intake Pumping Station Concrete Structure, Intake Channel, andRetaining Walls, Revision 11*Maintenance Instruction (MI)-17.033, Flood Preparation-Install Blind Flanges on

HPFPDischarge Relief Valves, Revision 6*WB-DC-40-29, Flood Protection Provisions, Section 4.11 and Table 4.1-2, Revision 9*Technical Instruction (TI)-50.021, Intake Pumping Station Strainer Room A Sump PumpA Performance Test, Revision 3*Technical Instruction (TI)-50.021, Intake Pumping Station Strainer Room A Sump PumpB Performance Test, Revision 4*Problem Evaluation Report (PER)

126535, B Train High Pressure Fire Pump Room atthe Intake Pumping Station was found flooded