IR 05000382/2006008

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May 8, 2006

Joseph E. VenableVice President Operations Waterford Steam Electric Station Unit 3Entergy Operations, Inc.17265 River RoadKillona, Louisiana 70066-0751

SUBJECT: WATERFORD STEAM ELECTRIC STATION, UNIT 3 - NRC PROBLEMIDENTIFICATION AND RESOLUTION INSPECTION REPORT05000382/2006008

Dear Mr. Venable:

On March 24, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed a teaminspection at your Waterford Steam Electric Station, Unit 3. The enclosed report documentsthe inspection findings, which were discussed with you and other members of your staff duringan exit meeting on March 24, 2006.This inspection was an examination of activities conducted under your license as they relate tothe identification and resolution of problems, compliance with the Commission's rules andregulations and the conditions of your operating license. The team reviewed 237 conditionreports, apparent cause and root cause analyses, as well as supporting documents. Inaddition, the team reviewed crosscutting aspects of NRC- and licensee-identified findings andinterviewed personnel regarding the safety conscious work environment.On the basis of the sample selected for review, there were no findings of significance identifiedduring this inspection. The team concluded that, in general, problems were properly identified,evaluated, and corrected. The team concluded that a positive safety-conscious workenvironment existed at your Waterford Steam Electric Station, Unit 3. Several examples ofminor problems were identified, including conditions adverse to quality that were not identifiedand entered into your corrective action program.

Entergy Operations, Inc.-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure, and your response (if any) will be available electronically for public inspection in theNRC Public Document Room or from the Publicly Available Records (PARS) component ofNRC's document system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Linda Joy Smith, ChiefPlant Engineering BranchDivision of Reactor SafetyDocket: 50-382License: NPF-38

Enclosure:

NRC Inspection Report 05000382/2006008 ATTACHMENT A: Supplemental Information ATTACHMENT B: Waterford 3 Pressurizer Surge Line Temperature Change Rate ATTACHMENT C: White Paper on Effect of Diesel Sump Pump Inoperability on UltimateHeat Sink Operabilitycc w/enclosure:Senior Vice President and Chief Operating OfficerEntergy Operations, Inc.P.O. Box 31995Jackson, MS 39286-1995Vice President, Operations SupportEntergy Operations, Inc.P.O. Box 31995Jackson, MS 39286-1995Wise, Carter, Child & CarawayP.O. Box 651Jackson, MS 39205General Manager, Plant OperationsWaterford 3 SESEntergy Operations, Inc.17265 River RoadKillona, LA 70066-0751 Entergy Operations, Inc.-3-Manager - Licensing ManagerWaterford 3 SESEntergy Operations, Inc.17265 River RoadKillona, LA 70066-0751ChairmanLouisiana Public Service CommissionP.O. Box 91154Baton Rouge, LA 70821-9154Director, Nuclear Safety & Regulatory AffairsWaterford 3 SESEntergy Operations, Inc.17265 River RoadKillona, LA 70066-0751Michael E. Henry, State Liaison OfficerDepartment of Environmental QualityPermits DivisionP.O. Box 4313Baton Rouge, LA 70821-4313Parish President St. Charles ParishP.O. Box 302Hahnville, LA 70057Winston & Strawn LLP1700 K Street, N.W.Washington, DC 20006-3817 Entergy Operations, Inc.-4-Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Senior Resident Inspector (MCH)Branch Chief, DRP/E (DNG)Senior Project Engineer, DRP/E (VGG)Team Leader, DRP/TSS (RLN1)RITS Coordinator (KEG)DRS STA (DAP)S. O'Connor, OEDO RIV Coordinator (SCO)ROPreportsWAT Site Secretary (AHY)ADAMS: / YesG No Initials: __ljs____ / Publicly Available G Non-Publicly AvailableG Sensitive/ Non-SensitiveDOCUMENT: R\_WAT\2006\WT2006-08RP-ELC.wpdRI:DRP/EPE:DRP/BPE:DRP/ASOE:DRS/OERI:DRP/EELCrowe/lmbDHOverlandMABrownMEMurphyGFLarkin/RA/ T/RA//RA//RA//RA/ T5/5/065/5/065/5/065/5/065/5/06BC:DRP/ESRI:DRS/EB2BC:DRS/EB2DNGravesD. ProulxLJSmith/RA//RA//RA/5/8/065/5/065/8/06OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax Enclosure-1-ENCLOSUREU.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket:50-382 License:NPF-38Report:05000382/2006008Licensee:Entergy Operations, Inc.Facility:Waterford Steam Electric Station, Unit 3Location:Hwy. 18 Killona, Louisiana Dates:March 6-24, 2006Inspectors:M. Brown, Project Engineer, Projects Branch AE. Crowe, Resident Inspector, Projects Branch EG. Larkin, Resident Inspector, Projects Branch EM. Murphy, Senior Operations Engineer, Operations BranchD. Overland, Project Engineer, Projects Branch BApproved by:L. J. Smith, ChiefEngineering Branch 2Division of Reactor Safety Enclosure-2-SUMMARY OF FINDINGSIR 05000382/2006008; Entergy Operations, Inc., 03/06-24/2006; Waterford Steam ElectricStation, Unit 3; biennial baseline inspection of the identification and resolution of problems. The inspection was conducted by two resident inspectors, one senior operations engineer, andtwo project engineers. The NRC's program for overseeing the safe operation of commercialnuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3,dated July 2000.Identification and Resolution of Problems*The team reviewed 237 corrective action program documents, apparent and root causeanalyses, as well as supporting documents to assess problem identification andresolution activities. Based on this review, the team found the licensee's process toidentify, prioritize, evaluate, and correct problems was generally effective; thresholds foridentifying issues remained appropriately low and, in most cases, corrective actionswere adequate to address conditions adverse to quality. However, a number of issueswere identified associated with the proper identification of degraded conditions in theplant. The team reviewed corrective actions associated with these degraded conditionsand design issues at Waterford Steam Electric Station, Unit 3, which had crosscuttingaspects in the area of problem identification and resolution.The team concluded that a positive safety-conscious work environment exists atWaterford Steam Electric Station, Unit 3, based upon interviews conducted with plantpersonnel. The team determined that employees and contractors feel free to raisesafety concerns to their supervision or bring concerns to the employee concernsprogram.Inspector-Identified and Self-Revealing FindingsNone Enclosure-3-REPORT DETAILS4.OTHER ACTIVITIES (OA)4OA2Identification and Resolution of Problems a.Effectiveness of Problem Identification (1)Inspection ScopeThe inspectors reviewed items selected across four of the seven cornerstones todetermine if problems were being properly identified, characterized, and entered into thecorrective action program for evaluation and resolution. Specifically, the team's reviewincluded a selection of 237 condition reports, equipment walkdowns, review of operatorlogs, maintenance records, and station quarterly trend reports. The majority of thecondition reports were opened and closed since the last NRC problem identification andresolution inspection completed on May 21, 2004. The team also performed a historicalreview of condition reports written over the last 5 years for the high pressure safetyinjection system, main feedwater isolation valves, main steam isolation valves, essentialchillers, and the emergency diesel generators. The team reviewed a sample of licenseeaudits and self assessments, trending reports, system health reports, and various otherreports and documents related to the problem identification and resolution program. The audit and self-assessment results were compared with the self-revealing andNRC-identified issues to determine the effectiveness of the audits and selfassessments.The team interviewed station personnel and evaluated corrective action documentationto determine the licensee's threshold for identifying problems and entering them into thecorrective action program. In addition, in order to assess the licensee's handling ofoperator experience, the team reviewed the licensee's evaluation of selected industryoperating experience reports, including licensee event reports, NRC generic letters,NRC bulletins, and NRC information notices, and generic vendor notifications to assessif issues applicable to Waterford Steam Electric Station, Unit 3, were appropriatelyaddressed.A listing of specific documents reviewed during the inspection is included in theattachment to this report. (2)AssessmentThe team determined that, in general, problems were adequately identified and enteredinto the corrective action program, as evidenced by the relatively few findings identifiedduring the assessment period. The licensee's threshold for entering issues into thecorrective action program was appropriately low. However, the team found twoexamples of ineffective problem identification during this inspection. The licensee alsofailed in some instances to identify or document deficiencies, which resulted in NRCnoncited violations.

Enclosure-4-Current IssuesExample 1: The licensee failed to identify multiple temperature changes of thepressurizer surge line, which exceeded the heatup and cooldown rate described inSection 5.4.3.1 of the station's Final Safety Analysis Report. Specifically, the inspectionteam discovered during a plant shutdown in August 2005 that the pressurizer surge linehad experienced 19 changes in temperature, which exceeded this limit. This example isfurther described in Section 4OA2.e of this report.Example 2: The team found the licensee's identification of adverse trends to be weak. The inspection team reviewed 17 conditions reports, in which the licensee documentedinadequacies in the procurement of replacement parts for the station. The licensee had identified a trend of improper parts passing through the receipt inspection, but failed toidentify adverse trends related to lack of engineering involvement, as required by theprocurement process; failure to perform professional engineering evaluations for partstransferred into the system; and receipt inspection documents missing requiredattributes. These procurement process weaknesses resulted in a nonseismicallyqualified synchronization switch being installed in an otherwise operable emergencydiesel generator and a nonconforming fuel oil nipple passing receipt inspection.Example 3: The NRC identified that the licensee missed several opportunities to identifythe containment fan cooler condensate flow switches that did not meet the designrequirements for detecting a one gallon per minute reactor coolant system leak (NRCInspection Report 05000382/2005005-01).Example 4: Control room operators missed several opportunities over a 32.5 hourperiod to identify that a vacuum had been drawn on the reactor coolant system duringrefueling outage draindown conditions (self-revealing, NRC InspectionReport 05000382/2005010-03).Historical IssueExample: The NRC identified the licensee failed to identify an inappropriate value of theunfiltered in-leakage parameter used to calculate the control room operator dose fordesign basis accident conditions involving radiological releases (NRC InspectionReport 05000382/2004006-01). b.Prioritization and Evaluation of Issues (1)Inspection ScopeThe team reviewed condition reports, engineering operability evaluations, andoperations operability determinations to assess the licensee's ability to evaluate theimportance of the conditions adverse to quality. The team reviewed a sample ofcondition reports, failure mode analyses, apparent cause and root cause analyses, toascertain whether the licensee identified and considered the full extent of conditions, Enclosure-5-generic implications, common causes, and previous occurrences. The team alsoobserved management oversight of the significant conditions adverse to quality,including one Corrective Action Review Board meeting.In addition, the inspectors reviewed licensee evaluations of selected industry operatingexperience reports, including licensee event reports, NRC generic letters, NRC bulletins,NRC information notices, and generic vendor notices to assess whether issuesapplicable to Waterford Steam Electric Station, Unit 3, were appropriately addressed. The team performed a historical review of condition reports covering the last 5 yearsregarding the high pressure safety injection system, the emergency diesel generators,main feedwater isolation valves, essential chillers, and the dry cooling tower todetermine if the licensee had appropriately addressed long-standing issues and thosethat might be age dependent.A listing of specific documents reviewed during the inspection is included in theattachment to this report. (2)AssessmentThe team concluded that problems were generally prioritized and evaluated inaccordance with the licensee's corrective action program guidance and NRCrequirements. The team found that for the sample of root cause analyses reviewed, thatthe licensee was generally self critical and exhaustive in its research into the history ofsignificant conditions adverse to quality. However, the team found one example ofineffective problem evaluation during this inspection. Current IssuesExample 1: The inspectors discovered the licensee had categorized the failure of a fueloil pipe nipple in the Emergency Diesel Generator B in 2002, as a condition adverse toquality. The licensee followed Procedure EN-LI-102, "Corrective Action Process,"Revision 4, in making the determination of significance. The inspectors followed thesteps of Procedure EN-LI-102 and arrived at the same level of significance, however,the procedure provides a provision for the Condition Review Group to change the levelof significance, as warranted by the conditions. The inspectors determined that this wasa significant condition adverse to quality because the failure rendered one emergencydiesel inoperable. The Emergency Diesel Generator A experienced a failure of itscorresponding fuel oil nipple in 2005. The licensee determined this failure was asignificant condition adverse to quality solely because of the repetitive nature of thefailure. c.Effectiveness of Corrective Actions (1)Inspection ScopeThe team reviewed 237 condition reports to verify that corrective actions related to theissues were identified and implemented in a timely manner commensurate with safety,including corrective actions to address common cause or generic concerns. The team Enclosure-6-reviewed corrective actions planned and implemented by the licensee and sampledspecific technical issues to determine whether adequate decisions related to structure,system, and component operability were made. In addition, the team reviewed a sample of those condition reports written to addressNRC inspection findings to ensure that the corrective actions adequately addressed theissues as described in the inspection report writeups. The team also reviewed a sampleof corrective actions closed to other condition reports and programs, such as work andengineering work requests to ensure that the condition described was adequatelyaddressed and corrected.A listing of specific documents reviewed during the inspection is included in theattachment to this report. (2)AssessmentThe effectiveness of identified corrective actions to address adverse conditions wasgenerally adequate. The team evaluated several occurrences where the licensee didnot effectively address conditions adverse to quality and corrective actions taken wereuntimely and inappropriate. These included five examples, one identified by the teamand four by other NRC inspections, where the licensee failed to take prompt correctiveactions to resolve long-standing issues. The team also evaluated nine other findingsidentified by the NRC baseline inspection program and other NRC inspections atWaterford Steam Electric Station, Unit 3, since the last problem identification andresolution inspection that had crosscutting aspects related to prompt and effectivecorrective actions to resolve conditions adverse to quality. Current IssuesExample 1: The reactor coolant draindown procedure failed to identify that temporaryvent rigs, required by procedure to properly establish vent paths, included in-line ballvalves in series with the vent path and also failed to direct those ball valves be openedto establish the vent path. The licensee was aware of and did not fix the procedure toaddress the ball valves in 2002 (NRC Inspection Report 05000382/2005010-02).Example 2: The NRC identified the licensee failed to correct the condition whichresulted in multiple cycle timer failures in the essential chiller (NRC InspectionReport 05000382/2005002-01).Example 3: The NRC identified the licensee failed to prevent recurrence of through wallpipe leakage on the main steam line Pipe 2MS2-123. This deficiency resulted in anunisolable steam leak requiring NRC approval to deviate from the American Society ofMechanical Engineers Boiler and Pressure Code Case N523-2 to perform temporaryrepairs preventing a plant shutdown (NRC Inspection Report 05000382/2005004-03).

Enclosure-7-Historical IssuesExample 1: The NRC identified the licensee failed to correct a known deficient conditioninvolving the failure to account for instrument uncertainty to satisfy TechnicalSpecification Surveillance Requirement 4.7.6.5.a. This failure potentially affects theability of the control room envelope to perform its design function with respect toprotecting operators from postulated design basis accidents resulting in radiologicalreleases (NRC Inspection Report 05000382/2004006-03).Example 2: The NRC identified the licensee failed to correct a known deficient conditioninvolving multiple occasions of accumulator overpressure conditions resulting fromdegraded hydraulic fluid adversely affecting the main feedwater isolation valve hydraulicactuator pressure relief system. These over pressure conditions potentially result invalve closure stroke times outside design basis values (NRC InspectionReport 05000382/2004005-03).Example 3: The NRC identified the licensee failed to promptly correct instances wherethe main feedwater isolation valve actuator thermal relief valves failed to properlyfunction. In one case, the licensee failed to properly address system operability and, fora 2-week period, actual valve operability was unknown (NRC InspectionReport 05000382/2004006-02).Example 4: The NRC identified the licensee failed to correct deficiencies in theemergency diesel generator loading and fuel oil consumption analysis. The licenseeinappropriately closed a corrective action requiring the revisions, which subsequentlyresulted in the failure to maintain design control of the emergency diesel generator fueloil storage inventory requirements to ensure a 7-day postaccident fuel oil inventory(NRC Inspection Report 05000382/2004002-05).Example 5: The NRC identified the licensee failed to determine the cause andprecluded recurrence of main steam isolation solenoid-operated dump valve failures. The inspectors noted that the licensee's apparent cause did not provide an extent ofcondition analysis for the solenoid-operated valve failure (NRC InspectionReport 05000382/2004004-03).Example 6: The NRC identified the licensee failed to take adequate corrective action toensure the torque applied to the flow control valve for Accumulator B of main feedwaterisolation Valve 1 was sufficient to prevent an o-ring from extruding, resulting in aloss-of-system hydraulic fluid and rendering the valve inoperable (NRC InspectionReport 05000382/2004008-02).Example 7: The NRC identified the licensee failed on multiple occasions to correct aknown deficient condition involving the failure to account for instrument uncertainty tosatisfy Technical Specification Surveillance Requirement 4.7.6.5.a. This failurepotentially affects the ability of the control room envelope to perform its design functionwith respect to protecting operators from postulated design basis accidents resulting inradiological releases (NRC Inspection Report 05000382/2004006-03).

Enclosure-8-Example 8: The licensee failed to replace known age-degraded o-rings affecting themain feedwater isolation valves in the Year 2000 resulting in o-ring failure andinoperability of the Train A feedwater isolation valve on December 27, 2003(NRC Inspection Report 05000382/2004002-01).Example 9: The NRC identified the licensee failed to establish appropriate torquespecification to ensure adequate o-ring compression that ultimately led to an o-ringfailure and the inoperability of the Train A main feedwater isolation valve. The licenseehad previously identified concerns related to inadequate work instructions for performingmaintenance activities on the main feedwater isolation valves (NRC InspectionReport 05000382/2004002-02). d.Assessment of Safety-Conscious Work Environment (1)Inspection ScopeThe team interviewed 24 individuals from the licensee's staff, representing a crosssection of functional organizations and supervisory and nonsupervisory personnel. These interviews assessed whether conditions existed that would challenge theestablishment of a safety-conscious work environment. The team interviewed the siteemployee concerns program coordinator. (2)AssessmentThe team concluded that a positive safety-conscious work environment exists atWaterford Steam Electric Station, Unit 3. Based on interviews, station personnel feltfree to enter issues into the corrective action program, raise safety concerns with theirsupervision, to the employee concerns program, and to the NRC. The team determinedthat the majority of safety concerns were addressed through the site's normal chain ofcommand by the relatively few safety concerns entered into the employee concernsprogram and the small number of allegations made to the NRC. e.Specific Issues Identified During this Inspection (1)Inspection ScopeDuring this assessment, the team performed the inspections scoped inSections 4OA2 a.(1), 4OA2 b.(1), 4OA2 c.(1), and 4OA2 d.(1) above. (2)Finding Details (i)Unresolved Item: 05000382/2006008-01, "Failure to Maintain Design Control of thePressurizer Surge Line"Introduction. The team identified an unresolved item related to compliance with 10 CFRPart 50, Appendix B, Criterion III, "Design Control," for the failure to translatedesign-basis heatup and cooldown rates for the pressurizer surge line into appropriatespecifications, procedures, and instructions. As a result, Entergy Operations, Inc., failed Enclosure-9-to effectively control and evaluate pressurizer surge line temperature changes onnumerous occasions. Description. Final Safety Analysis Report (FSAR) Section 5.4.3.1, "Reactor CoolantPiping Design Basis," and Section 5.4.10.1, "Pressurizer Design Basis," states, in part,that during heatup and cooldown of the plant, the allowable rate of temperature changefor the surge line is limited to 200°F/hr. Technical Requirements Manual (TRM),Section 3.4.8.2, "Pressurizer Heatup/Cooldown," specifies the limiting condition foroperation, in part, as a maximum heatup rate of 200°F per hour and a maximumcooldown rate of 135°F per hour.On April 18, 2005, Entergy Condition Report CR-WF3-2005-1392 stated that apressurizer surge line temperature transient occurred with the surge line temperaturedropping from 425°F to 140°F, a change of approximately 285°F with approximately200°F occurring within 8 minutes. Technical Requirements Manual, Section 3.4.8.2Action specifies, "With any of the pressurizer limits in excess of the above, the operatorsmust restore the affected parameter to within the limits within 30 minutes; perform anengineering evaluation to determine the effects of the out-of-limit condition on thestructural integrity of the pressurizer; and enter TRM LCO 3.0.3."The team noted that Entergy Operations, Inc., failed to restore pressurizer/surge linelimits within 30 minutes and perform an engineering evaluation to determine the effectsof the out-of-limit condition on the structural integrity of the pressurizer/surge line. Theteam reviewed Entergy Operations, Inc.'s operating procedures for plant heatup andcooldown activities, OP-010-005, "Plant Shutdown," and OP-010-003, "Plant Startup,"and did not find procedure steps to limit surge line temperature changes to less than200°F/hr, nor were there any procedure steps to assess whether surge line stress orfatigue limits had been exceeded. This appeared to be a violation of 10 CFR Part 50,Appendix B, Criterion III, "Design Control," for the failure to translate design-basisheatup and cooldown rates for the pressurizer surge line into appropriate specifications,procedures, and instructions. The design limit in Report CEN-387-P was based, in part, by temperature gradientsgreater than 200°F occurring less than 3.6 occurrences per heatup/cooldown cycle for500 heatup/cooldown cycles over the 40-year life of the plant. Calculation CN-OA-04-53documented 19 instances where pressurizer insurges, in excess of the volume of thesurge line, occurred with a temperature gradient greater than 200°F. These pressurizerinsurges occurred during five refueling outage heatup/cooldown cycles (RefuelingOutages 8-12)for an average of 3.8 temperature gradients greater than 200°F perheatup/cooldown cycle.Entergy Operations, Inc. disagreed and provided a paper (Attachment B), whichdocumented their position. While they acknowledged that the FSAR was not up to date,they stated that the pressurizer surge line temperature transient on April 18, 2005, wasbounded by Combustion Engineering Owners Group Report CEN-387-P, "PressurizerSurge Line Flow Stratification Evaluation," submitted to the NRC in response to NRCBulletin 88-11, "Pressurizer Surge Line Thermal Stratification." Report CEN-387-Pconcluded that the pressurizer surge line met all applicable design codes, FSAR, and Enclosure-10-other regulatory commitments for the licensed life of the plant considering thephenomenon of thermal stratification in fatigue and stress evaluations. The team notedthat this conclusion was based on operating the plant consistent with the assumptions inthe evaluation (Report CEN-387-P). Additional inspection is required to complete thereview of Entergy Operations, Inc.'s, position and determine whether the licensee wasoperating their facility within the assumptions of the analysis.Analysis. The significance of this issue depends on whether or not the analysis boundspast plant operation. Enforcement. The potential failure to translate the design basis into appropriatespecifications, procedures, and instructions to effectively control and evaluate surge linetemperature changes, during plant heatup and cooldown, that exceeded those limitsdescribed in the FSAR and the TRM is unresolved: (URI 05000382/2006008-01);"Failure to Maintain Design Control of the Pressurizer Surge Line." (ii)Unresolved Item 05000382/2006008-02, "Failure to Ensure that Written ProceduresAdequately Incorporate Regulatory Requirements and Design Basis"Introduction. The team identified an unresolved item related to compliance withTechnical Specification, Section 6.8.1, for the failure to ensure that written proceduresadequately incorporate regulatory requirements and the design basis for the dry coolingtower diesel-driven sump pumps.Description. Waterford Safety Evaluation Report, Supplement 4, Section 2.4.2.3,discusses the design basis rainfall event and combination of events. This supplementcommits the licensee to the probable maximum precipitation event. Because of the factthat the motor-driven sumps are not seismically qualified, the NRC requested thelicensee analyze the effects of a standard project storm, which consists of 50 percent ofthe probable maximum precipation event concurrent with an operating basisearthquake. The results of the licensee's analysis showed the licensee was susceptibleto ponding in the dry cooling tower sumps, assuming the loss of all motor-driven pumps,which would endanger the safety-related transformers and motor control centers locatedin the cooling tower areas. The licensee submitted Amendment 34, dated January 1984, subsequent to SafetyEvaluation Report, Supplement 4. Section 2.4.2.3.4 of this amendment submittalcontains an analysis showing the probability of standard project storm and operatingbasis earthquake is 3.6E-08, which is considered negligible. However, the licenseeproposed to provide a 100 gpm portable pump that would be sufficient to pump downthe dry cooling tower sumps in the event of the standard project storm. The NRCdetermined that the portable pump was sufficient (as evidenced in Safety EvaluationReport, Supplement 4) provided the pump was placed in operation within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. In2000, after determining that more sump pumping capacity was needed, the licenseeinstalled a diesel-driven sump pump, with 300 gpm capacity, in each dry cooling towersump. The Design Basis Calculation EC-M99-010 analyzed for a probable maximumprecipation event, concurrent with a loss-of-offsite power, and determined that a highercapacity portable pump was needed. The calculation also analyzed for a rainfallequivalent to 60 percent of the probable maximum precipation event, concurrent with aloss of all motor-driven sump pumps, and determined that a 300 gpm portable pump Enclosure-11-would be sufficient. The licensee's Procedure OP-100-014, "Technical Specificationsand Requirements Compliance," Revision 14, states that two motor-driven sump pumpsor one motor-driven pump and one diesel-driven pump are required for ultimate heatsink operability. This procedure implies that the diesel driven sump pump can be out ofservice indefinitely without affecting operability of the ultimate heat sink. The NRC staffbelieves this procedure does not adequately address the requirement of the portablesump pump in the design basis of the ultimate heat sink, nor does the procedure requireany compensatory actions be taken in the event the diesel-driven sump pump becomesinoperable. Also, the staff believes the controls and location of the diesel-driven sumppump are not adequately addressed by the licensee. Analysis. The significance of this issue has not been determined.Enforcement. The licensee has provided a position paper (Attachment C) related to thedesign basis requirements for the dry cooling tower diesel-driven sump pumps, whichhas not been fully reviewed by the NRC. The potential failure to ensure regulatoryrequirements for these pumps is unresolved: (URI 05000382/2006008-02) "Failure toTranslate Design Control into Station Documents Regarding Diesel-driven Dry CoolingTower Sump Pumps" 4OA6Exit MeetingThe team discussed the findings of the Problem Identification and Resolution inspectionwith Mr. J. Venable, Vice President Operations, and other members of the licensee'sstaff on March 24, 2006. Licensee management did not identify any materials examinedduring the inspection as proprietary.The licensee acknowledged the findings presented. The inspectors noted that whileproprietary information was reviewed, none would be included in this report.ATTACHMENT A: Supplemental InformationATTACHMENT B: Waterford 3 Pressurizer Surge Line Temperature Change RateATTACHMENT C: White Paper on Effect of Diesel Sump Pump Inoperability on Ultimate Heat Sink Operability Attachment AA-1KEY POINTS OF CONTACTLicensee PersonnelB. Baxter, Control Room SupervisorC. DeDeaux Sr., Senior Project Manager, LicensingR. Dodds, Manager, OperationsR. Fletcher, Training ManagerC. Fugate, Assistant Operations ManagerJ. Hall, Operations Training Supervisor - Operator RequalificationJ. Holman, Manager, Nuclear EngineeringJ. Laque, Manager, MaintenanceR. Murillo, Senior Staff EngineerR. Osborne, Manager, Engineering Programs and ComponentsA. Pilutti, Manager, Radiation ProtectionO. Pipkins, Senior Licensing EngineerR. Porter, Superintendent, Mechanical MaintenanceB. Proctor, Systems Engineering ManagerJ. Rachal, Design Engineering SupervisorJ. Ridgel, Manager, Corrective Action ProgramT. Tankersley, Acting Director, Nuclear Safety AssuranceK. Walsh, General Manager, Plant OperationsB. Williams, Engineering DirectorJ. Venable, Site Vice President, Waterford 3NRC M. Hay, Senior Resident Inspector Waterford 3LIST OF ITEMS OPENED, CLOSED, AND DISCUSSEDOpened05000382/2006008-01URIFailure to Maintain Design Control of the Pressurizer SurgeLine (Section 4OA2 e.)05000382/2006008-02URIFailure to Translate Design Control into Station DocumentsRegarding Diesel-driven Dry Cooling Tower Sump Pumps(Section 4OA2 e.)

Attachment AA-2LIST OF DOCUMENTS REVIEWEDPlant ProceduresNAMETITLEREVISIONCEP-IST-1IST Bases Document3EN-OP-115Conduct of Operations0LI-102Corrective Action Process4LI-19645Quality Related Administrative Procedure2MM-006-119Yard Oil Separator to CW Temporary Pumping System0OI-042-000Watch Station Procedures1OP-001-003Reactor Coolant System Draindown23OP-005-004Main Steam12OP-009-008Safety Injection System18OP-100-001Operations Standards and Management Expectations22OP-100-009Control of Valves and Breakers17OP-100-0014Technical Specification and Technical RequirementsCompliance13UNT-005-004Temporary Alteration Control16Engineering ReportsER-W3-2002-0055ER-W3-2004-0537ER-W3-2005-0426ER-W3-00-0337ER-W3-2003-0010ER-W3-2005-0305ER-W3-2002-0278CalculationsCN-OA-04-53EC-M99-010MN(Q)-6-27Root Cause Analysis Reports for CR-WF3-2001-03172002-03392003-00622003-38912004-7592004-1011 Attachment AA-3Condition Reports, CR-WF3-1997-12272000-04412000-13472000-14552001-05962001-06732001-07822001-12842001-13672002-04682002-04702002-05882002-06782002-14102002-18422002-27992003-01472003-05772003-11922003-12022003-27582003-27592003-29912003-30882003-36492003-38912004-02512004-03042004-03092004-03262004-04202004-04642004-04832004-04942004-05082004-06342004-06512004-07012004-07032004-07212004-07592004-08212004-08352004-08652004-09032004-10112004-10472004-11902004-12082004-13122004-13402004-14462004-14802004-15182004-15532004-15722004-15932004-16212004-16452004-16462004-16682004-16792004-16842004-17162004-17512004-17532004-17632004-18102004-18502004-18542004-18552004-18632004-18802004-19422004-20022004-22282004-22902004-23202004-23262004-23822004-24042004-24872004-24962004-25172004-25202004-25222004-25452004-25472004-25492004-26382004-26902004-27222004-27342004-27662004-28842004-28902004-29282004-29732004-29952004-30662004-31302004-32002004-32192004-32442004-34132004-34602004-34642004-36952004-37202004-37252004-37532004-38532004-38812004-39242004-39442004-39492004-40002005-00332005-00812005-00982005-01092005-01322005-01342005-01972005-02172005-03462005-04132005-04152005-04712005-04892005-05302005-05872005-05902005-05912005-05922005-06082005-07172005-07632005-08042005-08052005-08062005-08392005-08522005-09212005-09662005-09672005-11322005-11432005-11732005-12472005-12602005-12792005-13152005-13322005-13462005-13622005-13632005-13922005-14632005-16262005-16462005-16942005-18212005-18362005-20702005-21392005-22672005-22722005-23502005-24022005-24692005-24892005-25362005-25462005-25482005-26002005-26792005-26852005-26952005-27802005-27992005-28192005-28372005-28442005-28692005-28742005-29902005-30062005-30912005-32932005-33082005-34552005-34742005-36592005-36982005-38122005-38222005-38302005-38312005-38402005-38722005-38722005-39022005-39142005-39242005-39282005-39602005-39612005-39852005-40382005-40652005-40662005-40672005-41472005-41492005-41512005-41732005-42512005-44442005-44802005-45972005-46472005-46942005-49152005-49172005-49292005-50242006-00062006-00582006-01642006-02002006-03802006-04922006-07592006-07672006-08392006-0895 Attachment AA-4Learning Organization Conditions ReportsLO-OPX-2004-0247LO-OPX-2005-0100LO-OPX-2005-0217LO-OPX-2006-0011LO-OPX-2005-0036LO-OPX-2005-0103LO-OPX-2005-0243LO-OPX-2006-0034LO-OPX-2005-0085LO-OPX-2005-0132 LO-OPX-2005-0252Work Orders5169751699528245282557759626417260472606412565428180145999015100331101Maintenance Action Items420105438981Miscellaneous DocumentsCommercial Grade Evaluation 01214C-PAC-002L-19645L-23993MMR Project 53465PO WPY205832004 Second Quarter Waterford Quarterly Trend Report2004 Third Quarter Waterford Quarterly Trend Report2004 Fourth Quarter Waterford Quarterly Trend ReportQuality Assurance Audit Report QA-12-20050-WF3-1Quality Assurance Audit Report QA-12-20050-WF3-009Quality Assurance Audit Report QA-12-20050-WF3-1PO 10083675INITIAL MATERIAL REQUESTINITIAL INFORMATION REQUEST FROM WATERFORD 3 FOR PI&R INSPECTION (Report Number 05000382/2004006)The inspection will cover the period of October 2002 to March 2004. The information may beprovided in either electronic or paper media or a combination thereof. Information provided inelectronic media may be in the form of CDs, or 3-1/2 inch floppy disks. The agency's text editingsoftware is Corel WordPerfect 8, Presentations, and Quattro Pro; however, we have documentviewing capability for MS Word, Excel, Power Point, and Adobe Acrobat (.pdf) text files.Please provide the following information to Peter Alter by March 29, 2004 at the ResidentInspector Office at Waterford-3 Attachment AA-5All procedures governing or applying to the corrective action program, including theprocessing of information regarding generic communications and industry operatingexperiencesProcedures and descriptions of any informal systems, used by engineering, operations,maintenance, security, training, and emergency planning for issues below the thresholdof the formal corrective action programA searchable table of all corrective action documents (condition reports) that wereinitiated or closed during the period, include condition report number, description ofissue and significance classificationEither annotate on the above list or a separate list of all condition reports associatedwith:(1)Human performance issues(2)Emergency preparedness issues(3)Response to 10 CFR Part 21 reportsA separate list of all condition reports closed to other programs, such as maintenanceaction items/work orders, engineering requests, etc.A copy of each significant event review team report and root cause analysis report forthe period (not necessarily the whole condition report)Copies of condition reports (for the period) associated with nonescalated (no responserequired) or noncited violations for the periodCopies of condition reports for the period associated with repetitive problems or issues Copies of condition reports for the period associated with ineffective or untimelycorrective actionsList of all self assessments or quality assurance assessments/audits for the periodAll corrective action program reports or metrics used for tracking effectiveness of thecorrective action program for the periodAll quality assurance audits and surveillances, and functional self assessments ofcorrective action activities completed for the periodControl room logs for the Year 2003Security event logs for the year 2003Radiation protection event logs for the year 2003List of risk significant systems from W3 PRA/PSA, based on risk achievement worth(RAW) and "0% availability CDF" Attachment AA-6Searchable list of all maintenance action items/work orders for the periodList of all SSC's placed in or removed from the maintenance rule a(1) category for theperiodAll corrective action documents related to the following industry operating experiencegeneric communications:NRC BulletinsNRC Bulletin 2002-001, "Reactor Pressure Vessel Head Degradation and ReactorCoolant Pressure Boundary Integrity"NRC Information NoticesNRC Information Notice 2004-001, "Auxiliary Feedwater Pump Recirculation Line OrificeFouling - Potential Common Cause Failure"NRC Information Notice 2003-019, "Unanalyzed Condition of Reactor Coolant PumpSeal Leakoff Line During Postulated Fire Scenarios or Station Blackout"NRC Information Notice 2003-013, "Steam Generator Tube Degradation at DiabloCanyon"NRC Information Notice 2003-011, "Leakage Found on Bottom-MountedInstrumentation Nozzles"NRC Information Notice 2003-008, "Potential Flooding Through Unsealed ConcreteFloor Cracks" NRC Information Notice 2003-005, "Failure to Detect Freespan Cracks in PWR SteamGenerator Tubes"NRC Information Notice 2003-002, "Recent Experience With Reactor Coolant SystemLeakage And Boric Acid Corrosion"NRC Information Notice 2002-034, "Failure of Safety-Related Circuit Breaker ExternalAuxiliary Switches at Columbia Generating Station" Attachment AA-7Information Request 1 - January 2006Waterford PIR Inspection (IP 71152; Inspection Report 50-382/06-08)The inspection will cover the period of March 1, 2004 to March 1, 2006. All requestedinformation should be limited to this period unless otherwise specified. The information may beprovided in either electronic or paper media of a combination of this media. Informationprovided in electronic media may be in the form of e-mail attachment(s), CDs, or 3 1/2 inchfloppy disks. The agency's text editing software is Corel WordPerfect 10, Presentations, andQuattro Pro; however, we have document viewing capability for MS Word, Excel, PowerPoint,and Adobe Acrobat (pdf.) text files.Please provide the following by February 8, 2006, to:U.S. Nuclear Regulatory CommissionResident Inspector's Office - Attn. Grant LarkinWaterford Steam Electric Station Unit 3Entergy Operations, Inc.17265 River RoadKillona, Louisiana 70066Note:On summary lists please include a description of problem, status, initiating date, andowner organization1.Summary list of all condition reports opened during the period2.Summary list of all open condition reports with significance of "B" or greater which weregenerated during the period3.Summary list of all condition reports with significance of "B" or greater closed during thespecified period4.Summary list of all condition reports which were down-graded or up-graded insignificance during the period5.A list of all corrective action documents that subsume or "roll-up" one or more smallerissues for the period6.List of all root cause analyses completed during the period7.List of all apparent cause analyses completed during the period8.List of root cause analyses planned, but not complete at end of the period9.List of plant safety issues raised or addressed by the employee concerns programduring the period10.List of action items generated or addressed by the plant safety review committeesduring the period Attachment AA-811.Summary list of operator work-arounds, engineering review requests and/or operabilityevaluations, temporary modifications, safety system deficiencies, and control roomdeficiencies12.All quality assurance audits and surveillances of corrective action activities completedduring the period13.A list of all quality assurance audits and surveillances scheduled for completion duringthe period, but which were not completed14.All corrective action activity reports, functional area self-assessments, and non-NRCthird party assessments completed during the period15.Corrective action performance trending/tracking information generated during the periodand broken down by functional organization16.Current procedures/policies/guidelines for:1.Condition Reporting2.Corrective Action Program3.Root Cause Evaluation/Determination4.Deficiency Reporting and Resolution17.A listing of all external events evaluated for applicability at Waterford during the period18.Condition Reports or other actions generated for each of the items below [ADAMSaccession numbers or other cross reference listed for some]:1.Part 21 Reports (2005-41-00; 2005-38-00 [ml053180299]; 2005-37-00;2005-33-01 [ml052860229]; 2005-30-01 [ml052640220]; 2005-26-01[ml052910389]; 2005-22-00; 2005-20-00; 2005-17-00 [ml051110087];2005-16-00 [ml051100285]; 2005-13-00 [ml050950428]; 2005-12-01[ml052080368]; 2005-12-00 [ml050630275]; 2005-10-00 [ml050560142];2005-07-00; 2005-05-01 [ml051100355]; 2005-01-00 [ml043520077];2004-27-01 [ml043280541]; 2004-24-00 [ml042470299]; 2004-22-00[ml042660175]; 2004-21-00 [ml042520048]; 2004-17-00 [ml041900058];2004-15-00; 2004-14-00; 2004-10-00 [ml041140335]; 2004-08-00[ml041110893]; 2004-02-01 [ml040420567]2.NRC Information Notices 05-32; 05-31; 05-30; 05-29; 05-26; 05-25; 05-24; 05-23; 05-21; 05-19; 05-16; 05-11; 05-09; 05-08; 05-06; 05-02;04-021; 04-019;04-016; 04-012;04-011; 04-010;04-009; 04-008;04-007; 04-0013.All LERs issued by Waterford during the period4.NCVs and Violations issued to Waterford during the period19.Safeguards event logs for the period20.Radiation protection event logs Attachment AA-921.Current system health reports or similar information22.Current predictive performance summary reports or similar information23.Corrective action effectiveness review reports generated during the period ATTACHMENT BWaterford 3 Pressurizer Surge Line Temperature Change Rate Waterford 3 Pressurizer Surge Line Temperature Change RatePage 1 of 4PurposeThis Paper is to document the Entergy position on the potential NCV of 10CFR50Appendix B, Criterion III, "Design Control" for not translating design basis criteriainto plant operating procedures. The design basis criteria in question is astatement in the FSAR (Section 5.4.3.1) which states:During heatup and cooldown of the plant, the allowable rate oftemperature change for the surge line is increased to 200°F/hr as a designrequirement specified in Subsection 3.9.1.1.BackgroundThe following is a time line of the Entergy response to NRC Bulletin No. 88-11.This concludes that the fatigue life of the Waterford 3 surge line is 40 years whichthe NRC concurred with.* The NRC issued NRC Bulletin No. 88-11, Pressurizer Surge Line ThermalStratification, on December 20, 1988. The purpose of the Bulletin was torequest that addressees establish and implement a program to confirmpressurizer surge line integrity in view of the occurrence of thermalstratification and to inform the staff of the actions taken to resolve thisissue.* CEN-387-P was transmitted to the NRC on July 27, 1989. Thisdocumented that the Waterford 3 surge line fatigue life is longer than 40years.* On August 28, 1989, Entergy sent a letter to the NRC stating that Bulletin88-11 item 1b, 1c and 1d were addressed in CEN-387-P and that item 1a(visual inspection of the pressurizer surge line) would be addressed duringthe next refueling outage.* On March 7, 1990, Entergy sent a letter to the NRC which addressed theresults of the visual inspections of the pressurizer surge line. The letterconcluded that the Waterford 3 surge line was structurally sound.* On August 15, 1990, the NRC issued a letter stating there was not enoughinformation in the CEN document to conclude that the pressurizer surgeline meets all appropriate Code limits for a 40 year plant life.* On December 20, 1991, CEN-387-P, Revision 1-P was sent to the NRC toaddress the concerns of the August 15, 1990 NRC evaluation of the CENdocument.* On May 5, 1992, Entergy sent a letter to the NRC documenting thesubmittal of the revised CEN document and stated the only remainingaction to complete the response to the Bulletin is for the Waterford 3 toupdate the pressurizer surge line design documentation. This wascommitted to be completed within 180 days of issuance of a favorableSER by the NRC.

Waterford 3 Pressurizer Surge Line Temperature Change RatePage 2 of 4* On June 22, 1993, the NRC issued an SER for CEN-387-P, Revision 1. Itwas concluded that the analysis in the CEN adequately demonstrates thatthe bounding surge line and nozzles meet ASME Code stress and fatiguerequirements for the 40 year design life of the facility considering thephenomenon of thermal stratification and thermal stripping. The staffrequested Entergy to provide a final status of the Waterford 3 activitiesrequired by NRC Bulletin 88-11.* On December 23, 1993, Entergy sent a letter to the NRC stating that alldesign documents had been updated and that all actions required by NRCBulletin 88-11 had been completed.CEN-387-P, Revision 1, is the Combustion Engineering response to NRCBulletin 88-11. This document addresses pressurizer surge line flowstratification. The document provides a detailed fatigue analysis of stress due tostratified temperature profiles of the fluid in the pressurizer surge line. Note thatthis document indicates that thermal stratification is assumed for all surge flow asthe velocities will always be low. This document also specifically indicates thatthe stratified temperature analysis envelopes high velocity flow and thermalshock.The following paragraphs are excerpted from the Thermal Striping Analysis forthe pressurizer surge line in CEN-387-P, Revision 1. The conclusion is the"effect of thermal striping is negligible and will not affect the fatigue life of thepressurizer surge line".The term "striping" refers to the thermal oscillations that occur at the hot-cold interface.The period of oscillations was chosen to be 1 second and 4 seconds forthe surge line analysis. Test data was measured or was empiricallydetermined to be in the range of 1 second to 10 seconds. For the largetemperature differences and high heat transfer coefficient used in thisanalysis, the period is closer to 1 second than 4 seconds. A longer periodwould yield a lower heat transfer coefficient, and therefore smallerchanges in metal temperatures. However, to be conservative, the sameheat transfer coefficient was used for all cases.The stresses due to each gradient as a function of time were calculatedusing formulas in ASME Code Section III, NB-3653.2. Table 3.5.3-2 liststhe alternating stress calculated for each of the four transients used forevaluating fatigue. As can be seen from this table only one of the fourtransients contributes anything to fatigue. That transient is number four(4) with an alternating stress of 15,780 psi and a number of allowablecycles of 1.42E7.

Waterford 3 Pressurizer Surge Line Temperature Change RatePage 3 of 4Waterford 3 Design Specification 9270-PE-140 is the project specification forreactor coolant pipe and fittings. This document provides a summary of thedesign analysis for surge line temperature transients. It includes text sectionsand 2 tables as they apply to the surge line and surge line nozzle. The tablesaddress temperature differences anticipated as a result of thermal stratification.Table 4.5.15.3.1 lists expected occurrences of temperature differences betweenthe pressurizer and the RCS hot leg and provides the number of expectedoccurrences. Table 4.5.15.3.2 lists expected occurrences of temperaturedifferences between the top and bottom of the surge line piping. Thesetemperatures differences are for the pressurizer surge line piping and not thefluid temperature in the piping. The number of occurrences is the expectednumber for the life of the plant.Entergy PositionThe Entergy position is that pressurizer surge line temperature is not required tobe specifically monitored per procedure to ensure the design limits aremaintained, and that FSAR Section 5.4.3.1 should have been revised in 1993when the Waterford 3 stress and fatigue analyses and design specifications wererevised per NRC Bulletin 88-11 to reflect the results of CEN-387-P, Revision 1.This section of the FSAR has not been revised since the initial FSAR. CR-WF3-2006-0839 was initiated to revise the FSAR. The reasoning for Entergy'sposition is documented in the paragraphs below.The pressurizer surge line temperatures during heatup and cooldown aremaintained by ensuring the heatup and cooldown limits in the RCS andpressurizer are maintained. The RCS limits are located in the TS and thepressurizer limits are located in the TRM. Temperature changes in the surge linecan be greater than 200°F due to thermal stratification and thermal stripping.CEN-387-P, Revision 1 documented that the pressurizer surge line meets Codestress and fatigue requirements for the 40 year design life of the facilityconsidering the phenomenon of thermal stratification and thermal stripping.Analysis in the CEN has indicated that temperature differences of up to 340°Fhave been evaluated for.The data recorded by the temperature element in the surge line has shownperiods of temperature changes greater than 200°F/hr. Thermal stratification isapplicable to all of these recorded temperature changes. These temperaturechanges do not necessarily reflect the average temperature change of the surgeline but reflects a change in local fluid temperature at the temperature element.This recorded temperature changes over time are not the same deltatemperatures listed in the tables in 9270-PE-140.Therefore, the temperature difference in the pressurizer surge line is bounded bythe analysis performed in CEN-387-P, Revision 1 and monitoring pressurizer Waterford 3 Pressurizer Surge Line Temperature Change RatePage 4 of 4surge line temperature per procedure during heatup and cooldown is notnecessary.Additional InformationThe additional information specifically addresses the difference between thesurge line temperature increase seen during Refuel 13 and during the shutdownfor Hurricane Katrina, and the delta temperature values in 9720-PE-140. It alsoaddresses the reason Waterford 3 does not currently monitor surge linetemperature during heatups and cooldowns.There following information is clarification regarding cycles listed in DesignSpecification 9270-PE-140 and the temperatures recorded in PI with thetemperature element located in the surge line. The graphical data recording thesingle surge line temperature element over time for our Refuel 13 outage and theHurricane Katrina outage indicates periods of temperature changes greater than200 degrees within one hour. Thermal stratification is applicable to all of theserecorded temperature changes. Thermal stratification temperature changes wereaddressed by CEN-327-P (NRC accepted response to NRC Bulletin 88-11). Thissingle temperature element does not necessarily reflect the average temperaturechange of the surge line but reflects a change in local fluid temperature at thetemperature element. The recorded temperature changes of a single point overtime is not the same delta temperatures listed in the tables of the W3 Designspecification of RCS Piping and Fitting document (document #9270-PE-140).The table 4.5.15.3.1 lists expected occurrences of temperature differencesbetween two different locations; the pressurizer and the RCS hot leg andprovides the number of expected occurrences. Table 4.5.15.3.2 lists expectedoccurrences of temperature differences between the top and bottom of the surgeline piping. These tables clearly state this information at the end of theirrespective sections. Thus comparing a graph of temperature changes withrespect to time to these tables is not appropriate.The effects on the Pressurizer Surge Line due to thermal stratification andthermal stripping were evaluated in CEN-327-P, Revision 1. This was reviewedby the NRC and in the SER the Staff concluded that the surge line meets ASMECode stress and fatigue requirements for the 40-year design life. Waterford 3currently monitors heatups and cooldowns of the RCS and Pressurizer. Theeffects of these heatups and cooldowns on the pressurizer surge line have beenevaluated in CEN-327-P.

ATTACHMENT CWhite Paper on Effect of Diesel Sump Pump Inoperability on Ultimate Heat Sink Operability 11.0 PurposeThis paper provides an answer to the question, what is the original licensingbasis for flood protection of essential equipment in the Dry Cooling Tower Areas?The paper also provides the chronology of regulatory requirements and licensingbases that support the conclusion.2.0 Conclusion Regarding Licensing BasisThe original licensing basis for essential equipment in the Dry Cooling Towerareas is that essential equipment be protected from Standard Project Storm(SPS).The elements of the licensing basis are the following:§The SPS, with all installed sump pumps inoperative, was analyzed as anevent less severe than the probable maximum precipitation.§Provisions are required to be in place for emplacing the portable sump pumpwithin 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of an SPS event to ensure that the ponding level from SPSdoes not adversely affect essential equipment if installed pumps areinoperative.§The electric pumps are seismically designed but not seismically qualified;therefore they were assumed not to be available following an OBE.§The probability of the occurrence of an SPS and OBE is 3.6E-8 andnegligible.In essence, the original licensing basis required that the portable sump pump beemplaced and started within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of the start of an SPS (sump high levelalarm) to ensure that essential equipment in the DCT areas is not flooded.On July 26, 1999, Condition Report CR-WF3-1999-0789 was initiated to identifythat the Dry Cooling Tower sump pump capacities were not sufficient to meet theoriginal licensing basis.A new discharge path for the DCT sump pumps was installed via DCP-3251.The DCP also replaced the 1 portable sump pump that had a capacity of 100gpm with 2 portable sump pumps having a capacity of 300 gpm each. Theinstalled sump pump's capacities were reduced from 325 gpm to 270 gpm due tothe new piping configuration. The revised time frame for starting the portablesump pump to ensure essential equipment is not flooded was re-established as 3hours from the start of an SPS (sump high level alarm). Procedure OP-901-521instructs Operations to operate the DCT Portable Sump Pumps in accordancewith OP-003-024, Sump Pump Operation within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of the sump level alarm.

23.0 ChronologyRegulatory Guide 1.70, Revision 2, September 1975Waterford 3 is committed to Regulatory Guide 1.70, Revision 2, as noted insection 1.8 of FSAR. Neither Regulatory Guide Section 2.4.2.3, "Effects of LocalIntense Precipitation," or Section 2.4.3.1, "Probable Maximum Precipitation(PMP)," have any requirement to consider OBE or SPS concurrently.Regulatory Guide Section 2.4.2.3 states:"Describe the effects of local probable maximum precipitation (see Section2.4.3.1) on adjacent drainage areas and site drainage systems, includingdrainage from the roofs of structures. Summarize the design criteria for sitedrainage facilities and provide analyses that demonstrate the capability of sitedrainage facilities to prevent flooding of safety related facilities resulting fromlocal probable maximum precipitation."The fundamental requirement in the Regulatory Guide is that the applicantensures that safety related equipment is not adversely impacted from maximumprecipitation.Regulatory Guide 1.59, Revision 2, August 1977Waterford 3 is committed to Regulatory Guide 1.59, Revision 2, as noted insection 1.8 of FSAR. Regulatory Guide 1.59, Revision 2, does not have aspecific requirement to consider OBE and SPS concurrently.Two important requirements are discussed in the Regulatory Guide.First, seismically induced floods are associated with land features specific toeach site such as streams, estuaries, dam failures, and landslides. Thisrequirement does not apply to flooding in the DCT sump areas.Second, the Regulatory Guide states that the most severe flood conditions maynot indicate potential threats to safety related systems that might result fromcombination of flood conditions thought to be less severe. The Regulatory Guidestates that reasonable combinations of less severe flood conditions should beconsidered to the extent needed. The Regulatory Guide states that suchcombinations should be evaluated in cases where theprobability of theirexisting at the same time and having significant consequences is at leasecomparable to that associated with the most severe hydro-meteorological orseismically induced flood. We judge that the requirement to consider the SPSoriginates from this requirement. Also, since the probability of a SPS and OBEconcurrent was later established to be negligible, we judge that not consideringthe SPS concurrent with the OBE is in conformance with the Regulatory Guide.

3Standard Review Plan 2.4.3, Revision 2 July 1981Standard Review Plan 2.4.3 does not have a specific requirement to considerOBE and SPS concurrently.Standard Review Plan 2.4.3,Section I, states:Included is a review of the details of site drainage-, including the roofs of safetyrelated structures, resulting from potential PMP probable maximumprecipitation-"Standard Review Plan 2.4.3,Section IV, states:"The local PMF resulting from the estimated local PMP was found not to causeflooding of safety related facilities, since the site drainage system will be capableof functioning adequately during such a storm."The fundamental requirement in the Standard Review Plan is that the applicantensures that safety related equipment is not adversely impacted form maximumprecipitation.NRC Safety Evaluation Report, July 1981The NRC evaluates the effects of a 6-hr duration PMP on the open cooling towerareas and adjacent roofs. The NRC concludes that, assuming one sump pumpin each area is inoperable and that the roof drainage system is clogged withdebris during the PMP, that the ponding could inundate the transformers andMCC's in the cooling tower areas.The Safety Evaluation Report makes no reference to SPS or OBE.FSAR Amendment 25, January 1982FSAR Section 2.4.2.3.4 was initially added to the FSAR; previously it did notexist. This FSAR Section is titled, "Effects of Standard Project Storm (SPS) onCooling Tower Areas".Two important aspects of the licensing basis are established in this FSARSection.First, a probability evaluation is documented establishing that the occurrence ofan SPS and OBE is 3.6 E-8 and negligible.Second, FSAR Section states that the SPS was still analyzed, assuminginoperability of all pumps, in order to determine the time available before levelsare reached that could affect essential equipment in the Cooling Tower Areas.

4Safety Evaluation Report, Supplement 4, October 1982The SER states the following:"An alternative combination which should be considered is an operating basisearthquake (OBE), which fails the sump pumps, coincident with a rainfall eventless than the PMP. This combination is considered appropriate since the pumpsare not seismically qualified1, and thus cannot be shown to be operable followinga seismic event. The staff therefore, requested that the applicant provide ananalysis of the effects of a standard project storm (SPS)2 assuming all fourpumps in the cooling tower areas are inoperable."The SER further states:"-the staff considered a SPS of 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> duration. This event would produce atotal rainfall of about 23 inches and would result in a ponding depth of about 1.9ft in the cooling tower areas assuming that all four pumps are inoperable. Sincethis is higher than the maximum allowable ponding depth of 1.71 feet, theapplicant has proposed to provide a portable pump with a pumping capacity of100 gpm and sufficient head to pump over the cooling tower wall. -a provisionwill be included for emplacing the portable pump within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of a seismicevent if the installed pumps fail."FSAR Amendment 33, September 1983FSAR Amendment 33 revises Section 2.4.2.3.4 to state the following:"The maximum height to which rainwater can rise in this area before essentialequipment is reached is 1.71 ft (see subsection 2.4.2.3.3d). As shown in Table2.4-6c, this level would not be reached for over seven hours into the SPS.""Furthermore, a portable pump is provided, with a pumping capacity of 100 gpmand sufficient head to pump over the cooling tower wall. Provisions are includedfor emplacing the portable pump within six hours of a seismic event if theinstalled pumps fail and heavy rains are expected."Thus, the FSAR Amendment 33 is in agreement with NRC SER Supplement 4 inthat the fundamental requirement is to protect essential equipment in the coolingtower areas in the event of a SPS. The specific requirement in FSARAmendment 33 is that provisions be made for emplacing the portable sumppump within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of a SPS event and that essential equipment be protected,by ensuring that the ponding level does not reach 1.71 ft. The seismic event is avehicle to postulate the installed pumps are not available; however, important tothe licensing basis is the condition that the electric sump pumps will not beavailable and that essential equipment needs to be protected prior to the pondinglevel reaching 1.71 ft.

5NRC Letter dated December 18 1984, Issuance of Five Percent Power License,The NRC issues five percent power license, and Section 2.B.2 of the licenseapproves operation as described in FSAR as supplemented and amendedthrough Amendment 36.NRC Letter dated March 16, 1985, Issuance of 100% Power LicenseThe NRC issues 100 percent power license, and Section 2.B.2 of the licenseapproves operation as described in FSAR as supplemented and amendedthrough Amendment 36.Design Change, July 26, 1999On July 26, 1999, Condition Report CR-WF3-1999-0789 was initiated to identifythat the Dry Cooling Tower sump pump capacities were not sufficient to meet theoriginal licensing basis.A new discharge path for the DCT sump pumps was installed via DCP-3251.The DCP also replaced the 1 portable sump pump that had a capacity of 100gpm with 2 portable pumps having a capacity of 300 gpm each. The installedsump pump's capacities were reduced from 325 gpm to 270 gpm due to the newpiping configuration. The revised time frame for ensuring essential equipment isnot flooded was re-established as 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> from the start of SPS (sump high levelalarm). Procedure OP-901-521 instructs Operations to operate the DCT PortableSump Pumps in accordance with OP-003-024, Sump Pump Operation within 3hours of the sump level alarm.