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{{Adams|number = ML080320244}}
{{Adams
| number = ML071730036
| issue date = 06/20/2007
| title = IR 05000247-07-006; on 04/23 - 05/18/2007; Indian Point Nuclear Generating, Unit 2; Triennial Fire Protection Team Inspection
| author name = Rogge J F
| author affiliation = NRC/RGN-I/DRS/EB3
| addressee name = Dacimo F
| addressee affiliation = Entergy Nuclear Operations, Inc
| docket = 05000247
| license number = DPR-026
| contact person =
| document report number = IR-07-006
| document type = Inspection Report, Letter
| page count = 21
}}


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{{IR-Nav| site = 05000247 | year = 2007 | report number = 006 }}
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[[Issue date::February 1, 2008]]
[[Issue date::June 20, 2007]]


Mr. Joseph E. PollockSite Vice PresidentEntergy Nuclear Operations, Inc.Indian Point Energy Center450 Broadway, GSBP.O. Box 249Buchanan, NY 10511-0249
Mr. Fred DacimoSite Vice President Entergy Nuclear Operations, Inc.


SUBJECT: INDIAN POINT NUCLEAR GENERATING UNIT 3 - NRC COMPONENT DESIGNBASES INSPECTION REPORT 05000286/2007006
Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249


==Dear Mr. Pollock:==
SUBJECT: INDIAN POINT UNIT 2 - NRC TRIENNIAL FIRE PROTECTION INSPECTIONREPORT 05000247/2007006
On December 18, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection of Indian Point Nuclear Generating Unit 3. The preliminary inspection results werediscussed with Messrs. P. Conroy and T. Orlando and other members of your staff at thecompletion of the on-site inspection activities on November 8, 2007. Following in-office reviewsof additional information, the final results of the inspection were provided by telephone toMessrs. P. Conroy and T. Orlando on December 18, 2007, and to Mr. P. Conroy on January 29,2008. The enclosed inspection report documents the inspection results.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. This particular inspection was performed by a team of NRC inspectors and contractors usingNRC Inspection Procedure 71111.21, "Component Design Bases Inspection." In conducting theinspection, the team examined the adequacy of selected components and operator actions tomitigate postulated transients, initiating events, and design basis accidents. The inspection alsoreviewed Entergy's response to selected operating experience issues. The inspection involvedfield walkdowns, examination of selected procedures, calculations and records, and interviewswith station personnel. This report documents six NRC-identified findings that were of very low safety significance(Green). Five of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance of the violations and because they wereentered into your corrective action program, the NRC is treating the violations as non-citedviolations (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contestany NCV in this report, you should provide a response within 30 days of the date of thisinspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission,ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the RegionalAdministrator, Region I; the Director, Office of Enforcement, U.S. Nuclear RegulatoryCommission, Washington, D.C. 20555-0001; and the NRC Resident Inspectors at Indian PointUnit 3.


J. Pollock2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in theNRC Public Document Room or from the Publicly Available Records component of NRC'sdocument system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
==Dear Mr. Dacimo:==
On May 17, 2007, the NRC completed a triennial fire protection team inspection at your IndianPoint Nuclear Generating Unit 2. The enclosed report documents the inspection results, which were discussed at an exit meeting on [[Exit meeting date::May 17, 2007]], with you 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.


Sincerely,/RA/
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, no findings of significance were identified.
Lawrence T. Doerflein, ChiefEngineering Branch 2Division of Reactor SafetyDocket No. 50-286License No. DPR-64


===Enclosure:===
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/ADAMS.html (the Public Electronic Reading Room).
Inspection Report 05000286/2007006 J. Pollock2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in theNRC Public Document Room or from the Publicly Available Records component of NRC'sdocument 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/
Sincerely,/RA/John F. Rogge, ChiefEngineering Branch 3 Division of Reactor Safety June 20, 2007Mr. Fred DacimoSite Vice President Entergy Nuclear Operations, Inc.
Lawrence T. Doerflein, ChiefEngineering Branch 2Division of Reactor SafetyDocket No. 50-286License No. DPR-64


===Enclosure:===
Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249
Inspection Report 05000286/2007006SUNSI Review Complete: LTD  (Reviewer's Initials)ADAMS ACC#ML080320244DOCUMENT NAME: C:\FileNet\ML080320244.wpdAfter declaring this document "An Official Agency Record" it will be released to the Public.To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy withattachment/enclosure "N" = No copyOFFICERI/DRSRI/DRSRI/DRSRI/DRSRI/DRPNAMELScholl/LLSLDoerflein/LTD MGamberoni/DJRforWSchmidt/WLSECobey/EWCDATE1/7/082/1/081/30/081/7/081/25/08 J. Pollock3cc w/encl:J. Wayne Leonard, Chairman and CEO, Entergy Nuclear Operations, Inc.G. J. Taylor, Chief Executive Officer, Entergy OperationsM. Kansler, President & CEO/CNO, Entergy Nuclear Operations, Inc.J. T. Herron, Senior Vice President, Entergy Nuclear Operations, Inc.M. Balduzzi, Senior Vice President & COO, Regional Operations NortheastSenior Vice President of Engineering and Technical ServicesJ. DeRoy, Vice President, Operations Support (ENO)A. Vitale, General Manager, Plant Operations O. Limpias, Vice President, Engineering (ENO)J. McCann, Director, Nuclear Safety and Licensing (ENO)J. Lynch, Manager, Licensing (ENO)E. Harkness Director of Oversight (ENO)P. Conroy, Director, Nuclear Safety Assurance W. Dennis, Assistant General Counsel, Entergy Nuclear Operations, Inc.P. Tonko, President and CEO, New York State Energy Research and Development AuthorityP. Eddy, Electric Division, New York State Department of Public ServiceC. Donaldson, Esquire, Assistant Attorney General, New York Department of LawD. O'Neill, Mayor, Village of BuchananJ. G. Testa, Mayor, City of PeekskillR. Albanese, Four County CoordinatorS. Lousteau, Treasury Department, Entergy Services, Inc.Chairman, Standing Committee on Energy, NYS AssemblyChairman, Standing Committee on Environmental Conservation, NYS AssemblyChairman, Committee on Corporations, Authorities, and CommissionsM. Slobodien, Director, Emergency PlanningW. Dennis, Assistant General CounselAssemblywoman Sandra Galef, NYS AssemblyT. Seckerson, Clerk of Westchester County Board of LegislatorsA. Spano, Westchester County ExecutiveR. Bondi, Putnam County ExecutiveC. Vanderhoef, Rockland County ExecutiveE. A. Diana, Orange County ExecutiveT. Judson, Central NY Citizens Awareness NetworkM. Elie, Citizens Awareness NetworkD. Lochbaum, Nuclear Safety Engineer, Union of Concerned ScientistsPublic Citizen's Critical Mass Energy ProjectM. Mariotte, Nuclear Information & Resources ServiceF. Zalcman, Pace Law School, Energy ProjectL. Puglisi, Supervisor, Town of CortlandtCongressman John HallCongresswoman Nita LoweySenator Hillary Rodham ClintonSenator Charles SchumerG. Shapiro, Senator Clinton's StaffJ. Riccio, GreenpeaceP. Musegaas, Riverkeeper, Inc.M. Kaplowitz, Chairman of County Environment & Health CommitteeA. Reynolds, Environmental Advocates J. Pollock4D. Katz, Executive Director, Citizens Awareness NetworkS. Tanzer, The Nuclear Control InstituteK. Coplan, Pace Environmental Litigation ClinicM. Jacobs, IPSECW. DiProfio PWR SRC ConsultantW. Russell, PWR SRC ConsultantG. Randolph, PWR SRC ConsultantW. Little, Associate Attorney, NYSDECM. J. Greene, Clearwater, IncR. Christman, Manager Training and Development J. Spath, New York State Energy Research, SLO DesigneeA. J. Kremer, New York Affordable Reliable Electricity Alliance (NY AREA)
J. Pollock5Distribution w/encl:(via E-mail)S. Collins, RA M. Dapas, DRA G. West, RI OEDO (Acting)J. Lubinski, NRRJ. Boska, PM, NRRJ. Hughey, NRRM. Gamberoni, DRSD. Roberts, DRSL. Doerflein, DRSL. Scholl, DRSE. Cobey, DRPD. Jackson, DRPB. Welling, DRPP. Cataldo, Senior Resident Inspector - Indian Point 3C. Hott, Resident Inspector - Indian Point 3 R. Martin, DRP, Resident OARegion I Docket Room (with concurrences)ROPreports@nrc.gov (All IRs)
EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION IDocket No.50-286License No.DPR-64Report No.05000286/2007006Licensee:Entergy Nuclear NortheastFacility:Indian Point Nuclear Generating Unit 3Location:450 Broadway, GSBBuchanan, NY 10511-0308Dates:October 1 to November 8, 2007 (on site)November 13 to December 18, 2007 (in-office)Inspectors:L. Scholl, Senior Reactor Inspector (Team Leader)S. Pindale, Senior Reactor InspectorJ. Richmond, Senior Reactor InspectorG. Ottenberg, Reactor InspectorT. Sicola, Reactor InspectorO. Mazzoni, NRC Instrumentation and Controls Contractor S. Kobylarz, NRC Electrical ContractorW. Sherbin, NRC Mechanical ContractorApproved by:Lawrence T. Doerflein, Chief Engineering Branch 2Division of Reactor Safety Enclosureii


=SUMMARY OF FINDINGS=
SUBJECT: INDIAN POINT UNIT 2 - NRC TRIENNIAL FIRE PROTECTION INSPECTIONREPORT 05000247/2007006
.....................................................vi 1R21Component Design Bases Inspection ......................................1.1Inspection Sample Selection Process.......................................1
.2Results of Detailed Reviews..............................................2.2.1 Detailed Component Design Reviews ................................2.2.1.1No. 33 Safety Injection Pump.................................2.2.1.2Residual Heat Removal Pump Discharge Header Isolation Valve (AC-MOV-744).................................................2.2.1.3Service Water Pump 31......................................4.2.1.4Recirculation Pump 32.......................................5.2.1.5Auxiliary Feedwater Pump 31 (Motor Driven).....................8.2.1.6Auxiliary Feedwater Pump 32 (Turbine Driven)....................9.2.1.7No. 31 Emergency Diesel Generator (Mechanical)................11.2.1.8 Residual Heat Removal Supply from Reactor Coolant System IsolationValves (AC-MOV-730 and -731)..............................13.2.1.9Main Steamline Atmospheric Steam Dump Valves  (MS-PCV-1134, 1135, 1136, & 1137).......................................14.2.1.10Motor Driven Auxiliary Feedwater Flow Control Valves (BFD-FCV-406A,B,C,D)..............................................14.2.1.11Station Battery 31..........................................15.2.1.12480V Switchgear 32 Bus 6A.................................17.2.1.13Emergency Diesel Generator 31 (Electrical).....................17.2.1.14Station Auxiliary Transformer (SAT)...........................19.2.1.15Auxiliary Feedwater Pump and Valve Instrumentation and Controls..21.2.1.16118 Vac Instrumentation Bus 31 and Inverter....................22.2.1.17Appendix "R" Standby Diesel Generator........................22.2.1.18480 Vac Motor Control Center MCC-36B.......................23.2.1.19Steam Generator Atmospheric Dump Valve (MS-PCV-1134) ControlCircuitry.................................................232.1.20 Switchgear Room Ventilation Fan 33...........................23.2.2Detailed Operator Action Reviews ..................................24.2.2.1AC Power Recovery........................................24.2.2.2Initiate Low and High Head Recirculation Flow...................25.2.2.3Manually Trip the Reactor Coolant Pumps Following Loss of Component Cooling Water System............................25.2.2.4Local/Manual Control of Turbine Driven Auxiliary Feedwater PumpFlow....................................................25.2.2.5Local/Manual Operation of Atmospheric Dump Valves.............26 Enclosureiii.3Review of Industry Operating Experience (OE) and Generic Issues..............26.3.1NRC Information Notice (IN) 2005-023, Vibration-Induced Degradation ofButterfly Valves.................................................26.3.2NRC IN 2002-012, Submerged Safety-Related Electrical Cables..........27.3.3NRC IN 2006-26, Failure of Magnesium Rotors in Motor-Operated ValveActuators......................................................27.3.4NRC IN 2006-22, Ultra-Low-Sulfur Diesel Fuel Oil Adverse Impact on EDGPerformance....................................................27.3.5NRC IN 2005-30, Safe Shutdown Potentially Challenged by Unanalyzed Internal Flooding Events and Inadequate Design.......................27.3.6NRC IN 1992-16, Supplement 2, Loss of Flow From the Residual Heat Removal Pump During Refueling Cavity Draindown.....................284OA2Problem Identification and Resolution......................................284AO6Meetings, Including Exit.................................................28 ATTACHMENT.............................................................A-1KEY POINTS OF CONTACT.............................................A-1LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED......................A-2LIST OF DOCUMENTS REVIEWED......................................A-2LIST OF ACRONYMS USED............................................A-13 1 Described in NRC's Inspection Manual Chapter 0308, Reactor Oversight Process2 Described in NRC's Inspection Manual Chapter 0609, Appendix A, Determining theSignificance of Reactor Inspection Findings for At-Power SituationsEnclosureivEXECUTIVE SUMMARYDuring the period from October 1 through November 8, 2007, the U.S. Nuclear RegulatoryCommission (NRC) conducted a team inspection at the Indian Point Nuclear Generating Unit 3(IP-3) in accordance Inspection Procedure  71111.21, "Component Design Bases Inspection."The inspection involved four weeks of on-site effort. Additional in-office reviews of informationwere also conducted through December 18, 2007. The inspection procedure is conducted aspart of the NRC's Reactor Oversight Process (ROP).1  The objective of the inspection was toverify that the IP-3 design bases had been correctly implemented for selected risk-significantcomponents, and that operating procedures and operator actions were consistent with thedesign and licensing bases. This was to ensure that the selected components were capable ofperforming their intended safety functions and could support the proper operation of theassociated systems. The inspection team consisted of eight inspectors, including a team leaderand four inspectors from the NRC's Region I Office, and three contractors. The team selected twenty components for a detailed design review after completing a detailed,risk based selection process. In selecting samples for review, the team focused on thosecomponents and operator actions that have a high relative contribution to the risk of apostulated core damage accident if the component was to fail or if the operator did notsuccessfully complete the action. The team also assessed available margin for the risk-significant components in selecting the samples. The selected samples included components inthe safety injection (SI), residual heat removal (RHR), auxiliary feedwater (AFW), service water(SW), main steam (MS), onsite electrical power, and off-site electrical power systems. Theteam selected five risk-significant operator actions for review using the complexity of the action,time to complete the action, and extent of training on the action as inputs. The team alsoselected six operating experience issues related to the selected components or generic issuesto verify they had been appropriately assessed and dispositioned. For each sample selected,the team reviewed design calculations, corrective action reports, maintenance and modificationhistories, and associated operating and testing procedures. The team also performedwalkdowns of the accessible components to assess their material condition. Overall, the inspection team determined that the components reviewed were capable ofperforming their intended safety functions. The team also found that the operating procedures,operator training and equipment staging adequately supported completion of the operatoractions and were consistent with the design and licensing bases. The team did identify six findings of very low safety significance (Green) and one unresolved item. The six findings arelisted in the "Summary of Findings" section of this report. The team assessed the safetysignificance of each of the findings using the NRC's Significance Determination Process (SDP).2 Also, for each of the findings where current operability was a relevant question, Entergycompleted an operability evaluation. In each case, Entergy determined the equipment wasoperable. The inspection team independently confirmed Entergy's conclusions. All of thefindings were entered into Entergy's corrective action program to ensure a more comprehensiveassessment of the issue and to identify and implement appropriate corrective actions.


3 As described in Inspection Manual Chapter 0305, Operating Reactor AssessmentProgramEnclosurev Under the NRC's Reactor Oversight Process, findings of very low safety significance (Green)are addressed through the facility's corrective action program. Future NRC inspections, mostnotably the biennial Problem Identification and Resolution (PI&R) team Inspection, review asubstantial sample of Entergy's response to the Green findings and assess the adequacy of theactions taken to correct the deficiencies.The findings are also an input into the NRC's assessment process.3  The most recentassessment of IP-3 issued on August 31, 2007 (ADAMS Ref. ML072430942), concluded thatthe plant's performance was in the Regulatory Response Column of the NRC's Action Matrixbased on one White performance indicator in the Initiating Events cornerstone. Subsequently,IP-3 performance transitioned back to the Licensee Response Column when the PI returned tothe Green band at the end of the third quarter of 2007. Because the findings of this ComponentDesign Bases Inspection were all Green, the NRC's overall assessment of IP-3 will not changefrom the Licensee Response Column as a result of this inspection. The recent assessment alsodiscussed an existing substantive cross-cutting issue in the area of human performanceregarding procedure adequacy. The Reactor Oversight Process considers that the areas ofhuman performance, problem identification and resolution and safety conscious workenvironment, contain performance attributes that extend across (cross-cut) all areas of reactorplant operation. As noted in the inspection report, two of the findings had a cross-cuttingaspect. As part of the assessment process, the NRC performs a collective review semi-annually of cross-cutting aspects of all inspection results from the previous twelve months, andmonitors and evaluates a plant licensee's actions to address a substantive cross-cutting issue. This inspection is a key part of NRC's inspection effort to assure overall plant safety, protectionof the public and the environment, and efficacy of key plant design features and procedures. Many other NRC inspection and review activities are also important to NRC's role of ensuringsafety. More detail is provided in the NRC's description of the Reactor Oversight Process athttp://www.nrc.gov/NRR/OVERSIGHT/ASSESS/index.html. A similar inspection was completed for the Indian Point Nuclear Generating Unit 2 on February 15, 2007 (ADAMS Ref.ML070890270).
==Dear Mr. Dacimo:==
On May 17, 2007, the NRC completed a triennial fire protection team inspection at your IndianPoint Nuclear Generating Unit 2. The enclosed report documents the inspection results, which were discussed at an exit meeting on [[Exit meeting date::May 17, 2007]], with you 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.


EnclosureviSUMMARY OF FINDINGSIR 05000286/2007-006; 10/01/2007 - 12/18/2007; Indian Point Nuclear Generating Unit 3;Component Design Bases Inspection.This inspection covers the Component Design Bases Inspection, conducted by a team of fiveNRC inspectors and three NRC contractors. Six findings of very low safety significance (Green)were identified, five of which involved a violation of regulatory requirements and wereconsidered to be non-cited violations. The significance of most findings is indicated by theircolor (Green, White, Yellow, Red) using IMC 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level afterNRC management review. The NRC's program for overseeing the safe operation ofcommercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"Revision 4, dated December 2006.A.NRC-Identified and Self-Revealing Findings
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, no findings of significance were identified.


===Cornerstone: Mitigating Systems===
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/ADAMS.html (the Public Electronic Reading Room).
: '''Green.'''
The team identified a finding of very low significance involving a non-citedviolation of 10 CFR 50, Appendix B, Criterion III, "Design Control," in that Entergy did notuse an adequate methodology to determine if the residual heat removal pump dischargeheader isolation valve (AC-MOV-744) was susceptible to the pressure lockingphenomenon. Additionally, the operation of the isolation valve seal water system(IVSWS) was not included in either the pressure locking analysis or actuator capabilitycalculations. In response, Entergy performed a calculation using an appropriatemethodology and as-found leak test results and determined that the valve would notpressure lock. Entergy also performed a calculation which verified that the valveactuator had sufficient margin to overcome the pressure applied by the IVSWS. Entergyentered these performance deficiencies into their corrective action program for longerterm resolution.The finding is more than minor because the methodology and calculation deficienciesrepresented reasonable doubt regarding the operability of the AC-MOV-744 valve, eventhough the valve was ultimately shown to be operable. The finding is associated withthe design control attribute of the Mitigating Systems cornerstone and affected thecornerstone objective of ensuring the availability, reliability, and capability of systemsthat respond to initiating events to prevent undesirable consequences. In accordancewith NRC Inspection Manual Chapter (IMC) 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," the teamconducted a Phase 1 screening and determined the finding was of very low safetysignificance because it was a design deficiency that did not result in a loss of valveoperability.  (Section 1R21.2.1.2)*Green. The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergyhad not verified the adequacy of design for the turbine driven auxiliary feedwater(TDAFW) pump. Specifically, the pump hydraulic analysis was non-conservative, butwas used to verify adequacy of surveillance test acceptance criteria for pump minimum Enclosureviidischarge pressure. Entergy subsequently verified that the pump remained operableand entered the finding into their corrective action program to revise the systemanalysis.The finding is more than minor because the design analysis deficiency resulted in acondition where there was reasonable doubt regarding TDAFW pump operability. Thefinding was associated with the design control attribute of the Mitigating Systemscornerstone and affected the cornerstone objective of ensuring availability, reliability andcapability of systems that respond to initiating events to prevent undesirableconsequences. In accordance with NRC Inspection Manual Chapter (IMC) 0609,Appendix A, "Significance Determination of Reactor Inspection Findings for At-PowerSituations," the team conducted a Phase 1 screening and determined the finding was ofvery low safety significance because it was a design deficiency that did not result in aloss of pump operability. The finding had a cross-cutting aspect in the ProblemIdentification and Resolution area, because Entergy did not thoroughly evaluate a similarproblem, such that the extent of condition adequately considered and resolved thecause.  (IMC 0305, aspect P.1(c))  (Section 1R21.2.1.6)*Green. The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergydid not ensure a change to the design basis was correctly translated into maintenanceprocedures. Specifically, a modification replaced the control element in the emergencydiesel generator (EDG) jacket water temperature control valves, with a control elementwith a higher setpoint, to support EDG operation at a higher service water temperature. Subsequently, using the uncorrected procedure, maintenance technicians re-installedelements with the lower setpoint. Entergy subsequently verified that the EDGs remainedoperable and entered the finding into their corrective action program to revise themaintenance procedure and replace the temperature control elements.The finding is more than minor because the failure to update the maintenance procedureresulted in a diesel engine configuration different than that required to operate atmaximum design cooling water specifications. The finding was associated with thedesign control attribute of the Mitigating Systems cornerstone and affected thecornerstone objective of ensuring availability, reliability and capability of systems thatrespond to initiating events to prevent undesirable consequences. In accordance withNRC Inspection Manual Chapter (IMC) 0609, Appendix A, "Significance Determination ofReactor Inspection Findings for At-Power Situations," the team conducted a Phase 1screening and determined the finding was of very low safety significance because it wasa design deficiency that did not result in a loss of EDG operability. (Section 1R21.2.1.7)*Green. The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR 50, Appendix B, Criterion III, "Design Control," in that measures hadnot been established to verify the proper component operating voltage requirements forbattery sizing calculations. Specifically, the battery calculations did not properly verifythat the minimum voltage needed to operate four-pole Agastat 7000 series timing relayswould be available. Entergy reviewed the most recent battery discharge tests to ensurethe error did not impact battery or relay operability and entered the issue into thecorrective action program to resolve the calculation errors.


EnclosureviiiThe finding is more than minor because it is associated with the design control attributeof the Mitigating System cornerstone and affected the cornerstone objective of ensuringthe availability, reliability, and capability of systems that respond to initiating events toprevent undesirable consequences. In accordance with NRC Inspection ManualChapter (IMC) 0609, Appendix A, "Significance Determination of Reactor InspectionFindings for At-Power Situations," the team conducted a Phase 1 screening anddetermined the finding was of very low safety significance because it was a designdeficiency that did not result in a loss of battery or relay operability. (Section1R21.2.1.11)*Green. The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that Entergydid not ensure that design inputs in the EDG load analysis were conservative. As aresult, capacity testing for EDG 32 was not sufficient to envelope the design basis loadrequirement at the maximum frequency limit allowed by Technical Specifications. Entergy reviewed the calculation errors and determined EDG operability was notaffected and entered the issues into the corrective action program to resolve thecalculation errors.The finding is more than minor because it is associated with the design control attributeof the Mitigating Systems cornerstone and affected the cornerstone objective to ensurethe availability, reliability, and capability of systems that respond to initiating events toprevent undesirable consequences. In accordance with NRC Inspection ManualChapter (IMC) 0609, Appendix A, "Significance Determination of Reactor InspectionFindings for At-Power Situations," the team conducted a Phase 1 screening anddetermined the finding was of very low safety significance because it was a designdeficiency that did not result in a loss of EDG operability.  (Section 1R21.2.1.13)*Green. The team identified a finding of very low safety significance involving the failureto perform a transformer bushing power factor (Doble) test within Entergy, vendor, orindustry recommended frequencies. Entergy had not performed this test on the stationauxiliary transformer (SAT) bushings since 1999, and had re-scheduled a 2007 test for2009. Specifically, a ten year interval between tests significantly exceeds Entergy'smaintenance procedure specification to perform testing every 4 years as well as thebushing manufacturer and industry recommended test frequencies. Additionally,Entergy did not provide an appropriate technical bases for deferring the test beyond thenormal interval. Entergy evaluated the 1999 test results and the SAT's current operatinghistory, concluded the SAT remained operable, and entered this condition into thecorrective action program. The finding is more than minor because it is associated with the equipment performanceattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability and capability of systems that respond to initiatingevents to prevent undesirable consequences. In accordance with NRC InspectionManual Chapter (IMC) 0609, Appendix A, "Significance Determination of ReactorInspection Findings for At-Power Situations," the team conducted a Phase 1 screeningand determined the finding was of very low safety significance because it was not adesign or qualification deficiency, did not result in an actual loss of safety function, anddid not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The finding had a cross-cutting aspect in the Human Performance -Work Control area, because Entergy had not adequately considered risk insights, job Enclosureixsite conditions (i.e., outside work during winter) did not support the test activity, andthere was no planned contingency if the work could not be accomplished within itsscheduled work window.  (IMC 0305, aspect H.3(a))  (Section 1R21.2.1.14)
Sincerely,/RA/John F. Rogge, ChiefEngineering Branch 3 Division of Reactor SafetySUNSI Review Complete: JFR (Reviewer's Initials
)DOCUMENT NAME: C:\FileNet\ML071730036.wpdAfter declaring this document "An Official Agency Record" it will be released to the Public.To receive a copy of this document, indicate in the box:
" C" = Copy withoutattachment/enclosure " E" = Copy with attachment/enclosure " N" = No copyOFFICERI/DRSNRI/DRPRI/DRSNAMERFuhrmeister/RFECobey/JDO forJRogge/JFRDATE06/7/0706/14/0706/20/07OFFICIAL RECORD COPY* See Previous Concurrence PageADAMS ACC # ML071730036 F. Dacimo2Docket No. 50-247License No. DPR-26


===B.Licensee-Identified Violations===
===Enclosure:===
None 1RAW is the factor by which the plant's core damage frequency increases if thecomponent or operator action is assumed to fail.2RRW is the factor by which the plant's core damage frequency decreases if thecomponent or operator action is assumed to be successful.Enclosure
NRC Inspection Report 05000247/2007006 cc w/encl:G. J. Taylor, Chief Executive Officer, Entergy Operations M. Kansler, President, Entergy Nuclear Operations, Inc.


=REPORT DETAILS=
J. T. Herron, Senior Vice President for Operations M. Balduzzi, Senior Vice President, Northeastern Regional Operations W. Campbell, Senior Vice President of Engineering and Technical Services C. Schwarz, Vice President, Operations Support (ENO)
1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R21Component Design Bases Inspection (IP 71111.21).1Inspection Sample Selection ProcessThe team selected risk significant components and operator actions for review usinginformation contained in the Indian Point 3 Probabilistic Risk Assessment (PRA) and theNuclear Regulatory Commission's (NRC) Standardized Plant Analysis Risk (SPAR)model. Additionally, the Indian Point 3 Significance Determination Process (SDP)Phase 2 Notebook, Revision 2, was referenced in the selection of potential componentsand actions for review. In general, the selection process focused on components andoperator actions that had a risk achievement worth (RAW)1 factor greater than 2.0 or aRisk Reduction Worth (RRW)2 factor greater than 1.005. The components selectedwere located within both safety related and non-safety related systems, and included avariety of components such as pumps, valves, diesel generators, transformers, batteriesand electrical buses.The team initially compiled an extensive list of components based on the risk factorspreviously mentioned. The team performed a margin assessment to narrow the focus ofthe inspection to 20 components and five operator actions. The team's evaluation ofpossible low design margin considered original design issues, margin reductions due tomodifications, or margin reductions identified as a result of material condition/equipmentreliability issues. The margin assessment evaluated the impact of licensing basischanges that could reduce safety analysis margins. The assessment also includeditems such as failed performance test results, corrective action history, repeatedmaintenance, maintenance rule (a)(1) status, operability reviews for degradedconditions, NRC resident inspector input of equipment problems, plant personnel input ofequipment issues, system health reports and industry operating experience. Consideration was also given to the uniqueness and complexity of the design and theavailable defense-in-depth margins. The margin review of operator actions includedcomplexity of the action, time to complete action, and extent of training on the action.This inspection effort included walk-downs of selected components, a review of selectedsimulator scenarios, interviews with operators, system engineers and design engineers,and reviews of associated design documents and calculations to assess the adequacyof the components to meet both design basis and risk informed beyond design basisrequirements. A summary of the reviews performed for each component, operatoraction, operating experience sample, and the specific inspection findings identified are 2Enclosurediscussed in the following sections of the report. Documents reviewed for this inspectionare listed in the Attachment..2Results of Detailed Reviews.2.1 Detailed Component Design Reviews (20 Samples).2.1.1No. 33 Safety Injection Pump
K. Polson, General Manager Operations O. Limpias, Vice President, Engineering (ENO)
J. McCann, Director, Licensing (ENO)
C. D. Faison, Manager, Licensing (ENO)
R. Patch, Director of Oversight (ENO)
J. Comiotes, Director, Nuclear Safety Assurance P. Conroy, Manager, Licensing T. C. McCullough, Assistant General Counsel, Entergy Nuclear Operations, Inc.


====a. Inspection Scope====
M. Balboni, Deputy Secy, New York State Energy, Research and Development Authority P. Eddy, Electric Division, New York State Department of Public Service C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law D. O'Neill, Mayor, Village of Buchanan J. G. Testa, Mayor, City of Peekskill R. Albanese, Four County Coordinator S. Lousteau, Treasury Department, Entergy Services, Inc.
The team reviewed design basis documents, including hydraulic calculations, technicalspecifications, accident analyses and drawings to verify that the safety injection (SI)pump was capable of meeting system functional and design basis requirements. Therefueling water storage tank (RWST) level setpoints and uncertainty calculations werealso reviewed because the RWST is the water source for the SI pump during theinjection phase of a postulated accident. The team also reviewed SI pump surveillancetest results, system health reports, and corrective action documents to determinewhether SI pump design margins were adequately maintained and to verify that Entergyentered problems that could affect system performance into their corrective actionprogram. The team reviewed operating and emergency operating procedures to assesswhether sufficient RWST inventory existed to inject water into the reactor vessel during apostulated accident, and to verify whether pump suction swap-over occurred before theonset of vortexing at the RWST outlet piping. To assess the general condition of thepump, the team performed walkdowns of the SI pump area. The team also reviewed SIpump and motor cooling systems and SI pump minimum flow requirements to assessthe ability of the SI pump to operate under design basis conditions.


====b. Findings====
Chairman, Standing Committee on Energy, NYS Assembly Chairman, Standing Committee on Environmental Conservation, NYS Assembly Chairman, Committee on Corporations, Authorities, and Commissions M. Slobodien, Director, Emergency Planning B. Brandenburg, Assistant General Counsel Assemblywoman Sandra Galef, NYS Assembly County Clerk, Westchester County Legislature A. Spano, Westchester County Executive R. Bondi, Putnam County Executive C. Vanderhoef, Rockland County Executive E. A. Diana, Orange County Executive T. Judson, Central NY Citizens Awareness Network M. Elie, Citizens Awareness Network D. Lochbaum, Nuclear Safety Engineer, Union of Concerned Scientists Public Citizen's Critical Mass Energy Project M. Mariotte, Nuclear Information & Resources Service F. Zalcman, Pace Law School, Energy Project L. Puglisi, Supervisor, Town of Cortlandt Congressman John Hall Congresswoman Nita Lowey Senator Hillary Rodham Clinton Senator Charles Schumer G. Shapiro, Senator Clinton's Staff J. Riccio, Greenpeace F. Dacimo3P. Musegaas, Riverkeeper, Inc.M. Kaplowitz, Chairman of County Environment & Health Committee A. Reynolds, Environmental Advocates M. Jacobs, Director, Longview School D. Katz, Executive Director, Citizens Awareness Network S. Tanzer, The Nuclear Control Institute K. Coplan, Pace Environmental Litigation Clinic M. Jacobs, IPSEC D. C. Poole, PWR SRC Consultant W. Russell, PWR SRC Consultant W. Little, Associate Attorney, NYSDEC M. J. Greene, Clearwater, Inc R. Christman, Manager Training and Development J. Spath, New York State Energy Research, SLO Designee A. J. Kremer, New York Affordable Reliable Electricity Alliance (NY AREA)
No findings of significance were identified..2.1.2Residual Heat Removal Pump Discharge Header Isolation Valve (AC-MOV-744)
F. Dacimo4Distribution w/encl:(via E-mail)
S. Collins, RAM. Dapas, DRA J. Lamb, RI OEDO J. Lubinski, NRR M. Kowal, NRR J. Boska, PM, NRR J. Hughey, NRR E. Cobey, DRP D. Jackson, DRP M. Cox, DRP, Senior Resident Inspector - Indian Point 2 G. Bowman, DRP, Resident Inspector - Indian Point 2 R. Martin, DRP, Resident OA Region I Docket Room (w/concurrences)
ROPreports@nrc.gov M. Gamberoni, DRS J. Rogge, DRS R. Fuhrmeister, DRP EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION IDocket No.50-247 License No.DPR-26 Report No.05000247/2007006 Licensee:Entergy Nuclear Northeast (Entergy)
Facility:Indian Point Nuclear Generating Unit 2 Location:450 Broadway, GSBBuchanan, NY 10511-0249Dates:April 23, 2007 through April 27, 2007 andMay 14, 2007 through May 18, 2007Inspectors:R. Fuhrmeister, Senior Project Engineer, DRPL. Cheung, Senior Reactor Inspector, DRS M. Patel, Reactor Inspector, DRS K. Diederich, Reactor Inspector, DRSApproved by:John F. Rogge, ChiefEngineering Branch 3 Division of Reactor Safety Enclosure


====a. Inspection Scope====
=SUMMARY OF FINDINGS=
The team selected the residual heat removal (RHR) pump discharge header isolationmotor operated valve (MOV), AC-MOV-744, as a representative high risk MOV sample. The team reviewed calculations, procedures, leakage test results and technical reportsto verify the valve's capability to perform during postulated design basis accidentconditions. The team also interviewed engineers and reviewed correspondence relatedto NRC Generic Letter 95-07, "Pressure Locking and Thermal Binding of Safety-RelatedPower-Operated Gate Valves," to verify that Entergy was meeting its commitments toensure the valve would not be susceptible to the pressure locking or thermal bindingphenomena. Analysis methodology reports were reviewed to determine if appropriateinputs were being used to support the conclusion that the valve was not susceptible topressure locking. Corrective action reports and preventive maintenance work orderswere reviewed in order to assess the performance and operational history of the valve.
IR 05000247/2007006; 04/23 - 05/18/2007; Indian Point Nuclear Generating Unit 2; TriennialFire Protection Team Inspection.The report covered a two-week triennial fire protection team inspection by a Region I seniorproject inspector and three Region I specialist inspectors. The NRC's program for overseeingthe safe operation of commercial nuclear power reactors is described in NUREG-1649,


====b. Findings====
"Reactor Oversight Process," Revision 3, dated July 2000.A.


=====Introduction:=====
===NRC-Identified Findings===
The team identified a finding of very low significance (Green) involving anon-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," in thatEntergy did not use an adequate methodology to determine if AC-MOV-744 wassusceptible to the pressure locking phenomenon. Additionally, the operation of theisolation valve seal water system (IVSWS) was not included in either the pressurelocking analysis or actuator capability calculations.Description:  The team found that Entergy used an inadequate methodology todetermine if valve AC-MOV-744 was susceptible to pressure locking. Specifically,Entergy used an incorrect and non-conservative valve bonnet depressurization rate,which was based on a generic Westinghouse report (ESBU/WOG-96-022) that creditedleakage from the valve bonnet past the valve seats and past the stem packing, to verifythat the valve bonnet would not pressurize under postulated design basis conditions dueto thermal inputs. This depressurization rate was inappropriately used in conjunctionwith a pressurization rate from another Westinghouse report (V-EC-1620) which alsocredited leakage from the bonnet. Additionally, the calculation used to determine thetemperature change of the water in the bonnet post-accident did not include heat inputsdue to conduction from the downstream piping and from the valve yoke and actuator.The team also determined that the IVSWS could be actuated during a postulated designbasis accident, after long term recirculation flow is established using the internalrecirculation system. The IVSWS uses pressurized nitrogen applied to the bonnet ofAC-MOV-744 in order to reduce leakage from containment following a loss-of-coolantaccident (LOCA). Following establishment of internal recirculation flow and a postulatedpassive failure of the internal recirculation discharge header, AC-MOV-744 would haveto reopen against the pressure applied by the IVSWS in order for long term recirculationflow to be established using the RHR system. Neither valve capability calculations northe pressure locking analysis accounted for actuation of the IVSWS. In response to this issue, Entergy performed a calculation using an appropriatemethodology and used as-found leakage test results to determine that the valve wouldnot become pressure locked. Entergy also performed a calculation to show that thevalve actuator had sufficient margin to overcome the pressure applied by the IVSWS.Entergy's immediate corrective actions included performing the calculations discussedabove and performing the associated operability determinations. The team reviewed thecalculations and operability assessments for the pressure locking and IVSWS issuesand found them to be acceptable. The team verified that the deficiencies did not impactthe operability of the valve. Entergy entered these performance deficiencies into theircorrective action program for longer term resolution.Analysis:  The team determined that Entergy's failure to use a correct methodologywhen evaluating AC-MOV-744 for pressure locking represented a performancedeficiency that was reasonably within Entergy's ability to foresee and prevent. Specifically, Entergy did not use a correct methodology when evaluating the valve for 43Subsequent to the inspection, the Phase 1 screening process remained unchanged butwas moved from IMC0609, Appendix A, to IMC0609, Attachment 4, "Phase 1 - Initial Screeningand Characterization of Findings."Enclosurethermally induced pressure locking, nor did Entergy include the potential actuation of theIVSWS in the evaluation or design inputs for the valve.The finding was more than minor because it was similar to NRC Inspection ManualChapter 0612, Appendix E, "Examples of Minor Issues," Example 3.j, in that themethodology and calculation deficiencies represented reasonable doubt regarding theoperability of AC-MOV-744. The finding was associated with the design control attributeof the Mitigating Systems cornerstone and affected the cornerstone objective of ensuringthe availability, reliability, and capability of systems that respond to initiating events toprevent undesirable consequences. Traditional enforcement does not apply becausethe issue did not have any actual safety consequences or potential for impacting theNRC's regulatory function, and was not the result of any willful violation of NRCrequirements. In accordance with NRC Inspection Manual Chapter 0609, Appendix A,"Significance Determination of Reactor Inspection Findings for At-Power Situations," theteam conducted a Phase 1 SDP screening3 and determined the finding was of very lowsafety significance (Green) because it was a design deficiency that was confirmed not toresult in a loss of AC-MOV-744 operability.Enforcement:  10 CFR 50 Appendix B, Criterion III, "Design Control," requires, in part,that measures shall provide for verifying or checking the adequacy of design. Contraryto the above, as of November 8, 2007, Entergy's design control measures were notadequate to verify the adequacy of the design of the RHR pump discharge headerisolation valve (AC-MOV-744). Specifically, Entergy did not use an appropriatemethodology to evaluate the potential for pressure locking of valve AC-MOV-744. Because this violation is of very low safety significance and has been entered intoEntergy's corrective action program (CR-IP3-2007-04204 and CR-IP3-2007-04217), thisviolation is being treated as a non-cited violation consistent with Section VI.A.1. of theNRC Enforcement Policy.  (NCV 05000286/2007006-01, Inadequate Pressure LockingMethodology Used to Ensure Valve Operability)
No findings of significance were identified.


===.2.1.3 Service Water Pump 31===
===B.Licensee-Identified Violations===
 
====a. Inspection Scope====
The team evaluated the service water (SW) pump and strainer to verify that the pumpand strainer performance satisfied design basis flow rate requirements during postulatedtransient and accident conditions, and to assess the potential for common cause failureof the pumps or strainers. To determine design basis performance requirements andoperational limitations, the team reviewed design basis documents including SW systemhydraulic models and flow balance studies, calculations, operating instructions andprocedures, system drawings, surveillance tests, and modifications. The team verifiedthat design requirements and operational limits were properly translated into operatinginstructions, and procedures. Surveillance test results were reviewed to determine 5Enclosurewhether established test acceptance criteria were satisfied. The acceptance criteriawere compared to design basis assumptions and requirements to verify there wereadequate margins for allowable pump degradation limits, strainer clogging affects, andavailable net positive suction head (NPSH) to ensure actual pump and strainerperformance would be satisfactory during transient and accident conditions. In addition,the team walked down the SW pump house and strainer areas, interviewed system anddesign engineers, and reviewed system health reports and selected condition reports toassess the current material condition of the pumps and strainers.


====b. Findings====
None.
No findings of significance were identified..2.1.4Recirculation Pump 32


====a. Inspection Scope====
Enclosure
The team evaluated the recirculation pump to verify that pump performance, duringpostulated accident conditions, would satisfy design basis head and flow raterequirements, and to assess the potential for common cause failure of the recirculation pumps. To determine design basis performance requirements and operationallimitations, the team reviewed design basis documents including NPSH analysis,certified pump curves, technical specifications, accident analysis, and system andvendor drawings. The team assessed whether the licensee adequately translateddesign requirements and operational limits into operating instructions, procedures, andemergency operating procedures. Post modification and surveillance test results werereviewed to determine whether established test acceptance criteria were satisfied. Theacceptance criteria were compared to design basis assumptions and requirements todetermine there were adequate margins for allowable pump degradation limits, minimumpump flow, and available NPSH, to ensure actual pump performance would besatisfactory during accident conditions. In addition, the team interviewed designengineers, system engineers and licensed operators, and reviewed selected conditionreports to identify any potential adverse conditions or trends.


====b. Findings====
=REPORT DETAILS=
Inadequate Design Control of Recirculation PumpsThe team identified an unresolved item concerning the adequacy of design controlassociated with a modification that replaced both internal recirculation pumps in March2007. Specifically, Entergy did not evaluate or determine the minimum flow requirements for the new pumps and did not evaluate or determine whether the newpumps would be susceptible to strong-pump to weak-pump interactions, when operatedin parallel.
BackgroundThis report presents the results of a triennial fire protection inspection conducted in accordancewith NRC Inspection Procedure (IP) 71111.05T, "Fire Protection." The objective of the inspection was to assess whether Entergy Nuclear Northeast has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are being properly maintained at the Indian Point Energy Nuclear Generating Unit 2 (IP2). The following fire areas (FAs) and fire zones (FZs) were selected for detailed review based on risk insights from the IP2 Individual Plant Examination (IPE) and Individual Plant Examination ofExternal Events (IPEEE):Fire Area P, FZ-1Fire Area A, FZ-1AFire Area A, FZ-11Fire Area I, FZ-22/63AThe inspection team evaluated Entergy's fire protection program (FPP) against applicablerequirements which included facility operating license condition 2.K, NRC safety evaluation reports, 10 CFR 50.48 and 10 CFR 50, Appendix R. The team also reviewed related documents that included the Updated Final Safety Analysis Report (UFSAR), the fire hazards analysis (FHA) and the post-fire safe shutdown analysis (SSA).Specific documents reviewed by the team are listed in the attachment.1.REACTOR SAFETYCornerstones:  Initiating Events, Mitigating Systems1R05Fire Protection
 
6EnclosureBackgroundThe recirculation pump portion of the low-head safety injection system consists of twopumps, located in primary containment, that take suction from a containment sump anddischarge into a common discharge header. Each recirculation pump has a 3/4 inchminimum flow line upstream of the pump discharge check valve and the two pumpsshare a 2 inch minimum flow line on the common discharge header. All three minimumflow lines return to the containment sump. Emergency operating procedure (EOP)ES-1.3, "Transfer to Cold Leg Recirculation," directed operators to sequentially start bothrecirculation pumps during the recirculation phase of a loss-of-coolant accident (LOCA).Strong-pump to Weak-pump InteractionNRC Bulletin 88-04, "Safety-Related Pump Loss," documented industry operatingexperience regarding design deficiencies where the weaker centrifugal pump (i.e., lowerdischarge head at same flow rate) could be dead-headed under low flow conditionswhen operated in parallel with a stronger pump (i.e., higher discharge head at same flowrate), if both pumps shared a common minimum flow line. Letter IP3-89-036, dated May 12, 1989, provided the licensee's Bulletin 88-04 responseto the NRC. The licensee stated that although the recirculation pumps shared acommon minimum flow line, the potential for a stronger pump to dead-head a weakerpump did not exist. The basis, in part, was that having the individual pump minimumflow lines upstream of the pump discharge check valve would ensure flow through thepump even if the stronger pump would cause the discharge check valve on the weakerpump to close. The licensee also credited the EOPs with preventing the weak pumpfrom becoming dead-headed because they assumed that by the time the EOPs directedstarting of the second pump, flow to the reactor core would be sufficient to allow bothpumps to operate at a point on their head verses flow curves where there was adequateflow for both pumps.The team's review of the recirculation pump curves identified that the No. 32recirculation pump had about 10 psi higher discharge head, under low flow conditions,than the No. 31 recirculation pump. The team determined that the No. 31 recirculationpump would likely be susceptible to dead-heading if both pumps were operated inparallel, as required by procedure ES-1.3, and at a low system flow rate, which might beencountered during certain small break LOCAs, such as high head recirculation. Theteam noted that the system valve line-up required the 3/4 inch minimum flow valve to bethrottled to 1.5 turns open, resulting in very low flow through these lines. The mostrecent surveillance test results recorded the as-found flows as approximately zero(No. 31 pump was 0.1 gpm, No. 32 pump was 7 gpm). The team also identified thatEntergy had not assessed the new recirculation pumps for strong-pump to weak-pumpinteractions.
 
7EnclosureThe team concluded that Entergy had not verified the design adequacy for the newrecirculation pumps for strong-pump to weak-pump interaction. In addition, the previousengineering evaluation for recirculation pump strong-pump to weak-pump interactionappeared to be inconsistent with a small break LOCA accident analysis and with thethrottled configuration of the 3/4 inch minimum flow line. Entergy preliminarilydetermined the weaker pump was only susceptible to dead-heading during high headrecirculation (e.g., other small break LOCA scenarios would not result in weak pumpdead-heading). Entergy entered this issue into their corrective action program asCR-IP3-2007-04212. As an immediate corrective action, Entergy revised EOPs3-ES-1.3, "Transfer to Cold Leg Recirculation," and 3-ES-1.4, "Transfer to Hot LegRecirculation," to not start the second recirculation pump during high head recirculation.Minimum Flow RequirementsNRC Bulletin 88-04 also documented industry operating experience regarding designdeficiencies with individual pump minimum flow rates that did not prevent pump damagewhile operating in the minimum flow mode. Based on Westinghouse analysis SECL-89-508, dated May 22, 1989, the licensee determined that the recirculation pumpmechanical minimum flow rate (flow required to prevent pump mechanical damage atlower than design flow rates) and the thermal minimum flow rate (flow required toprevent fluid inside the pump from reaching saturation conditions) were adequate for alloperational modes except surveillance testing. The lower flow rates during testing wereevaluated as acceptable because of the short test duration and infrequent test times. SECL-89-508 Table-1, "Required Minimum Flow vs. Actual Flow Rates," stated for thesmall break LOCA operating mode and a 24-hour duration, recirculation pump total flowwas 1000 gpm, with a minimum required thermal and mechanical flow of 540 gpm.The team identified that design drawing IP3V-2057-0010, "Flowserve RecirculationPump Replacement," stated that sustained pump operation below 900 gpm should beavoided. In addition, the new recirculation pumps had a different suction stage designthan the previous pumps. The team determined that EOP ES-1.3 would allow parallelpump operation if the total system flow was greater than approximately 1440 gpm, notincluding 130 gpm in the common minimum flow line. Since this would result in a totalsystem flow of 1570 gpm, possibly with both pumps operating, the team questionedwhether there were any LOCA scenarios where an individual pump flow might be lessthan 900 gpm. The team determined that Entergy had not evaluated the newrecirculation pumps for thermal or mechanical minimum flow requirements, and had notverified whether the previous 18 year old minimum flow analysis was applicable to thenew pumps. Entergy entered this issue into their corrective action program as CR-IP3-2007-04296.Current Recirculation Pump OperabilityEntergy preliminarily determined that the recirculation pumps were potentiallysusceptible to adverse effects from strong-pump to weak-pump interactions and frominadequate minimum flow protection only during small break LOCA scenarios. Entergyis continuing to evaluate pump susceptibility to adverse affects during other (i.e., non-small break LOCA) scenarios.
 
8EnclosurePreliminary hydraulic analysis, performed by Entergy, indicated that the highestcontainment sump water temperature for a small break LOCA was about 195 degreesFahrenheit (F). Entergy received an initial evaluation for minimum flow from the pumpvendor (Flowserve) in a letter dated November 9, 2007, which stated, in part, that while900 gpm is recommended for continuous operation, 200 gpm is acceptable for up to athree hour duration in any 24 hour period. In addition, Flowserve stated that if thesuction water temperature was less than or equal to 200F, and the temperature rise inthe pump did not result in flashing, then extended operation would only result inshortened pump life (i.e., not a short term pump failure). Based on the preliminaryinformation, Entergy concluded that the pumps will operate satisfactorily under all designbasis accident conditions. The team evaluated Entergy's immediate corrective actions,including EOP changes, and Entergy's operability assessment and found these actionsand assessments to be reasonable. Entergy is evaluating recirculation system hydraulic models and small break LOCAaccident scenarios to determine expected minimum reactor core flows and individualpump flows. In addition, Entergy is evaluating recirculation pump design characteristicsto determine pump minimum flow requirements. The acceptability of Entergy's finaldetermination of pump minimum flow requirements will be an unresolved item (URI),pending further NRC review.  (URI 05000286/2007006-02, Inadequate Design Controlof Recirculation Pumps).2.1.5Auxiliary Feedwater Pump 31 (Motor Driven)
 
====a. Inspection Scope====
The team reviewed the motor driven auxiliary feedwater (MDAFW) pump to verify thatthe pump was capable of achieving its design basis requirements. The review includedan assessment of the design capacity of the condensate storage tank, ability to transferthe pump suction to an alternate water source, available net positive suction head,margin to prevent vortexing, pump minimum flow and run-out protection, andenvironmental and electrical qualification of equipment. The team reviewed drawings,calculations, hydraulic analyses, procedures, system health reports, and selectedcondition reports to evaluate whether maintenance, testing, and operation of theMDAFW pump were adequate to ensure the pump performance would satisfy designbasis requirements under transient and accident conditions. Surveillance test resultswere reviewed to assess whether the pump was operated within acceptable limits, andto verify whether established test acceptance criteria were satisfied. The testacceptance criteria were compared to design basis assumptions and requirements todetermine whether there were adequate margins to ensure actual pump performancewould be satisfactory during transient and accident conditions. The team performed awalkdown of accessible areas of the auxiliary feedwater (AFW) system and supportingsystems to determine whether the system alignment was in accordance with designbasis and procedural requirements, and to assess the MDAFW pump and AFW systemcomponent material condition.


====b. Findings====
===.01 Post-Fire Safe Shutdown From Outside the Main Control Room (Alternative Shutdown)and Normal Shutdown===
No findings of significance were identified..2.1.6Auxiliary Feedwater Pump 32 (Turbine Driven)


====a. Inspection Scope====
====a. Inspection Scope====
The turbine driven auxiliary feedwater (TDAFW) pump was reviewed to assess its abilityto meet its design basis head and flow rate requirements in response to transient andaccident events. The team verified that the design inputs were properly translated intosystem procedures and tests, and reviewed completed surveillance tests associatedwith the demonstration of pump operability. Accident analysis evaluations for loss-of-normal feedwater were reviewed to determine whether appropriate design criteria for theTDAFW pump were used. The adequacy of the TDAFW pump for operation during astation blackout condition was reviewed. The team reviewed the design capacity of thecondensate storage tank (CST), which is the preferred water source for the system, andthe potential for vortexing at the pump suction line. The design and operatingprocedures for the service water system were reviewed with respect to supportingoperability of the TDAFW pump when the normal pump suction source (CST) isdepleted. The team also reviewed room temperature requirements and equipmentthermal design requirements to assess whether the TDAFW pump would operate withindesign temperature limits. Lastly, the team performed walkdowns to assess the generalcondition of the TDAFW pump.
MethodologyThe team reviewed the safe shutdown analysis, operating procedures, piping andinstrumentation drawings (P&IDs), electrical drawings, the UFSAR and other supporting documents to verify that hot and cold shutdown could be achieved and maintained from outside the control room for fires that rely on shutdown from outside the control room.
 
====b. Findings====
 
=====Introduction:=====
The team identified a finding of very low safety significance (Green)involving a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III,"Design Control," in that Entergy had not verified the adequacy of design for the TDAFWpump. Specifically, the pump hydraulic analysis was non-conservative, but was used toverify the adequacy of surveillance test acceptance criteria for pump minimum dischargepressure.Description:  The team reviewed calculation IP3-CALC-AFW-02581, "AFW PumpDischarge Pressure at Two Flow Rates 340 and 600 gpm."  The purpose of thecalculation was to verify the adequacy of the pump discharge pressure acceptancecriteria for TDAFW pump surveillance testing. The test acceptance criteria had beenestablished based on pump curves and allowances for pump degradation. The teamidentified that the analysis did not include the increased AFW flow requirements due tothe IP-3 stretch power uprate (SPU), and did not include the increased pressure at thepump discharge due to the back-pressure between the main steam safety valves(MSSVs) and the steam generators (SGs). As a result, the calculation predicted too lowof a value for pump discharge pressure, which resulted in a non-conservative valuebeing used to assess the adequacy of the pump surveillance test acceptance criteria.
 
10EnclosureEntergy determined the AFW system remained operable because the most recentsurveillance test results of the TDAFW pump documented an as-found pump dischargepressure greater than the value needed to account for the identified calculationdeficiencies. In addition, Entergy determined that the approved surveillance testacceptance criteria was greater than the value needed to account for the identified calculation deficiencies. The team independently verified there was adequate marginbetween a higher required minimum pressure value and the current test acceptancecriteria.
 
=====Analysis:=====
The team determined that the use of a non-conservative calculation to verifythe adequacy of surveillance test acceptance criteria was a performance deficiency. Entergy's design control measures were not adequate to ensure that a completeevaluation of TDAFW pump discharge pressure had been performed. Specifically, theTDAFW pump hydraulic analysis was used to verify adequate pump discharge pressurefor surveillance test procedures, but did not include increased AFW flow requirementsfrom the SPU, and did not include the back-pressure from the MSSVs to the SGs.The finding was more than minor because it was similar to NRC Inspection ManualChapter (IMC) 0612, Appendix E, "Examples of Minor Issues," Example 3.j, in that thedeficient hydraulic analysis resulted in a condition where there was a reasonable doubtwith respect to operability of the TDAFW pump. The finding was associated with thedesign control attribute of the Mitigating Systems cornerstone and affected thecornerstone objective of ensuring the availability, reliability, and capability of systemsthat respond to initiating events to prevent undesirable consequences. Traditionalenforcement does not apply because the issue did not have any actual safetyconsequences or potential for impacting the NRC's regulatory function, and was not theresult of any willful violation of NRC requirements. In accordance with NRC IMC 0609,Appendix A, "Significance Determination of Reactor Inspection Findings for At-PowerSituations," the team conducted a Phase 1 SDP screening and determined the findingwas of very low safety significance (Green) because it was a design deficiency that wasconfirmed not to result in a loss of TDAFW pump operability.This finding had a cross-cutting performance aspect in the area of Problem Identificationand Resolution. Specifically, this issue was the subject of CR-IP3-2007-03257, whichidentified the calculation for the MDAFW pumps required revision, in order to verifyadequacy of surveillance test acceptance criteria for pump minimum discharge pressure. Entergy did not thoroughly evaluate the similar problem that affected the TDAFW pump,such that the extent of condition adequately considered and resolved the cause.  (IMC0305, aspect P.1(c))Enforcement:  10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, inpart, that design control measures shall provide for verifying or checking the adequacyof design. Contrary to the above, as of November 8, 2007, Entergy's design controlmeasures were not adequate to verify the adequacy of design for the TDAFW pumpminimum discharge pressure. Specifically, the TDAFW pump hydraulic analysis, incalculation IP3-CALC-AFW-02581, Rev. 0, did not include increased flow requirementsfrom the SPU and did not include back-pressure from the MSSVs to the SGs. As aresult, the hydraulic analysis was non-conservative, but had been used to verify the 11Enclosureadequacy of surveillance test acceptance criteria. Because this violation was of very lowsafety significance and was entered into Entergy's corrective action program (CR-IP3-2007-04174), this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A.1 of the NRC Enforcement Policy.  (NCV 05000286/2007006-03,Non-Conservative Calculation for TDAFW Pump Discharge Pressure Used forSurveillance Testing).2.1.7No. 31 Emergency Diesel Generator (Mechanical)


====a. Inspection Scope====
This review included verification that shutdown from outside the control room could be performed both with and without the availability of offsite power. Plant walkdowns were also performed to verify that the plant configuration was consistent with that described in the safe shutdown and fire hazards analyses. These inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant 2Enclosuremakeup, reactor decay heat removal, process monitoring instrumentation and supportsystems functions. The team verified that the systems and components credited for use during post-fire safe shutdown would remain free from fire damage. The team verified that the transfer of control from the control room to the alternative shutdown locations would not be affected by fire-induced failures.Similarly, for fire areas that utilize shutdown from the control room, the team alsoverified that the shutdown methodology properly identified the components and systems necessary to achieve and maintain safe shutdown conditions. Operational ImplementationThe team verified that the training program for licensed and non-licensed operatorsincluded alternative shutdown capability. The team also verified that personnel required for safe shutdown using the normal or alternative shutdown systems and procedures were trained, available onsite at all times, and exclusive of those assigned as fire brigade members.The team reviewed the adequacy of procedures utilized for post-fire safe shutdown andperformed an independent walk through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also verified that operators could reasonably be expected to perform specific actions within the time required to maintain plant parameters within specified limits. Time critical actions which were verified included restoring alternating current (AC) electrical power, establishing alternate shutdown system operation, establishing reactor coolant makeup and establishing decay heat removal.Specific procedures reviewed for alternative shutdown, including shutdown from outsidethe control room included the following:2-AOP-SSD-1, Rev. 9, Control Room Inaccessibility Safe Shutdown Control2-ONOP-FP-001, Rev. 2, Plant FiresThe team reviewed manual actions to ensure that they had been properly reviewed andapproved and that the actions could be implemented in accordance with plant procedures in the time necessary to support the safe shutdown method for each selected fire area. The team also reviewed periodic testing records of the alternative shutdown transfer capability and instrumentation and control functions to ensure the tests demonstrated the functionality of the alternative shutdown capability.
The team reviewed emergency diesel generator (EDG) No. 31 to assess whether theEDG would function as required during postulated transient and accident conditions tomeet design basis requirements. The review included the fuel oil storage and supply,starting air, combustion air, and jacket water and lube oil cooling systems. The teamreviewed drawings, calculations, fuel oil transfer analyses, starting air capabilityanalyses, heat exchanger performance analyses, system health reports, and selectedcondition reports to evaluate whether maintenance, testing, and operation of the EDGsystems were adequate to ensure the EDG performance would satisfy design basisrequirements under transient and accident conditions. Surveillance test results werereviewed to assess whether actual EDG performance, including starting air receiverpressures and service water flow rates, adequately demonstrated design basisassumptions would be met, that the EDG was operated within acceptable limits, and toverify whether established test acceptance criteria were satisfied. The test acceptancecriteria were compared to design basis assumptions and requirements to determinewhether there were adequate margins to ensure actual EDG performance would besatisfactory during transient and accident conditions. The team walked down selectedaccessible components and areas associated with the EDG to assess proper componentalignment and verify whether any observed material conditions could adversely impactsystem operability.


====b. Findings====
====b. Findings====
No findings of significance were identified.


=====Introduction:=====
3Enclosure.02Protection of Safe Shutdown Capabilities
The team identified a finding of very low safety significance (Green)involving a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III,"Design Control," in that Entergy did not ensure a change to the design basis wascorrectly translated into maintenance procedures. Specifically, a modification replacedthe control element in the EDG jacket water temperature control valves, with a controlelement with a higher setpoint to support EDG operation at a higher SW temperature. Subsequently, the failure to properly update the affected maintenance procedure tospecify the correct control element resulted in maintenance technicians re-installingelements with the old setpoint.Description:  The team reviewed Modification 90-03-158, "EDG Jacket Water and LubeOil Cooling," to assess the EDG's capability to operate at a higher SW temperature. Thepurpose of the 1990 modification was to support a design basis change that increasedthe maximum operating SW temperature from 85F to 95F. To allow the EDGs tooperate at a 10F higher SW temperature, the licensee determined, in part, that the 12Enclosurejacket water outlet temperature needed to be increased from 180F to 190F, bychanging the operating setpoint of the three-way temperature control valve (TCV). TheTCV maintains the engine jacket water outlet temperature by controlling the quantity ofwater that bypasses the jacket water cooler. The modification installed a 180Fthermostatic element assembly in the EDG jacket water temperature control valves(TCV-31/32/33), in place of the original 170F elements. A 180F element, in the three-way TCV, is used to control temperature at 190F, due to thermal hydraulic hysteresis. The team identified that the licensee had not documented an evaluation of the impact ofa jacket water temperature increase on the performance of the combustion air aftercooler in either the modification package or in the supporting safety evaluation. Basedon additional vendor information, Entergy subsequently determined the jacket watertemperature increase did not adversely affect the after cooler performance or EDGoperation.While gathering data regarding EDG after cooler performance, Entergy determined thatthe 180F thermostatic elements, installed in 1990 by Modification 90-03-158, hadsubsequently been replaced with 170F elements, while performing routine preventivemaintenance using maintenance procedure 3-GNR-022-ELC, EDG 6-Year Inspection. The 180F elements were sized to maintain jacket water temperature within design limitsand prevent exceeding the maximum flow limits to the combustion air after cooler, for aSW temperature of 95F. Entergy determined the EDGs were currently operable, basedon river water (i.e., source of SW) temperature of approximately 50F, because the170F elements were originally sized to support EDG operation for a maximum SWtemperature of 85F. Entergy entered this issue into their corrective action program asCR-IP3-2007-04411, and issued a corrective action to replace the elements prior to rivertemperature exceeding 85F.The team identified that jacket water cooling flow thorough the after cooler would haveexceeded the after cooler design flow of 130 gpm, if the EDG were operated with the170F element and SW temperature at 95F. Based on additional vendor information,Entergy subsequently determined that the after cooler design flow was 130 gpm, with amaximum allowable flow of 150 gpm. Entergy initiated a past operability assessment todetermine whether SW temperature had exceeded 85F while the 170F thermostaticelements had been installed and, if so, to determine whether the after cooler flow wouldhave exceeded the maximum allowable value of 150 gpm.As an immediate corrective action, Entergy evaluated data during the previous two yearperiod and determined that the SW maximum temperature had not exceeded 85F,except for one day when the SW maximum temperature had been recorded as 85.8F. Entergy determined that a SW temperature of 85.8F would result in an after cooler flowonly slightly above the nominal design flow of 130 gpm. Therefore, Entergy concludedthe EDGs had remained operable during the prior 2 year period. The teamindependently reviewed the Indian Point Monthly Environmental Reports for the previous2 year period (October 1, 2005 to September 30, 2007), verified that the SW intakemaximum temperatures did not exceed 85F during that period (except for 1 day), andconcluded that Entergy's past operability assessment for the prior 2 years wasreasonable, based on the after cooler margin between the nominal design and maximumallowable flow rates.
 
13EnclosureAnalysis:  The team determined that the failure to properly update the affected maintenance procedure was a performance deficiency. Entergy's design controlmeasures did not ensure that a change to the design basis was correctly translated intomaintenance procedures. Specifically, a modification replaced the 170F controlelement in the EDG jacket water temperature control valves, with a 180F element, tosupport EDG operation at a higher SW temperature of 95F. Subsequently, using theuncorrected procedure, maintenance technicians re-installed 170F elements.The finding was more than minor because it was similar to NRC Inspection ManualChapter (IMC) 0612, Appendix E, "Examples of Minor Issues," Example 3.b, in that avalve design was changed, but a licensee oversight resulted in a failure to update aprocedure, which could adversely affect an EDG. The finding was associated with thedesign control attribute of the Mitigating Systems cornerstone and affected thecornerstone objective of ensuring the availability, reliability, and capability of systemsthat respond to initiating events to prevent undesirable consequences. Traditionalenforcement does not apply because the issue did not have any actual safetyconsequences or potential for impacting the NRC's regulatory function, and was not theresult of any willful violation of NRC requirements. In accordance with NRC IMC 0609,Appendix A, "Significance Determination of Reactor Inspection Findings for At-PowerSituations," the team conducted a Phase 1 SDP screening and determined the findingwas of very low safety significance (Green) because it was a design deficiency that wasconfirmed not to result in the loss of EDG operability.Enforcement:  10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, inpart, that measures shall be established to ensure that the design basis are correctlytranslated into specifications, drawings, procedures, and instructions. Contrary to theabove, as of November 8, 2007, Entergy's design control measures were not adequateto ensure that a change to the design basis was correctly translated into maintenanceprocedure 3-GNR-022-ELC. Specifically, in 1990, Modification 90-03-158 installed a180F thermostatic element assembly in the EDG jacket water temperature controlvalves, in place of the original 170F elements. The modification's purpose was tosupport a design basis change that increased the maximum operating SW temperaturefrom 85F to 95F. As a result of not revising the procedure, during routine preventivemaintenance, the correct 180F element was subsequently removed and replaced with a170F element, which could have adversely affected EDG operation at SWtemperatures greater than 85F. Because this violation was of very low safetysignificance and was entered into Entergy's corrective action program (CR-IP3-2007-04411), this violation is being treated as a non-cited violation (NCV), consistent withSection VI.A.1 of the NRC Enforcement Policy.  (NCV 05000286/2007006-04,Maintenance Procedure Not Revised after Emergency Diesel Modification).2.1.8 Residual Heat Removal Supply from Reactor Coolant System Isolation Valves(AC-MOV-730 and -731)


====a. Inspection Scope====
====a. Inspection Scope====
The team selected the residual heat removal supply from reactor coolant system isolation valves as a high risk sample and due to their unique operation in that they are 14Enclosureroutinely electrically backseated. The team reviewed calculations, MOV diagnostictests, the valve vendor manual, and system and component level drawings to verify thevalves' capability to perform during design basis accident scenarios. The teaminterviewed engineers and reviewed the actuator torque switch settings to verify thatstructural limits of the valves were not being exceeded when the valves werebackseated. NRC Information Notice (IN) 87-40, "Backseating Valves Routinely toPrevent Packing Leakage," was reviewed to determine if the station took appropriatemeasures to prevent failure of the valves. Condition reports were reviewed to determinethe historical performance of the valves and valve actuators.
The team reviewed the fire hazards analysis, safe shutdown analyses and supportingdrawings and documentation to verify that safe shutdown capabilities were properly protected. The team ensured that separation requirements of 10 CFR 50, Appendix R, Section III.G, were maintained for the credited safe shutdown equipment includingsupporting power, control and instrumentation cables. This review included an assessment of the adequacy of the selected systems for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring, and associated support system functions.The team reviewed Entergy's procedures and programs for the control of ignitionsources and transient combustibles to assess their effectiveness in preventing fires and controlling combustible loading within limits established in the Combustible Loading Calculation. A sample of hot work and transient combustible control permits were also reviewed. The team performed plant walkdowns to verify that protective features were being properly maintained and administrative controls were being implemented.The team also reviewed Entergy's design control procedures to ensure that the processincluded appropriate reviews and controls to assess plant changes for any potential adverse impact on the fire protection program, post-fire safe shutdown analysis, and procedures.


====b. Findings====
====b. Findings====
No findings of significance were identified..2.1.9Main Steamline Atmospheric Steam Dump Valves  (MS-PCV-1134, 1135, 1136, & 1137)
No findings of significance were identified..03Passive Fire Protection


====a. Inspection Scope====
====a. Inspection Scope====
The atmospheric steam dump valves were chosen as a representative high risk airoperated valve (AOV) sample. The team conducted interviews with engineers andreviewed system and component level calculations, procedures, valve diagnostic testresults, and trend data to verify the capabilities of MS-PCV-1134, 1135, 1136, and 1137to perform their intended function during postulated design basis accident conditions. The backup nitrogen supply system for the atmospheric steam dump valves wasreviewed to determine if design assumptions were supported by procedural operation ofthe system. Preventive maintenance requirements and corrective action reports werealso reviewed in order to determine the performance and operational history of thevalves.
The team walked down accessible portions of the selected fire areas to observe materialcondition and the adequacy of design of fire area boundaries (including walls, fire doors and fire dampers) to ensure they were appropriate for the fire hazards in the area.
 
====b. Findings====
No findings of significance were identified..2.1.10Motor Driven Auxiliary Feedwater Flow Control Valves (BFD-FCV-406A,B,C,D)
 
====a. Inspection Scope====
The MDAFW flow control valves were chosen as a representative high risk AOV sample. The team conducted interviews with engineers and reviewed calculations, procedures, and periodic verification and inservice test results to verify the capability of the BFD-FCV-406A, B, C, and D valves to perform their intended function during design basisconditions. The backup nitrogen supply for the AFW system was reviewed to determineif there was sufficient capacity to support design assumptions for system operationfollowing a loss-of-instrument air. Condition reports were reviewed to assess thecondition of the system and to verify previously identified issues had been properlyresolved.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


===.2.1.1 1Station Battery 31===
4Enclosure.04Active Fire Protection


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the station battery, and associated 125 Vdc switchgear, buses,chargers and inverters. The team reviewed the battery calculations to verify that thebattery sizing would satisfy the requirements of the risk significant loads and that theminimum possible voltage was taken into account. Specifically, the evaluation focusedon verifying that the battery and battery chargers were adequately sized to supply thedesign duty cycle of the 125 Vdc system, and that adequate voltage would remainavailable for the individual load devices required to operate during a two-hour copingduration. The team reviewed battery surveillance test results to verify that applicabletest acceptance criteria and test frequency requirements specified for the battery weremet. The team also reviewed condition reports and maintenance work orders for theassociated battery chargers and inverters as well as design change records for the 125Vdc system. The team interviewed design and system engineers regarding designaspects and operating history for the battery. In addition, a walkdown was performed tovisually inspect the physical condition of the station batteries, switchgear and batterychargers. During the walkdown, the team also visually inspected the battery for signs ofdegradation such as excessive terminal corrosion and electrolyte leaks.
The team reviewed the design, maintenance, testing and operation of the fire detectionand suppression systems in the selected plant fire areas. This included verification that the manual and automatic detection and suppression systems were installed, tested and maintained in accordance with the NFPA code of record and that they would control or extinguish fires associated with the hazards in the selected areas. A review of the design capability of suppression agent delivery systems were verified to meet the code requirements for the fire hazards involved. The team also performed a walkdown of accessible portions of the detection and suppressions systems in the selected areas as well as a walkdown of major system support equipment in other areas (e.g. fire protection pumps, Halon storage tanks and supply system) to assess the materialcondition of the systems and components.The team reviewed electric and diesel fire pump flow and pressure tests to ensure thatthe pumps were meeting their design requirements. The team also reviewed the fire main loop flow tests to ensure that the flow distribution circuits were able to meet the design requirements. The team also assessed the fire brigade capabilities by reviewing training andqualification records, drill critique records, and observing live fire training. The team also reviewed pre-fire plans and smoke removal plans for the selected fire areas to determine if appropriate information was provided to fire brigade members and plant operators to identify safe shutdown equipment and instrumentation, and to facilitate suppression of a fire that could impact post-fire safe shutdown.


====b. Findings====
====b. Findings====
No findings of significance were identified.


=====Introduction:=====
===.05 Protection From Damage From Fire Suppression Activities===
The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," in that improper component voltage requirements were used when performing batterysizing calculations.Description:  The team reviewed calculations IP3-CALC-EL-184 thru 186, "31, 32, 33Battery, Charger, Associated Panels and Cables Component Sizing and Voltage DropCalculations," and associated technical manuals for components powered from thebatteries. The licensee utilized standardized calculation methods as described in IEEE-Standard-485-1983, "Recommended Practice for Sizing Large Lead Storage Batteriesfor Generating Substations."  The team found that the vendor manual for Agastat 7000series timing relays included a footnote that stated that four-pole models of the timingrelays have an operational voltage range of 85% -120% of the DC bus voltage of 125Vdc. However, the team noted that the 85% (106.25 Vdc) requirement as stated in thevendor manual was not used as the minimum voltage for determining the battery sizerequirements. A review of all IP-3 battery calculations showed that a minimumcomponent voltage of 100 Vdc was used for battery sizing and not the 106.25 Vdcrequired by the timing relays. Interviews conducted by the inspection team with systemengineers confirmed that the four-pole models of the Agastat 7000 series timing relayswere currently in use in IP-3 DC electrical systems powered from batteries 31, 32 and33, and that the 85% voltage requirement was not considered in the sizing calculations.
 
16EnclosureSpecifically, containment spray pump and high steam flow safety injection timingfunctions are controlled by these relays. A review of the most recent discharge test results for all of the batteries indicated thatcurrent capacity margins are adequate for operation. The team noted that the "StationBattery Load Profile Service Tests" (3PT-R156C, Rev. 13) showed that the batteries arecurrently capable of providing adequate current for the design two hour discharge timebefore they reach the minimum individual cell voltages required to support operation ofthe Agastat 7000 relays. However, the acceptance criteria for these tests, specificallythe minimum individual cell voltages (ICVs) may not be adequate to ensure the batterywill provide for minimum component operating voltages when the batteries reach 80% oftheir maximum capacity, considered to be "end of useful battery life."  The licenseedetermined the batteries are operable based on the review of the most recent testresults and initiated a condition report to track and document final resolution of the issue. The team reviewed the results of the battery tests and determined the licensee'soperability assessment was appropriate.
 
=====Analysis:=====
The team determined that Entergy's failure to use the minimum voltageassociated with the limiting component for the battery sizing calculations represented aperformance deficiency that was reasonably within the licensee's ability to foresee andprevent. Specifically, proper sizing of station batteries is vital to ensuring the operationof safety-significant equipment upon a loss of AC power through the battery's end ofuseful life (80% capacity). The minimum component voltage for the Agastat 7000 relays,including a circuit voltage drop of five volts as assumed in the calculations, results in arequired minimum battery terminal voltage requirement of 111.25 volts at the end of thedischarge time. This battery voltage results in a minimum ICV of 1.854 volts versus thepreviously calculated 1.75 volts. The surveillance tests with the current ICVrequirements could result in a battery remaining in service past its end of useful life. Theteam also noted that Agastat 7000 relay replacements in 2002 appears to have been amissed opportunity for prior identification.This issue is more than minor because it was associated with the design control attributeof the Mitigating Systems cornerstone and affected the cornerstone objective of ensuringthe availability, reliability and capability of systems that respond to initiating events toprevent undesirable consequences. Traditional enforcement does not apply becausethe issue did not have any actual safety consequences or potential for impacting theNRC's regulatory function, and was not the result of any willful violation of NRCrequirements. In accordance with NRC IMC 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," the teamconducted a Phase 1 SDP screening and determined the finding was of very low safetysignificance (Green) because it was a design deficiency confirmed not to result in a lossof battery operability.Enforcement:  10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, inpart, that measures shall provide for verifying or checking the adequacy of design. Contrary to the above, as of October 19, 2007, Entergy's design control measures werenot adequate to verify the adequacy of the battery design. Specifically, Entergy used anon-conservative minimum operating voltage for the Agastat 7000 series timing relays 17Enclosureas an input to the battery sizing calculations. Because this violation was of very lowsafety significance and was entered into Entergy's corrective action program (CR-IP3-2007-03957), this violation is being treated as a non-cited violation (NCV), consistentwith Section VI.A.1 of the NRC Enforcement Policy.  (NCV 05000286/2007006-05,Inadequate Design Controls for Station Battery Sizing Calculations)
 
===.2.1.1 2480V Switchgear 32 Bus 6A===
 
====a. Inspection Scope====
The team reviewed condition reports, corrective maintenance history, and preventivemaintenance procedures for selected Bus 6A breakers, including the bus feeder breaker6A, to evaluate the reliability of the equipment. The team reviewed the electricaldistribution system load flow analysis and the manufacturer's rating data for theWestinghouse type DS-416 and DS-532 circuit breakers and 480V switchgear todetermine the operating margin for components that were identified by calculation aslimiting components during design basis conditions. The team reviewed drawings,calculations, set point information network (SPIN) data sheets, and Amptector calibrationtests to verify that breaker overcurrent trip settings were appropriately selected andcalibration tested in accordance with the established acceptance criteria. The teamreviewed the coordination calculation to verify that breaker 6A trip setting wasdetermined in accordance with design basis conditions and the operating instructions forbus loading during a design basis accident. The team conducted walkdowns of theswitchgear and the switchgear area ventilation equipment, to observe the materialcondition for indications of equipment degradation.
 
====b. Findings====
No findings of significance were identified..2.1.13Emergency Diesel Generator 31 (Electrical)
 
====a. Inspection Scope====
The team reviewed the EDG 31 drawings and the schematics for the starting air circuitand the vendor nameplate data for the diesel starting air motor solenoid. The teamreviewed the EDG loading study for the worse case design basis loading conditions todetermine the margin available on the EDGs. The team also reviewed the results ofcapacity tests to verify that the diesel generator test conditions enveloped design basisand technical specification requirements. The team reviewed the coordinationcalculation, SPIN data sheet, and Amptector calibration tests to verify that EDG 31generator breaker EG1 overcurrent trip settings were appropriately selected andcalibration tested in accordance with the established acceptance criteria. The teamconducted walkdowns of the EDGs to evaluate the material condition and the operatingenvironment for the equipment and to determine if there were indications of degradationof any components.
 
18EnclosureThe team also reviewed plant modification ER-05-3-017, "Replacement of Unit ParallelRelay on the EDGs," to verify that the design bases, licensing bases, and performancecapability of the component had not been degraded as a result of the modification.
 
====b. Findings====
 
=====Introduction:=====
The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control." Specifically, Entergy did not use the most limiting design inputs in engineering analysesand surveillance test acceptance criteria for the EDG.Description:  The team identified several examples in the engineering analyses for EDGloading in which the most limiting design input values were not used. As a result, theconclusions of the various analyses were non-conservative. For example, the teamreviewed IP-CALC-04-00809, "Brake Horsepower Values Related to Certain Pumps andFans for EDG Electrical Loading," and found that the break horsepower (BHP) requiredfor the primary auxiliary building (PAB) exhaust fans and the auxiliary feedwater pumpmotors were non-conservative in that worst case design conditions for maximum flow, ineach case, were not considered. Also, the licensee assumed that the highest motorload for the containment fan coil units would occur when service water temperature tothe units was at the maximum design temperature. During the inspection, the licensee,working with the nuclear steam supply system (NSSS) vendor, was not able to confirmthat the assumption was correct or whether the lowest design service water temperatureshould have been considered. The team reviewed surveillance test 3PT-R160B, "32EDG Capacity Test," performed on March 14, 2007, and found that the testingperformed at 1900 kW load met Technical Specification surveillance requirement (SR)3.8.1.10.a. which requires the EDG be loaded between 1837 and 1925 kW. However,the actual tested load did not envelope the maximum possible load determined in theEDG load analyses using the most limiting design inputs.  (1924.4 kW)In addition, the team found that the maximum frequency limit 61.2 Hz allowed underTechnical Specification SR 3.8.1.2.b was not used by the licensee to determine themaximum load requirement. All of the issues identified by the team were documented incondition reports for additional followup and resolution. As an immediate correctiveaction, Entergy performed additional analyses and determined that the effects of theissues identified did not impact EDG operability. Specifically, fuel rack position data was recorded during surveillance testing. Entergy evaluated the rack position recordedduring the March 14, 2007, test and determined there was sufficient rack travel availableto achieve maximum design load, including higher loading as a result of errors identifiedin the loading analyses. The team reviewed Entergy's analyses and operabilityevaluation and found them to be reasonable.Analysis:  The team determined that the failure to adequately evaluate the most limiting load conditions in the EDG loading analysis was a performance deficiency. Specifically,Entergy's design control measures were not adequate to ensure design calculationinputs and assumptions were appropriate for the EDG loading calculation.
 
19EnclosureThe finding is more than minor because it is associated with the design control attributeof the Mitigating Systems cornerstone and affected the cornerstone objective of ensuringthe availability, reliability, and capability of systems that respond to initiating events toprevent undesirable consequences. Traditional enforcement does not apply becausethe issue did not have any actual safety consequences or potential for impacting theNRC's regulatory function, and was not the result of any willful violation of NRCrequirements. In accordance with NRC Inspection Manual Chapter 0609, Appendix A,"Significance Determination of Inspection Findings for At-Power Situations,"  the teamconducted a Phase 1 screening and determined that this finding had very low safetysignificance (Green) because it was a design deficiency that was confirmed not to resultin a loss of EDG operability.
 
=====Enforcement:=====
10 CFR Part 50, Appendix B, Criterion III, "Design Control", requires, inpart, that design control measures shall provide for verifying or checking the adequacyof design, such as by the performance of design reviews, by the use of alternate orsimplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, as of October 23, 2007, Entergy's design control measures werenot adequate to verify the adequacy of the EDG design. Specifically, Entergy did notverify that design inputs to the EDG load analysis enveloped the worse case loadconditions. Because the finding is of very low safety significance and has been enteredinto Entergy's corrective action program (CR-IP3-2007-04002, CR-IP3-2007-04024 andCR-IP3-2007-04098), this violation is being treated as a non-cited violation, consistentwith Section VI.A.1 of the Enforcement Policy.  (NCV 05000286/2007006-06,Inadequate Design Inputs and Testing Requirements for EDG Loading).2.1.14 Station Auxiliary Transformer (SAT)


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the design, testing, and operation of the SAT to verify it was capableof performing its design function during normal, transient and accident conditions. Theteam conducted interviews with engineers, conducted walkdowns of equipment, andreviewed the SAT control logic and interlocks. The review included the adequacy ofenergy sources, control circuit supply, field installation conditions, tap changer operation,potential failure modes, and design, testing, and operating margins. The team alsoreviewed maintenance and inspection activities associated with the SAT.The team also reviewed the electrical feed from the transformer secondary to the 6.9 kVBuses 5 and 6 to verify that the design, testing, and operation would result in a reliablesource of offsite power to the safety buses under all conditions. This review included theelectrical bus fast transfer scheme that transfers buses 1,2,3 and 4 from their normalfeed, the unit auxiliary transformer (UAT), to the feed from the SAT, following a plant trip. The team reviewed relevant sections of the study performed to analyze the transientconditions developed under an automatic fast bus transfer. The team reviewed theperiodic test of the closing time for the tie breakers, including methodology and actualtest results. The team also reviewed the settings, control and potential transformerconnections, potential failure modes, and periodic surveillance test results for the 20Enclosuresynchro-check relay, which is connected to supervise the UAT and the SAT voltagephasing conditions.
The team reviewed documents and walked down the selected fire areas to verify thatredundant trains of systems required for hot shutdown were not subject to damage from fire suppression activities or from the rupture or inadvertent operation of fire suppression systems. Specifically, the team verified that:A fire in one of the selected fire areas would not directly, through production ofsmoke, heat or hot gases, cause activation of suppression systems that could potentially damage all redundant safe shutdown trains, 5EnclosureA fire in one of the selected fire areas (or the inadvertent actuation or rupture ofa fire suppression system) would not directly cause damage to all redundant safe shutdown trains (e.g., sprinkler caused flooding of other than the locally affected train), and Adequate drainage was provided in areas protected by water suppressionsystems.


====b. Findings====
====b. Findings====
 
No findings of significance were identified..06Alternative Shutdown CapabilityAlternative shutdown capability for the selected fire areas inspection utilizes shutdownfrom outside the control room and is discussed in Section 1R05.01 of this report..07Circuit Analyses
=====Introduction:=====
The team identified a finding of very low safety significance (Green)involving the failure to perform a transformer bushing power factor (Doble) test withinEntergy, vendor, or industry recommended frequencies. Additionally, Entergy did notprovide an appropriate technical bases to defer the test beyond the normal interval.Description:  The SAT is an essential component in the circuit that provides thepreferred offsite electrical power source for the plant during both normal and post-accident conditions. A power factor test is an effective industry standard test used toassess the condition of transformers and bushings, and determine whether there isevidence of bushing contamination and/or deterioration. Industry operating experienceshows that high voltage bushings, if allowed to deteriorate, have failed and caused theloss of the transformer, as well as damage to adjacent equipment.During the last refuel outage, in March 2007, a SAT power factor test had beenscheduled, but was not performed due to inclement weather. Entergy determined thatthe test could not be re-scheduled during the remaining outage time frame. Since it isnecessary to remove the SAT from service to perform the test, Entergy determined thenext opportunity for the test would be during the 2009 refuel outage. Entergy performeda deferral evaluation to re-schedule the test, which concluded that not performing thetest for an additional 2 years was acceptable.The team identified that the last power factor test on the bushings had been performedin 1999, and a deferral until 2009 would result in a 10 year interval between tests. Theteam noted that a 10 year interval between bushing tests was significantly longer thanthe 4 year test interval specified in Entergy's maintenance procedure as well as thebushing vendor and industry recommendations for bushing test frequencies. The teamdetermined this test interval was excessive because it did not facilitate identification ofadverse trends, that if identified and corrected could prevent an in-service failure of thetransformer. The team also determined that Entergy's deferral evaluation lacked areasonable technical bases, because it contained errors (e.g. incorrectly assumed thelast test was in 2001), and incorrectly assumed the SAT was a component not importantto safety. The team noted that Indian Point's PRA identified the SAT as a risk significantcomponent, with a RAW value of 6.8, because it is a key component in the offsite powercircuit to the safety buses.Entergy evaluated the SAT and concluded it was operable, in part, based on acomparison of the 1999 power factor test results to the transformer nameplate data, andbecause the transformer was currently energized and operating normally. Entergyentered this condition into the corrective action program. The team determinedEntergy's operability evaluation was reasonable.Analysis:  The team determined that deferring an offsite power transformer test, to theextent that test results might not be adequate to predict degradation and allow 21Enclosuresubsequent corrective actions to prevent an in-service failure, was a performancedeficiency. Specifically, Entergy did not perform a power factor test that was alreadypast due, because of inadequacies in outage planning, scheduling, and work control,and re-scheduled the test for 2009, resulting in a 10 year test interval.The finding was more than minor because it is associated with the equipmentperformance attribute of the Mitigating Systems and affected the cornerstone objectiveof ensuring the availability, reliability and capability of systems that respond to initiatingevents to prevent undesirable consequences. In accordance with NRC IMC 0609,Appendix A, "Significance Determination of Reactor Inspection Findings for At-PowerSituations," the team conducted a Phase 1 SDP screening and determined the findingwas of very low safety significance (Green) because it was not a design or qualificationdeficiency, did not result in an actual loss of safety function, and did not screen aspotentially risk significant due to a seismic, flooding, or severe weather initiating event.This finding had a cross-cutting performance aspect in the Human Performance - WorkControl area. A past due transformer bushing power factor test was not performed asscheduled, during the 2007 refuel outage and was deferred to the next outage, in 2009. Specifically, risk insights had not been adequately considered (e.g., Entergy's deferralevaluation considered the SAT as a non-risk significant component), job site conditions(i.e., outside work during winter) did not support the test activity, and there was noplanned contingency if the test activity could not be accomplished within its scheduledwork window.  (IMC 0305, aspect H.3(a))Enforcement:  No violations of NRC requirements were identified. Entergy entered thisissue into the corrective action program (CR IP3-2007-4266).
 
(FIN 05000286/2007006-07, Inadequate Bushing Testing for the Station Auxiliary Transformer).2.1.15Auxiliary Feedwater Pump and Valve Instrumentation and Controls


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the design, testing and operation of the instrumentation and controlcircuitry associated with major components in the AFW system to ensure these circuitswould support the system in performing its design functions during transient andaccident conditions.The team inspected the AFW system controls and instrumentation for MDAFW pumpmotor manual and automatic start, and the automatic and manual controls for flowcontrol valves BFD-FCV-406A, B, C, and D. The team reviewed the capability of thevalves to control the discharge pressure/flow of the MDAFW pumps in the automatic andmanual modes. The team also reviewed the motor driven pump control circuit, whichprovides for a motor breaker trip for prevention of overload due to pump run-out. Periodic surveillance tests, energy sources, potential failure modes, as well as theinstrument setting calculations were also reviewed.
The team verified that Entergy performed a post-fire safe shutdown analysis for theselected fire areas and that the analysis appropriately identified the structures, systems and components important to achieving and maintaining post-fire safe shutdown.
 
22EnclosureThe team inspected the TDAFW pump controls and instrumentation for automatic startand manual operation. The team reviewed the controls and interlocks for steam turbinepressure reducing valve MS-PCV-1139. The team reviewed the capability of the flowcontrol valves (BFD-FCV-405A-D) for automatic and manual control of the dischargepressure/flow of the TDAFW pump. The automatic controls for steam isolation valvesMS-PCV-1310A and -1310B, and their automatic shut off operation in case of a steamline break in the AFW pump room were also reviewed. The team also reviewed theoperation of the speed controller MS-HCV-1118, which included periodic surveillancetests, energy sources, potential failure modes, and the instrument setting calculations.


====b. Findings====
Additionally, the team verified that Entergy's analysis ensured that necessary electrical circuits were properly protected and that circuits that could adversely impact safe shutdown due to hot shorts, shorts to ground or other failures were identified, evaluated and dispositioned to ensure spurious actuations would not prevent safe shutdown.The team's review considered fire and cable attributes, potential undesirableconsequences and common power supply/bus concerns. Specific items included the credibility of the fire threat, cable construction details, cable failure modes, spurious actuations, actuations resulting in flow diversion or loss of coolant events.The team also reviewed wiring diagrams and routing lists for a sample of componentsrequired for post-fire safe shutdown to verify that cables were routed as described in the cable routing reports.Cable failure modes were reviewed for the following components:
No findings of significance were identified..2.1.16118 Vac Instrumentation Bus 31 and Inverter
Charging Pumps 21 and 23,Service Water Pump 24,Auxiliary Feedwater Pump 21,Component Cooling Pump 23, andCircuit breakers associated with the 13.8 kV Alternate Safe Shutdown PowerSystem.
 
====a. Inspection Scope====
The team reviewed the design and testing of the 118 Vac Bus 31 and its associatedinverter to ensure it could perform its design function of providing a reliable source of118 Vac power to its associated buses and components during normal, transient and accident conditions. The team reviewed the voltage drop calculations, control diagrams,schematics, block diagrams, past corrective actions, surveillance tests and componentvendor manuals. The team verified proper load analyses, assumptions and calculationmethodologies. In addition, a walkdown was performed to visually inspect the physicalcondition of the bus and inverter. Additionally, the team reviewed change records for theinverter as well as maintenance testing on associated system breakers.
 
====b. Findings====
No findings of significance were identified..2.1.17Appendix "R" Standby Diesel Generator
 
====a. Inspection Scope====
The team reviewed the design, testing and operation of the Appendix "R" dieselgenerator to ensure it would provide a reliable source of AC power to equipmentnecessary to support plant safe shutdown during a fire that affects the availability ofoffsite and/or emergency diesel generator power and during a station blackout event(total loss of all AC power). Specifically, the team reviewed the Appendix "R" DG drawings and operationsprocedures to verify breaker alignments required for generator operation. The teamreviewed the DG loading study for the design basis loading conditions to determine themargin available on the DG. The team also reviewed the results of DG functional teststo verify that the test conditions enveloped design basis loading requirements. The teamconducted walkdowns of the DG to evaluate the material condition and the operating 23Enclosureenvironment for the equipment and to determine if there were indications of degradationof any components.
 
====b. Findings====
No findings of significance were identified..2.1.18480 Vac Motor Control Center MCC-36B
 
====a. Inspection Scope====
The team reviewed the design of 480 Vac motor control center MCC-36B to verify that itcould supply power to the necessary loads during normal, transient and accidentconditions. The team reviewed corrective actions, surveillance tests and electricalschematics. A walkdown of the system was also performed to verify load configurationand physical conditions.
 
====b. Findings====
No findings of significance were identified..2.1.19Steam Generator Atmospheric Dump Valve (MS-PCV-1134) Control Circuitry


====a. Inspection Scope====
6EnclosureThe team reviewed circuit breaker coordination studies to ensure equipment needed toconduct post-fire safe shutdown activities would not be impacted due to a lack of coordination. The team confirmed that coordination studies had addressed multiple faults due to fire. Additionally, the team reviewed a sample of circuit breaker maintenance and records to verify that circuit breakers for components required for post-fire safe shutdown were properly maintained in accordance with procedural requirements.
The team reviewed the design, testing and operation of the valve to ensure it wouldperform its design function of removing heat from the reactor coolant system (RCS)during off-normal conditions when the main condenser is not available.The review included the operation and settings of the proportional/integral/derivativecontrollers which control the atmospheric steam dump valves during automatic andmanual operation. The review also included the instrumentation calibration, periodictesting, potential failure modes, availability of energy sources, adequacy of set points,logic and interlocks, and remote indication system. The team verified that the controllersettings were such as not to unnecessarily challenge the operation of the safety valves. The team also verified that backup nitrogen could be utilized to operate the system inthe event the normal supply of instrument air was lost.


====b. Findings====
====b. Findings====
No findings of significance were identified..2.1.20 Switchgear Room Ventilation Fan 33
No findings of significance were identified..08Communications


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the design, operation and testing of the switchgear room ventilationfans to ensure the system would provide adequate cooling for all components within the 24Enclosureroom and prevent exceeding the maximum operating temperature of any components. The review included system modifications, switchgear room heatup calculations,surveillance testing and preventive maintenance activities. The team reviewed theoperating history of the fan to assess the adequacy of corrective actions taken toaddress failures. The team also interviewed design and system engineers andperformed walkdowns of the ventilation system to assess the material condition ofsystem components.
The team reviewed safe shutdown procedures, the SSA and associated documents toverify an adequate method of communications would be available to plant operators following a fire. During this review, the team considered the effects of ambient noise levels, clarity of reception, reliability and coverage patterns. The team also inspected the designated emergency storage lockers to verify the availability of portable radios for the fire brigade and plant operators. The team also verified that communications equipment such as repeaters and transmitters would not be affected by a fire.


====b. Findings====
====b. Findings====
No findings of significance were identified..2.2Detailed Operator Action Reviews (5 Samples)The team assessed manual operator actions and selected a sample of five actions fordetailed review based upon risk significance, time urgency, and factors affecting thelikelihood of human error. The operator actions were selected from a PRA ranking ofoperator action importance based on RAW and RRW values. The non-PRAconsiderations in the selection process included the following factors:*  Margin between the time needed to complete the actions and the time available prior      to adverse reactor consequences;*  Complexity of the actions;*  Reliability and/or redundancy of components associated with the actions;*  Extent of actions to be performed outside of the control room;*  Procedural guidance; and*  Training..2.2.1AC Power Recovery
No findings of significance were identified..09Emergency Lighting


====a. Inspection Scope====
====a. Inspection Scope====
The team selected the operator action to recover AC power to at least one safeguardselectrical bus via the alternate AC power source (Appendix "R" Diesel Generator). Thisaction must be completed within one hour of losing all AC power, and the potentialconsequence of failure of this action is core damage. The team reviewed theincorporation of this action into site procedures, classroom training, and simulatortraining. The team also accompanied operators and walked through station proceduresand plant equipment associated with the startup and alignment of the alternate ACpower source to safety related 480 Vac buses to verify that Entergy could restore ACpower within one hour of a station blackout event. Finally, the team observed a stationblackout simulator scenario to further evaluate operator training and emergencyoperating and recovery procedures.
The team observed the placement and coverage area of eight-hour emergency lightsthroughout the selected fire areas and evaluated their adequacy for illuminating access and egress pathways and any equipment requiring local operation or instrumentation monitoring for post-fire safe shutdown. The team also verified that the battery power supplies were rated for at least an eight-hour capacity. Preventive maintenance procedures, the vendor manual, completed surveillance tests and battery replacement practices were reviewed to verify that the emergency lighting was being maintained in a manner that would ensure reliable operation.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


25Enclosure.2.2.2Initiate Low and High Head Recirculation Flow
7Enclosure.10Cold Shutdown RepairsThe team verified that Entergy had dedicated repair procedures, equipment, andmaterials to accomplish repairs of components required for cold shutdown which might be damaged by the fire to ensure cold shutdown could be achieved within the time frames specific in their design and licensing bases. The inspectors verified that therepair equipment, components, tools and materials (e.g. pre-cut cables with prepared attachment lugs) were available and accessible on site..11Compensatory Measures
 
====a. Inspection Scope====
The team selected the operator action to manually align and initiate low and high headrecirculation flow. Specifically, the actions involve providing recirculation cooling flowfrom the recirculation or containment sumps to the reactor via the RHR system heatexchangers and low head or high head pumps. The IP-3 Human Reliability AnalysisNotebook considered this action to be of a moderately high stress level and a moderateto high task complexity. The team observed simulator scenarios that required theinitiation of low and high head recirculation, both by the use of the recirculation pumpsand the RHR pumps. The incorporation of this action into site procedures, classroomtraining, and job performance measures were also reviewed. The team also interviewedoperators and engineers to discuss the details associated with this action.
 
====b. Findings====
No findings of significance were identified..2.2.3Manually Trip the Reactor Coolant Pumps Following Loss of Component Cooling WaterSystem
 
====a. Inspection Scope====
The team selected the operator action to manually trip the reactor coolant pumps (RCP)following the loss of the component cooling water (CCW) system in order to prevent aninitiating event (RCP seal loss of coolant accident). The team verified that control roomannunciator response and abnormal operating procedures provided adequateinstructions to trip the RCPs following the loss of the CCW system. The teaminterviewed operators and observed a simulator scenario during which RCPs wererequired to be tripped following a significant CCW system malfunction.
 
====b. Findings====
No findings of significance were identified..2.2.4Local/Manual Control of Turbine Driven Auxiliary Feedwater Pump Flow


====a. Inspection Scope====
====a. Inspection Scope====
The team selected the operator action to manually control the TDAFW pump following aloss of all AC power or loss of instrument air. This operator action involved locally andmanually controlling the four flow control valves associated with the TDAFW pump. Theteam observed plant staff walk through the actions required to locally control steamgenerator levels, as well as resetting the TDAFW pump turbine overspeed trip device (inthe event of an overspeed trip of the TDAFW pump turbine). The team verified thatEntergy staged all necessary tools in an appropriate location to effectively and 26Enclosureexpeditiously operate the necessary equipment. The incorporation of this action into siteprocedures, classroom training, and job performance measures was also reviewed.
The team verified that compensatory measures were in place for out-of-service,degraded, or inoperable fire protection and post-fire safe shutdown equipment, systems, or features (e.g., detection and suppression systems and equipment, passive fire barriers, pumps, valves or electrical devices providing safe shutdown functions or capabilities). The team also verified that the short term compensatory measures compensated for the degraded function or feature until appropriate corrective action could be taken and that Entergy was effective in returning the equipment to service in a reasonable period of time.


====b. Findings====
====b. Findings====
No findings of significance were identified..2.2.5Local/Manual Operation of Atmospheric Dump Valves
No findings of significance were identified.4.OTHER ACTIVITIES4OA2Identification and Resolution of Problems.01Corrective Actions for Fire Protection Deficiencies


====a. Inspection Scope====
====a. Inspection Scope====
The team selected the operator action to operate the steam generator atmosphericdump valves. This action included manual activities to locally align the two sources ofbackup nitrogen supply to operate the ADVs (instrument air is normal supply). The teamreviewed the incorporation of this action into emergency and abnormal operatingprocedures, job performance measures, and classroom training. The team observed anoperator locate the local nitrogen supply valves and controls, and walk through theproceduralized actions to locally operate the ADVs.
The team verified that Entergy was identifying fire protection and post-fire safeshutdown issues at an appropriate threshold and entering them into the corrective action program. The team also reviewed a sample of selected issues to verify that Entergy had completed or planned appropriate corrective actions.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


===.3 Review of Industry Operating Experience (OE) and Generic Issues (6 Samples)===
8Enclosure4OA6Meetings, Including ExitExit Meeting SummaryOn May 18, 2007, the team presented the inspection results to Mr. F. Dacimo, Site VicePresident, and other members of the site staff. No proprietary information was included in this inspection report.ATTACHMENT:
 
====a. Inspection Scope====
The team reviewed selected OE issues for applicability at Indian Point Unit 3. The teamperformed a detailed review of the OE issues listed below to verify that Entergy hadappropriately assessed potential applicability to site equipment and initiated correctiveactions when necessary..3.1NRC Information Notice (IN) 2005-023, Vibration-Induced Degradation of ButterflyValvesThe team reviewed Entergy's evaluation of IN 2005-23 to assess the thoroughness andadequacy of the subject evaluation. IN 2005-23 focused on separation of butterfly valveinternal components due to the vibration-induced loss of taper pins used to connectthem. Entergy's evaluation included conducting a search of the corrective actiondatabase to identify whether there were condition reports involving related valve failures,and reviewing valve preventive maintenance procedures to evaluate the measuresemployed at IP-3 to secure the valve disc-to-stem taper pins. The results of Entergy'sevaluation indicated that the subject butterfly valves were not susceptible to vibrationinduced failure as described in the Information Notice.
 
27Enclosure.3.2NRC IN 2002-012, Submerged Safety-Related Electrical CablesThe team reviewed Entergy's disposition of IN 2002-012 for applicability and theidentification and effectiveness of corrective actions. This notice addressed submergedsafety-related cables in duct banks. The team reviewed work orders to confirm that ductbanks at IP-3 containing safety-related cables were periodically inspected under thepreventive maintenance program, and were drained when cables were found to besubmerged to minimize the time when cables are exposed to moisture. Entergy alsodetermined that the underground power, control and instrumentation cable procurementspecification for IP-3 required all cables to have a lead sheath under the jacket toprevent insulation damage due to long term moisture exposure..3.3NRC IN 2006-26, Failure of Magnesium Rotors in Motor-Operated Valve ActuatorsThe team reviewed the applicability and disposition of IN 2006-26. The team reviewedEntergy's response to the information notice, conducted interviews and reviewed industry response. The team evaluated Entergy's evaluation of IN 2006-16, their response and subsequent actions to monitor MOVs which may be susceptible to thefailures identified in IN 2006-26.
 
===.3.4 NRC IN 2006-22, Ultra-Low-Sulfur Diesel Fuel Oil Adverse Impact on EDG PerformanceThe team reviewed Entergy's evaluation of IN 2006-22 to assess the potential impact onEDG operation from the use of ultra-low-sulfur fuel oil.===
The team reviewed Entergy's fueloil monitoring program, including sample frequency, sample locations, acceptancecriteria, and results from recent samples. The review included a walkdown of the No. 31EDG and it's fuel oil system, and interviews with the system engineer..3.5NRC IN 2005-30, Safe Shutdown Potentially Challenged by Unanalyzed InternalFlooding Events and Inadequate DesignThe team reviewed Entergy's evaluation of IN 2005-30 to assess the potential impact ofinternal flooding events on electrical equipment. The team evaluated internal floodprotection measures for the EDG rooms, the 4 kV switchgear rooms, the AFW pumproom, and the relay room. The team walked down the areas to assess operationalreadiness of various features in place to protect redundant safety-related componentsand vital electrical components from internal flooding. These features includedequipment floor drains, floor barrier curbs, and wall penetration seals. The teamconducted several detailed walkdowns of the turbine building, EDG rooms, 4 kVswitchgear rooms, relay room, the AFW pump room, and cable tunnels to assesspotential internal flood vulnerabilities. The team also reviewed Entergy's internal floodanalysis, engineering evaluations, alarm response procedures, and CRs associated withflood protection equipment and measures.
 
28Enclosure.3.6NRC IN 1992-16, Supplement 2, Loss of Flow From the Residual Heat Removal PumpDuring Refueling Cavity DraindownThe team inspected the IP-3 response to IN 92-16, Supplement 2 and found that theplant had installed an additional level indication system (Mansel system) to improvemonitoring of RCS level. The team reviewed the operation of the system, the periodicsurveillance tests, energy sources, potential failure modes, as well as the instrumentsettings. The team reviewed all of the condition reports written against the system andnoticed that there were numerous issues at the beginning of operation in the year 2000. However, corrective actions were implemented and the system has performedadequately for the last seven years.
 
====b. Findings====
No findings of significance were identified.4.OTHER ACTIVITIES 4OA2Problem Identification and Resolution
 
====a. Inspection Scope====
The team reviewed a sample of problems that were identified by Entergy and enteredinto the corrective action program. The team reviewed these issues to verify anappropriate threshold for identifying issues, and to evaluate the effectiveness ofcorrective actions related to design or qualification issues. In addition, condition reports written on issues identified during the inspection, were reviewed to verify adequateproblem identification and incorporation of the problem into the corrective actionprogram. The specific condition reports that were sampled and reviewed by the teamare listed in the attachment to this report.
 
====b. Findings====
No findings of significance were identified.4AO6Meetings, Including ExitOn November 8, 2007, the team presented the preliminary inspection results to Mr. P. Conroy, Director, Nuclear Safety Assurance and Mr. T. Orlando, Director,Engineering, and other members of Entergy staff. Based on subsequent in-office reviewof additional information provided by Entergy, a telephone conference call wasconducted with Messrs. P. Conroy and T. Orlando and other members of their staff onDecember 18, 2007, and a followup telephone call was conducted with Mr. P. Conroy onJanuary 29, 2008, to provide the final inspection results. The team verified that noproprietary information is documented in the report.
 
A-1AttachmentATTACHMENT


=SUPPLEMENTAL INFORMATION=
=SUPPLEMENTAL INFORMATION=


==KEY POINTS OF CONTACT==
==KEY POINTS OF CONTACT==
Entergy Nuclear Operations, Inc.
: [[contact::R. Burroni]], Manager, Programs and Components
: [[contact::S. Wilkie]], Senior Fire Protection Engineer
: [[contact::J. Cottam]], Fire Protection Engineer
: [[contact::K. Elliott]], Fire Protection Engineer
: [[contact::J. Etzweiler]], Operations Supervisor
: [[contact::A. Singer]], Training Supervisor
: [[contact::M. Yee]], Electrical Engineer
: [[contact::G. Dahl]], Licensing Technical Specialist
NRC
: [[contact::J. Rogge]], Chief, Engineering Branch 3, Division of Reactor Safety
: [[contact::W. Cook]], Senior Reactor Analyst, Division of Reactor Safety
: [[contact::M. Cox]], Senior Resident Inspector, IP2
: [[contact::D. Jackson]], Acting Senior Resident, IP3
: [[contact::G. Bowman]], Resident Inspector, IP2
: [[contact::B. Wittick]], Resident Inspector, IP3
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
Opened NoneOpen and
===Closed===
: None


===Licensee Personnel===
===Closed===
: [[contact::R. Altadonna]], Program and Components Engineer
: None
: [[contact::V. Andreozzi]], System Engineering Supervisor
: [[contact::E. Bauer]], System Engineer
: [[contact::J. Bencivenga]], Design Engineer
: [[contact::J. Bubniak]], Design Engineer
: [[contact::R. Carpino]], Senior Reactor Operator
: [[contact::P. Conroy]], Director, Nuclear Safety Assurance
: [[contact::G. Dahl]], Licensing Engineer
: [[contact::J. Dinelli]], Assistant Operations Manager
: [[contact::J. Etzweiler]], Operations Coordinator
: [[contact::D. Gaynor]], Senior Lead Engineer
: [[contact::M. Imai]], System Engineer
: [[contact::C. Ingrassia]], System Engineer
: [[contact::J. Kayani]], Heat Exchanger Component Engineer
: [[contact::M. Kempski]], System Engineer
: [[contact::T. King]], Design Engineer
: [[contact::C. Kocsis]], Senior Operations Instructor
: [[contact::C. Laverde]], MOV Program Engineer
: [[contact::L. Liberatori]], Design Engineer
: [[contact::T. McCaffrey]], Manager, Design Engineering
: [[contact::I. McElroy]], Reactor Operator
: [[contact::T. Moran]], Check Valves Program Engineer
: [[contact::T. Orlando]], Director, Engineering
: [[contact::R. Parks]], Procedure Writer
: [[contact::M. Radvansky]], Design Engineering
: [[contact::J. Raffaele]], Design Engineering Supervisor
: [[contact::V. Rizzo]], AOV Program Engineer
: [[contact::H. Robinson]], Design Engineer
: [[contact::R. Ruzicka]], Senior Operations Instructor
: [[contact::D. Shah]], System Engineer
: [[contact::B. Shepard]], Design Engineer
: [[contact::A. Singer]], Superintendent, Training-Nuclear Operations
: [[contact::D. Vinchkoski]], Senior Operations Instructor
: [[contact::J. Whitney]], System Engineer
A-2Attachment
===NRC Personnel===
: [[contact::P. Cataldo]], Senior Resident Inspector
: [[contact::C. Hott]], Resident Inspector
: [[contact::W. Schmidt]], Senior Risk Analyst
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
Opened05000286/2007006-02URIInadequate Design Control of Recirculation Pumps (Section 1R21.2.1.4)ClosedNone


===Opened and Closed===
===Discussed===
05000286/2007006-01NCV Inadequate Pressure Locking Methodology Used toEnsure Valve Operability (Section 1R21.2.1.2)05000286/2007006-03NCVNon-Conservative Calculation for TDAFW Pump DischargePressure Used for Surveillance Testing (Section1R21.2.1.6)05000286/2007006-04NCVMaintenance Procedure Not Revised after EmergencyDiesel Modification (Section 1R21.2.1.7)05000286/2007006-05NCVInadequate Design Controls for Station Battery SizingCalculations (Section 1R21.2.1.11)05000286/2007006-06 NCVInadequate Design Inputs and Testing Requirements forEDG Loading (Section 1R21.2.1.13)05000286/2007006-07FINInadequate Bushing Testing for the Station AuxiliaryTransformer (Section 1R21.2.1.14)
None
A-2Attachment
==LIST OF DOCUMENTS REVIEWED==
==LIST OF DOCUMENTS REVIEWED==
ModificationsCD-96-3-210, Replacement of Agastat Relays, February 2, 2002DCP-00-3-018, Replace 31 and 32 Batteries, March 19, 2002DCP-01-22-022, Replace 34 Inverter, April 4, 2003DCP-03-3-034, Replacement of Sola Transformer for 34 Inverter, March 18, 2003
Calculations/Engineering Evaluation ReportsPGI-00577, Evaluation of Cable Spreading Room to CAS Corridor and Stairwell 3 Fire BarrierInterface, Rev. 0FMX-00358-00, Component Cooling Water (CCW) Pump Curbing Volume Calculation, Rev. 4
: A-3AttachmentDCP-90-03-158, EDG Jacket Water and Lube Oil Cooling, Rev. 0ER-04-3-062, Disable "Battery Discharge" Alarm Function on 36 Battery Charger, July 2, 2005ER-04-3-22, Battery 33 Replacement, March 3, 2005CalculationsIP3-ANAL-ED-01636, Adjusting Adequate Auxiliary Feedwater Flow Without Aux Feed PumpTrip on Overload, Rev. 1IP3-CALC-04-00809, Brake Horsepower Values Related to Certain Pumps and Fans for EDGElectrical Loading, Rev. 0IP3-CALC-06-00029, Appendix R Cooldown to RHR Initiation Using
: FLEX-00160-02, Rev. 2, IP2 Evaluation of Alternate Power Supplies
: RETRAN-3D, Rev.0IP3-CALC-06-00306, Recirculation Sump Level Versus Volume, Rev. 0IP3-CALC-07-00054, LHSI Post-LOCA Recirculation Performance in Support of ContainmentSump Program, Rev. 6IP3-CALC-07-00210, HELB Pressure & Temperature Response in AFW Pump Room, Rev. 0IP3-CALC-AFW-00418, AFW Pump Room Temperature After SBO, Rev. 0IP3-CALC-AFW-01801, Flow and Pressure Uncertainty for AFW Pump Cut-Back Control (F-1200, F-1201, F-1202, F-1203) Indication, Rev. 2 and Rev. 3IP3-CALC-AFW-01805, AFW Pump Cutback - Pressure Instrument Loop Uncertainty forPC-406A &
: EGP-00150-00, Appendix R Alternate Safe Shutdown System Voltage Drop Analysis, ElectricSupply through Indian Point 1.EGE-00001-02, Class 1E Motor Minimum Starting Voltage and Acceleration Time Calculations
: PC-406B, Rev. 1IP3-CALC-AFW-02576, Turbine Driven AFW Pump Flow Requirements, Rev. 0IP3-CALC-AFW-02581, 32 AFW Pump Discharge Pressure at 340 gpm & 600 gpm, Rev. 0IP3-CALC-CBHV-00996, Control Bldg HVAC Maximum Space Temperatures, Rev. 1IP3-CALC-CBHV-00997, CB Temperatures at Varying Outdoor Temperatures, Rev. 1IP3-CALC-CBHV-01758, CBHV Thermostats 23/319 and 23-4 Auto Start Setpoints, Rev. 2
: RPT-05-00084, Rev. 0, IP2 10
: IP3-CALC-CBHV-02791, Control Bldg. HVAC Room Temperatures, Rev. 0IP3-CALC-COND-02715, CST Vortex Determination For 12 Inch Suction Line, Rev. 0IP3-CALC-ED-00207, 480V Bus 2A, 3A, 5A and 6A and EDG's 31, 32, and 33 AccidentLoading, Rev. 7IP3-CALC-ED-00275, EDG Starting Air Tank Capacity, Rev. 3IP3-CALC-ED-01033, Heat Losses for Electrical Equip. in Upper & Lower Electrical Tunnel andAFW Pump Room, Rev. 1IP3-CALC-ED-01545, 480V Safety Related Switchgear Accident Operation at Above 40CAmbient, Rev. 0IP3-CALC-ED-03158, 6.9kV and 480V System Transient Voltage Analysis During DegradedVoltage Conditions, Rev. 1IP3-CALC-EDG-00217, EDG Storage Tank Level Setpoints, Rev. 4IP3-CALC-EDG-03466, Starting Air Receiver Pressure After a 17 Second Over-crank, Rev. 0IP3-CALC-EL-00113, 118 Volt AC Instrument Bus 31 Voltage Drop Calculation, Rev. 0IP3-CALC-EL-00114, 118 Volt AC Instrument Bus 32 Voltage Drop Calculation, Rev. 0IP3-CALC-EL-00115, 118 Volt AC Instrument Bus 33 Voltage Drop Calculation, Rev. 0IP3-CALC-EL-00116, 118 Volt AC Instrument Bus 34 Voltage Drop Calculation, Rev. 1IP3-CALC-EL-00184, 31 Battery, Charger, Associated Panels and Cables Component Sizingand Voltage Drop Calculations, Rev. 3IP3-CALC-EL-00185, 32 Battery, Charger, Associated Panels and Cables Component Sizingand Voltage Drop Calculations, Rev. 3IP3-CALC-EL-00186, 33 Battery, Charger, Associated Panels and Cables Component Sizingand Voltage Drop Calculations, Rev. 4A
: CFR 50 Appendix R Safe-Shutdown Manual Action FeasibilityReportIP2-RPT-03-00015, Rev. 3, IP2 Fire Hazards Analysis
: A-4AttachmentIP3-CALC-EL-00187, 34 Battery, Charger, Associated Panels and Cables Component Sizingand Voltage Drop Calculations, Rev. 1IP3-CALC-EL-00188, Inverter Number 31 System Component Sizing Analysis, Rev. 0IP3-CALC-EL-00189, Inverter Number 32 System Component Sizing Analysis, 10/3/1994IP3-CALC-EL-00190, Inverter Number 33 System Component Sizing Analysis, 10/3/1994IP3-CALC-EL-00191, Inverter Number 34 System Component Sizing Analysis, 10/2/1998IP3-CALC-EL-01972, Degraded Grid Voltage Study, Rev. 1IP3-CALC-EL-02984, Appendix R Diesel Generator Battery-Sizing Calculation, Rev. 0IP3-CALC-FP-00068, Appendix R Diesel Generator Static Load Study, Rev. 2IP3-CALC-IA-02728, Effects of IA Line Break in ABFP Room on the Ability to Close Valves
: IP-RPT-04-00188, Rev. 1, Evaluation of Hemyc Wrap Fire Protective Systems
: MS-PCV-1310A & B, Rev. 0IP3-CALC-IA-03573, Effects of 1/4" IA Line Break Near Valve
: IP-RPT-05-00071, Rev. 1, IP2 10
: MS-PCV-1139 on the Ability toClose Valves
: CFR 50 Appendix R Safe Shutdown Separation Analysis
: MS-PCV-1310A & B, Rev. 0IP3-CALC-MS-03649, AOV Component Level Calculation for Steam Generator AtmosphericDump Air Operated Valves, Rev. 0IP3-CALC-MS-03655, AOV System Level Calculation for Steam Generator Atmospheric SteamDump Air Operated Valves, Rev. 0IP3-CALC-MULT-382, N2 Backup to Auxiliary Feedwater Bldg Valves and Atmospheric DumpValves, Rev. 3IP3-CALC-RAD-00034, Radiological Plant Accessibility Following a Large-Break LOCA, Rev. 1IP3-CALC-RHR-01029, Thrust and Torque Limits Calculation for
: IP-RPT-05-00071, Rev. 2, Cable Logic Report
: AC-MOV-744, Rev. 4IP3-CALC-RHR-01079, Thrust and Torque Limits Calculation for
: NEA-00031-01, Rev. 1, SG Boil-Dry Analysis
: AC-MOV-730, Rev. 2IP3-CALC-RHR-01080, Thrust and Torque Limits Calculation for
: IP-CALC-05-01034, Rev. 0, Appendix R Cooldown Benchmark and Sensitivity Analysis UsingRETRAN-3DIP-CALC-06-00029, Rev. 0, Appendix R Cooldown to RHR Initiation Using
: AC-MOV-731, Rev. 2IP3-CALC-SI-02409, SI RWST Vortexing, Rev. 0IP3-CALC-SI-02430, NPSHA/NPSHR for Recirculation Pumps, Rev. 2IP3-CALC-SWS-01596, VT Inspection Point
: RERAN-3DProceduresEN-DC-127, Control of Hot Work and Ignition Sources, Rev. 2SMM-DC-901, IPEC Fire Protection Program Plan, Rev. 2
: EOC-28, Rev. 0IP3-CALC-UNSPEC-02558, Minimum AFW Flow During Station Blackout, Rev. 0IP3-ECAF-Bus 6A-11C, FDR to
: SA0-703, Fire Protection Impairment Criteria and Surveillance, Rev. 25
: MCC 36B, Rev. 0IP3-ECAF-Bus 3A-6D, Coordination Study, Rev. 3IP3-RPT-AFW-03400, Operation of AFWP Motors 31 & 33 With Discharge Feed Flow Control Valves In a Failed Open Position, Rev. 0IP3-RPT-ED-00922, Appendix "R" Diesel Generator System Evaluation, Rev. 2IP3-RPT-EDG-02963, EDG Short Term Capacity Rating, Rev. 0IP3-RPT-MULT-01279, Evaluation of Coefficient of Friction for Generic Letter 89-10 MotorOperated Valves, Rev. 4IP3-RPT-MULT-01763, Evaluation of Power Operated Gate Valves for Pressure Locking and Thermal Binding in Accordance With USNRC Generic Letter 95-07, Rev. 1IP3-RPT-MULT-02677, Evaluation of Load Sensitive Behavior (LSB) Data for Generic Letter 89-10 Motor Operated Valves, Rev. 1IP3-RPT-MULT-02668, Evaluation of Valve Factor Data for Generic Letter 89-10 MotorOperated Valves, Rev. 000186-C-003, Auxiliary Feedwater System AOV Functional and MEDP Calculation, Rev. 000186-C-016, AOV Component Level Calculation for Rising Stem Valve
: 2-BRK-020-ELC, Rev. 0, Westinghouse Model 150DH1000E (13.8kV) Air Circuit BreakersMaintenance Circuit Breakers Maintenance Procedure2-PC-R37, Rev. 11, Alternate Safe Shutdown and Remote shutdown Instrument CalibrationProcedures2-SOP-27.1.3, Rev. 30, Operation of 13.8 KV System
: BFD-FCV-406A, B, C, and D at Indian Point 3 Nuclear Power Plant, Rev. 032-1206502, AC
: EN-OP-115, Rev. 3, Conduct of Operations, Addendum 10.4, IPEC Plant Specific Addendum
: MOV 730 & 731- Differential Pressure Calculation, Rev. 132-1206235, MOV Terminal Voltage at Start (PH2) Calculation, Rev. 132-1200112,
: OAP-115, Rev. 05, Operations Commitments and Policy Details
: AC-MOV-744 Differential Pressure Calculation, Rev. 2
: 2-AOP-SSD-1, Rev. 09, Control Room Inaccessibility Safe Shutdown Control
: A-5Attachment98-049, MDAFW System Proto-Flo Thermal Hydraulic Model, Rev. A284-014-TW1, Required Thrust for Indian Point 3 MOVs 730 and 731- Copes-Vulcan ParallelDisk Gate Valves, Rev. 16604.346-6-PAB-001, PAB Ventilation System Analysis Without the Supply Fan, Rev. 26604.003-8-SW-140, EDG Jacket Water Tube Plugging Limit, Rev. 06604.219-8-SW-021, SW Hydraulic Model Inputs and Outputs, Rev. 66604.219-8-SW-024, EDG Lube Oil Cooling, Rev. 26604.266-8-SW-021, SW Hydraulic Model Results, Rev. 68399.003-F-SW-215, SW Flow Through EDG Coolers, Rev. 08399.164-2-SW-088, SW Flows to EDG Lube Oil and Jacket Water Coolers, Rev. 29321-05, AFW Pumps NPSH, Rev. 0CN-CRA-03-100,
: 2-AOP-SSD-1
: IP-3 Steam Line Break Inside Containment Analysis for SPU, Rev. 0CN-SEE-03-59, HHSI Injection and Recirculation for Stretch Power Uprate, Rev. 0CN-SEE-05-107, Post-LOCA Recirculation Pump Performance for Containment SumpProgram, Rev. 1CN-TA-03-143, Power Uprate Analysis for LOOP and Loss of Normal Feedwater, Rev. 0DRN 04-03512 to
: BGD-R07, Background Document for 2-AOP-SSD-1, Rev. 07
: IP3-CALC-SI-02430 Rev. 2, NPSHA/NPSHR for Recirculation PumpsPMX Study
: AOI 27.1.9.2, Rev. 0, Providing Appendix R Power from Unit 3
: PMXR-9002, Heat Exchanger Documentation, Rev. 0RFS-IN-1456, SI Pump NPSH, Rev. 0Completed Test Procedures0-BKR-406-ELC, Westinghouse 6900 Volt Breaker Inspection, Rev. 3 (2/16/05)0-BKR-406-ELC, Westinghouse 6900 Volt Breaker Inspection, Rev. 4 (9/27/06)0-BKR-406-ELC, Westinghouse 6900 Volt Breaker Inspection, Rev. 5 (6/14/07 and 7/1/07)0-VLV-404-AOV, Use of Air Operated Valve Diagnostics (3/29/05, 1/10/06, 4/1/05 and 12/12/05)3-IC-PC-I-F-1135S, 32 Auxiliary Boiler Feedwater Pump 31 Recirculation Flow Control, Rev. 9(1/31/07)3-IC-PC-I-F-1136S, 32 Auxiliary Boiler Feedwater Pump 31 Recirculation Flow Control, Rev. 10 (3/2/07)3-IC-PC-I-H1118, Auxiliary Boiler Feedwater Pump No. 32 Speed Control, Rev. 4 (4/20/04 and5/16/02)3-IC-PC-I-P-405, 32 Auxiliary Boiler Feedwater Pump Discharge Pressure Test, Rev. 4(3/13/07)3-IC-PC-I-P-405, 32 Auxiliary Boiler Feedwater Pump Discharge Pressure Test, Rev. 4 (1/16/07)3-IC-PC-I-T-31EDG, 31 EDG Temperature Instruments Calibration (03/17/07)3-PC-R60A, Auxiliary Feedwater Flow Rate Check and Calibration, Rev. 4 (10/01/02 and10/07/02)3-PC-R60B, Auxiliary Feedwater Flow Rate Check and Calibration, Rev. 6 (10/01/02 and2/06/07)3-PT-CS032A, Flow Test of SW Header Check Valves and Underground portions of Line 409(03/28/07)3-PT-CS032B, Flow Test of SW Header Check Valves and Underground portions of Line 408(03/28/07)3-PT-M090, Appendix "R" Diesel Generator Functional Test (2/11/05, 7/29/05, 1/12/06 and 4/4/06)3-PT-Q001C, #33 Station Battery Surveillance (5/07/2007)
: SAO-703, Rev. 25, Fire Protection Impairment Criteria and Surveillance
: A-6Attachment3-PT-Q016, EDG & Containment Temperature SW Valves (04/25/07)3-PT-Q092C, 33 Service Water Pump Train Operational Test (06/10/07)3-PT-Q116A, 31 Safety Injection Pump Functional Test (06/07/07)3-PT-Q120B, 32 TDAFW Surveillance and IST (06/27/07)3-PT-Q134A, 31 RHR Pump Functional Test (05/25/07)3-PT-R007A, 31 & 33 Auxiliary Boiler Feedwater Pumps Full Flow Test, Rev. 13 (1/13/07 and3/27/07)3-PT-R007B, 32 Auxiliary Boiler Feedwater Pump Full Flow Test, Rev. 13 (2/14/06, 12/14/06,12/26/06 and 03/29/07)3-PT-R013, Recirculation Pumps Inservice Test (03/27/07)3-PT-R035E, Leakage Test for IVSW Manual N2 to VC Iso Valves (4/15/03)3-PT-R090D, Emergency Local Operation of Auxiliary Boiler Feedwater Pumps, Rev. 12 (7/8/05)3-PT-R138, Main Steam Atmospheric Dump Valves Backup N2 Supply (4/14/03, 3/15/05 and3/10/07)3-PT-R156C Station Battery #33 Load-Profile Service Test, Rev. 13 (3/30/05)3-PT-R160A, 31 EDG Capacity Test (03/24/07)3-PT-R160B, 32 EDG Capacity Test (03/14/07)3-PT-V056, Auto Transfer Verification of Offsite Power for 6.9KV Buses 2 and 3, Rev. 0,(3/29/01)3-PT-W019, Electrical Verification - Offsite Power Sources and AC Distribution (2/8/07, 2/17/07,2/20/07, 2/24/07, 6/14/07, 6/16/07, 6/21/07, 6/23/07,6/30/07 and 7/1/07)ENG-487A, EDG Water Cooler Thermal Performance Test (09/29/92)MOV-011-ELC, Testing of Motor-Operated Valves Using the MOVATS MOV Diagnostic TestSystems (10/2/99 and 5/8/01)0PNL-401-ELC, Distribution Panel and Breaker Inspection and Maintenance (3/17/2007,4/9/2003 and 3/16/2007)PNL-001-ELC, Cat 'M' and 'I' Distribution Panel/Breaker Inspection (3/30/03 and 10/06/99)Synch Check Close Permissive, Relay 25-1 (4/11/03)Synch Check Close Permissive, Relay 25-2 (4/11/03)TSP-058, Static Diagnostic Test on MOV:
: SMM-DC-901, Rev. 2, IPEC Fire Protection Program PlanCompleted Tests/Surveillances0-PT-M001, Fire Brigade Equipment Inventory and Inspection, Rev. 3, Completed 04/19/072PT-2Y017, Penetration Fire Barrier Seal Inspections, Rev. 0, Completed 12/13/05
: AC-MOV-744 (3/10/07)VLV-064-AOV, Use of Air Operated Valve Diagnostics (1/12/04, 6/30/04, 1/13/04 and 1/16/04)Condition Reports1197-010001997-016151997-017601998-022651999-023682000-000842000-009192000-009252000-012112000-012732000-017152000-017612000-018542000-019412000-020402000-021542000-022452000-022812000-023692000-025132001-001072001-042702003-056552003-059812003-059882003-060072003-061062003-061192003-061462003-061642003-061912003-062042003-062502003-062512003-062532003-063382003-063702003-063792003-064012003-065132004-00192 2004-002162004-002722004-004412004-005892004-005912004-007962004-008182004-008712004-009662004-011582004-014432004-015692004-019182004-019242004-019252004-019312004-019422004-019542004-020012004-023082004-037702005-001482005-001902005-009922005-016002005-016102005-019012005-020542005-03052
: PT-EM9, Fire Dampers Operability, Rev. 4, Completed 11/16/06
: A-7Attachment2005-030582005-042282005-045952005-050482005-055482006-002292006-003962006-007032006-011162006-014232006-017072006-017302006-018162006-021522006-022322006-028192006-033832006-037562006-037562007-016292007-016412007-004092007-006312007-008392007-008972007-010132007-018342007-018912007-019942007-020292007-020402007-020592007-026212007-026862007-027882007-031352007-032392007-032572007-032592007-032892007-032992007-033162007-036952007-03791*2007-03798*2007-03946*2007-03927*2007-03957*2007-03982*2007-04002*2007-04024*2007-04025*2007-04028*2007-04049*2007-04088*2007-04098*2007-04109*2007-04112*2007-04142*2007-04146*2007-04156*2007-04158*2007-04165*2007-04167*2007-04173*2007-04174*2007-04177*2007-04178*2007-04182*2007-04204*2007-04207*2007-04212*2007-04213*2007-04217*2007-04219*2007-04266*2007-04296*2007-04411** Condition Report was written as a result of inspection effort.Work Orders98-0286199-0109699-0375302-0884002-1309702-1311802-1526402-1526502-1526502-1948102-1948602-1948602-1972202-1978202-2068702-2070702-2073202-2073503-0249203-0296703-1345603-1372103-1372203-1372303-1372403-1422003-1506403-1797203-1821303-1913103-2004703-2228603-2336403-2497403-2539304-1187104-1267004-1400604-1514504-1661204-1758204-1758205-0102705-0104905-0112305-0127705-1520405-1570505-1606505-1764205-1764305-2503005-2518005-2518105-2518106-1571806-1586406-1586506-1744707-0025307-0031707-0031707-0031807-0031807-20927514739945147538951481526I3-913331800I3-970601100Drawings9321-LD-72123, Sht. 3A, ABFP 31 Discharge Pressure and Flow Control Loop P-406A Diagram,Rev. 29321-LD-72373, Sht. 6, Steam Generator No. 34 Atmosphere Steam Dump Loop P-429Diagram, Rev. 2
: PT-SA12A, Ionization Type Smoke Detector (Conventional), Rev. 8, Completed 02/06/07
: A-8Attachment9321-LD-72373, Sht. 4, Steam Generator No. 32 Atmosphere Steam Dump Loop P-429Diagram, Rev. 19321-LD-72123, Sht. 3B, ABFP 31 Discharge Pressure and Flow Control Loop P-406A Diagram,Rev. 09321-LD-72123, Sht. 3, ABFP 31 Discharge Pressure and Flow Control Loop P-406A Diagram,Rev. 19321-LL-31183, Sht. 11, Schematic Diagram 480V Switchgear 32, Breaker 52/AF1, Aux.Feedwater Pump 31, Rev. 69321-LL-31143, Sht. 4, Schematic Diagram 6.9kV Switchgear 32, Bus 4 Normal Feed, Rev. 49321-F-36033, Appendix "R" On-Site Alternate Power Source Diesel Generator Main One-LineDiagram, Rev. 109321-LL-31313, Sht. 10A, Schematic Diagram Miscellaneous Solenoid Valves, Auxiliary BoilerFeed Pump 31 Recirc. Valve (AFPR1), Rev. 89321-H-23613, Auxiliary Feed Pump Building Turbine Steam Supply Equalizing Lines AroundControl Valves
: A-3AttachmentPT-SA12B, Ionization Type Smoke Detector (PAB), Rev. 6, Completed 04/09/07PT-SA12C, Ionization Type Smoke Detector (Electrical and Pipe Penetration Area), Rev. 6,Completed 04/10/07PT-SA13, Cable Spreading Room Halon System, Rev. 9, Completed 03/13/07
: PCV-1310A &
: PT-19, Cable Spreading Room Halon System, Rev. 10, Completed 12/21/06
: PCV-1310B, Rev. 09321-F-70093, Instrument Air Supply Sheet No. 2 Instrumentation & Restraint & Support Design,Rev. 199321-LL-31313, Sht. 10, Schematic Diagram for Aux Boiler Pump 31 Recirc. Valve (AFPR1),Rev. 159321-F-70533, Auxiliary Boiler Feed Pump Room Instrument Piping - Sheet No. 2, Rev. 21 9321-F-70313, Auxiliary Boiler Feed Pump Room Instrument Piping - Sheet No. 1, Rev 16 9321-LL-31313, Sht. 29, Schematic Diagram for 32 Aux Feedwater Turbine Steam IsolationValves
: 2-PT-A023, Fire Main Booster Pump Capacity Test, Rev. 10, Completed 06/14/06
: PCV-1310A and
: PT-A40, Diesel Fire Pump Capacity Test, Rev. 0, Completed 03/08/07
: PCV-1310B, Rev. 49321-LL-31303, Sht. 2B, Schematic Diagram Turbine Generator, Back Up Turbine Auto StopSolenoid, Rev. 8
: 2-PT-3Y015A, Underground Fire Loop Flow, Rev. 2, Completed 09/23/04
: 9321-LL-31303, Sht. 5, Schematic Diagram Turbine Generator, Generator Primary Lock OutRelay, Rev. 16 9321-LL-31303, Sht. 6, Schematic Diagram Turbine Generator, Generator Back Up Lock OutRelay, Rev. 189321-F-20123, Sht. 3, Instrument Piping Schematics, Rev. 179321-F-20173, Flow Diagram, Main Steam, Rev. 709321-F-20183 Sht. 1, Condensate and Feed Pump Suction P&ID, Rev. 609321-F-20183 Sht. 2, Condensate and Feed Pump Suction P&ID, Rev. 259321-F-20193, Flow Diagram, Boiler Feedwater, Rev. 589321-F-20303, EDG Fuel Oil P&ID, Rev. 299321-F-20333 Sht. 2, Service Water System P&ID, Rev. 279321-F-20333 Sht. 1, Service Water System P&ID, Rev. 499321-F-21193, EDG Lube Oil P&ID, Rev. 79321-F-21543, Alteration of Aux. Boiler Feed Pump Room IA Nitrogen Back-up Piping, Rev. 09321-F-27203, Auxiliary Coolant System Inside Containment, Rev. 299321-F-27223, Service Water System Nuclear Steam Supply P&ID, Rev. 429321-F-27353, Sht. 1, Flow Diagram - Safety Injection System, Rev. 409321-F-27353, Sht. 2, Flow Diagram - Safety Injection System, Rev. 469321-F-27383, Sht. 1, Reactor Coolant System P&ID, Rev. 279321-F-27383, Sht. 2, Reactor Coolant System P&ID, Rev. 419321-F-27463, Flow Diagram Isolation Valve Seal Water System, Rev. 309321-F-27513, Sht. 1, Auxiliary Coolant System in PAB & FSB P&ID, Rev. 299321-F-27513, Sht. 2, Auxiliary Coolant System in PAB & FSB P&ID, Rev. 42
: PMT-I2-2658, Installation of Halon System in Cable Spreading Room, Completed 12/18/79
: A-9Attachment9321-F-30113, Sht. 1, Main Three Line Diagram, Rev. 289321-F-30113, Sht. 2, Main Three Line Diagram, Rev. 49321-F-30113, Sht. 3, Main Three Line Diagram, Rev. 09321-F-32263, Wiring Diagram Terminal Boxes & Misc. Devices, Rev. 379321-F-33853, Electrical Distribution and Transmission System, Rev. 179321-F-41023, Sht. 2, Control Room Flow Diagram, Rev. 49321-F-70123, Sht. 3, Instrument Piping Schematics, Rev. 179321-F-70153, Sht. 6, Instrument Piping Schematics, Rev. 139321-F-70563, Control Valve Hook-Up Details, Instrumentation, Rev. 319321-H-20293, EDG Starting Air P&ID, Rev. 279321-H-36933, Extension of Electrical Facilities One Line Diagram, Rev. 109321-H-70076, Atmospheric Steam Dump Control Panel, Rev. 19321-H-96523, SG Atmospheric Dump Valves
: IP2-04-23808, 5/22/06 performance of
: PCV-1134,
: PC-2Y 1, RCS Alternate Safe Shutdown TemperatureMonitor Calibration, Rev. 6IP2-04-30257, 4/23/06 performance of
: PCV-1134,
: PC-2Y70, Source Range Neutron Flux (N-5143)Channel Calibration, Rev. 2IP2-04-31441, 5/5/06 performance of 2-PC-R37, Alternate Safe Shutdown and RemoteShutdown Instruments, Rev. 11IP-06-22688, 4/23/07 performance of 0-PT-M002, Appendix R Equipment Inventory andInspection, Rev. 3QS-2006-IP-04, Surveillance Report: Performance of Appendix R Safe Shutdown Procedure,4/18/06Quality Assurance AuditsAudit Report A03-12-I, IPEC Fire Protection ProgramQA-09-2005-IP-1, IPEC Fire Protection program Audit
: PCV-1135, and
: QA-09-2006-IP-1, IPEC Fire Protection Program Audit
: PCV-1136, Wiring Diagram, Rev. 0 9321-LL-20013, Sht. 133, Control Switch Reference, Rev. 29321-LL-30420, Sht. 5C, Fire Protection CO2 System Relay/SWGR Room, Rev. 19321-LL-31123, Sht. 5, Schematic Diagram Pilot Wire and Misc Lock-out Relays, Rev. 99321-LL-31133, Sht. 1, Schematic Diagram 6.9kV Switchgear 31, Rev. 59321-LL-31133, Sht. 2, Schematic Diagram 6.9kV Switchgear 31, Bus 1 Normal Feed, Rev. 59321-LL-31133, Sht. 3, Schematic Diagram 6.9kV Switchgear 31, Bus 1-5 Tie, Rev. 79321-LL-31133, Sht. 4, Schematic Diagram 6.9kV Switchgear 31, Bus 2 Normal Feed, Rev. 59321-LL-31133, Sht. 5, Schematic Diagram 6.9kV Switchgear 31, Bus 2-5 Tie, Rev. 79321-LL-31133, Sht. 6, Schematic Diagram 6.9kV Switchgear 31, Bus 5 Normal, Rev. 59321-LL-31143, Sht. 2, Schematic Diagram 6.9kV Switchgear 32, Bus 3 Normal Feed, Rev. 59321-LL-31143, Sht. 3, Schematic Diagram 6.9kV Switchgear 32, Bus 3-6 Tie, Rev. 69321-LL-31143, Sht. 5, Schematic Diagram 6.9kV Switchgear 32, Bus 4-6 Tie, Rev. 69321-LL-31143, Sht. 6, Schematic Diagram 6.9kV Switchgear 32, Bus 6 Normal Feed, Rev. 69321-LL-31173, Sht. 14, Schematic Diagram 480V Switchgear 31, Rev. 129321-LL-31183, Sht. 5, Schematic Diagram 480V Switchgear 32, Rev. 229321-LL-31263, Sht. 215, SWGR Room Exhaust Fan 34 Schematic Diagram, Rev. 79321-LL-31263, Sht. 17, SWGR Room Exhaust Fan 33 & Louver 319 Drive Motor ControlSchematic Diagram, Rev. 79321-LL-31313, Sht. 44, SG Atmospheric Dump Valves
: QS-2006-IP-04, Performance of Appendix R Safe Shutdown Procedure, 2-AOP-SSD-1,Revision 7DrawingsD-8775, Halon System Cable Spreading Room, Sh. 2, Rev. 4D-8775, Halon System Cable Spreading Room, Sh. 3, Rev. 4
: PCV-1134,
: D-8775, Halon System Cable Spreading Room, Sh. 4, Rev. 3
: PCV-1134,
: D-8775, Halon System Cable Spreading Room, Sh. 5, Rev. 2
: PCV-1135, andPCV-1136, Schematic Diagram, Rev. 19321-LL-31313, Sht. 2, Schematic Diagram 480V Switchgear 32, Rev. 159321-LL-31313, Sht. 3, Schematic Diagram 480V Switchgear 32, Rev. 1531 Service Water Pump DP vs. Flow Curve, 12/13/0632 Service Water Pump DP vs. Flow Curve, 05/27/0533 Service Water Pump DP vs. Flow Curve, 10/06/035651D72, Sht. 3, Logic Diagram Turbine Trip Signals, Rev. 10617-F-643, 6900V One Line Diagram, Rev. 10617-F-644, 480V One Line Diagram, Rev. 32617-F-645, Main One Line Diagram, Rev. 18B185758, Schematic Diagram for 138 kV Disconnect Switch
: D-8775, Halon System Cable Spreading Room, Sh. 6, Rev. 2
: BK-5, Rev. 0E-179950, Model D-100-160 Actuator 6" Class 600 Valve Assembly Tandem Trim, 3rdGeneration, Rev. 5IP3V-112-6.6-0013, 14"- 2500 lb Motor Operated Gate Valve Assembly, Rev. 1IP3V-13-0002, Breaker Control Schematic, Rev. 15
: D-8677, Halon System Piping Cable Spreading Room, Sh. 4, Rev. 1
: A-10AttachmentIP3V-13-0003, DC Schematic (Breaker Control), Rev. 2IP3V-2057-0010, Recirculation Pump General Arrangement, Rev. 0IP3V-306-0004, 7.2 KV Metal Clad BLDG Gen. Breaker & Auxiliaries, Rev. 2Design Basis DocumentsIP3-DBD-301, Main Steam System DBD, Rev. 3IP3-DBD-303, Auxiliary Feedwater System DBD, Rev. 3IP3-DBD-306, Safety Injection System DBD, Rev. 2
: 400411, Fire Area/Zone Arrangement - EL. 100', Sh. 1, Rev. 1
: IP3-DBD-315, HVAC Systems DBD, Rev. 2
: 400403, Fire Area/Zone Arrangement - EL. 53', Sh. 1, Rev. 2
: IP3-DBD-324, Emergency Diesel Generators DBD, Rev. 1Procedures3-AOP-AIR-1, Air Systems Malfunction, Rev. 23-AOP-CCW-1, Loss of Component Cooling Water, Rev. 33-AOP-Flood-1, Flooding, Rev. 33-AOP-FW-1, Loss of Feedwater, Rev. 63-AOP-SW-1, Service Water Malfunction, Rev. 23-ARP-005, 480 Volt Safeguard Bus Undervoltage, Rev. 313-ARP-010, Panel SGF - Auxiliary Coolant System, Rev. 283-ARP-012, Cooling Water and Air Alarm Response Procedure, Rev. 453-ARP-013, Panel SKF - Bearing Monitor, Rev. 343-ARP-019, EDG Local Panel Alarm Response Procedure, Rev. 203-COL-FW-2, Auxiliary Feedwater System, Rev. 293-COL-RHR-1, RHR Check Off List, Rev. 253-E-0, Reactor Trip or Safety Injection, Rev. 03-E-1, Loss of Reactor or Secondary Coolant, Rev. 03-ECA-0.0, Loss of all AC Power, Rev. 03-ECA-1.1, Loss of Emergency Coolant Recirculation, Rev. 03-ECA-3.3 DEV, SGTR Without Pressurizer Control, Rev. 03-ES-1.2, Post LOCA Cooldown and Depressurization, Rev. 03-ES-1.3 DEV, Transfer to Cold Leg Recirculation Basis, Rev. 03-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 03-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 13-FR-H.1, Response to Loss of Secondary Heat Sink, Rev. 03-GFO-1, Generic Foldout Page, Rev. 03-GNR-022-ELC, EDG 6-year Inspection, Rev. 23-IC-PC-I-P-405, 32 Auxiliary Boiler Feedwater Pump Discharge Pressure Test, Rev. 43-PT-6Y002, N2 Backup Supply System for AFW Valves, Rev. 03-PT-CS030, Atmospheric Steam Dump Valves Stroke Test, Rev. 143-PT-M079A, 31 EDG Functional Test, Rev. 353-PT-Q-092A, 31 Service Water Pump Train Operational Test, Rev. 123-PT-Q-092B, 32 Service Water Pump Train Operational Test, Rev. 103-PT-Q-092C, 33 Service Water Pump Train Operational Test, Rev. 123-PT-Q116C, 33 Safety Injection Pump Functional Test, Rev. 123-PT-Q120A, 31 ABFP (Motor Driven) Surveillance and IST, Rev. 103-PT-Q120C, 33 ABFP (Motor Driven) Surveillance and IST, Rev. 9
: 400404, Fire Area/Zone Arrangement - EL. 80', Sh. 1, Rev. 2
: A-11Attachment3-PT-R007B, 32 Auxiliary Boiler Feedwater Pump Full Flow Test, Rev. 133-PT-R013, Recirculation Pump Inservice Test, Rev. 193-PT-R138, Main Steam Atmospheric Dump Valves Backup N2 Supply, Rev. 53-PT-R160A, 31 EDG Capacity Test, Rev. 103-RO-1, BOP Operator Actions During Use of EOPs, Rev. 03-SOP-CB-011, Non-Automatic Containment Isolation, Rev. 93-SOP-EL-001, EDG Operation, Rev. 383-SOP-EL-005, Operation of On-Site Power Sources, Rev. 373-SOP-EL-013, Appendix "R" DG Operation, Rev. 223-SOP-EL-014, Energization of the 480V Buses from the Appendix "R" DG, Rev. 83-SOP-EL-015, Operation of Non-Safeguards Equipment During Use of EOPs, Rev. 163-SOP-ESP-001, Local Equipment Operation and Contingency Actions, Rev. 173-SOP-RCS-017, Mansel Level Monitoring System, Rev. 33-SOP-RW-005, Service Water System Operation, Rev. 340-CY-1810, Diesel Fuel Oil Monitoring, Rev. 50-GNR-406-ELC, EDG 6-year Inspection, Rev. 00-MCB-401-ELC, Molded Case Circuit Breaker Inspection/Replacement, Rev. 20-PNL-401-ELC, Distribution Panel and Breaker Inspection and Maintenance, Rev. 20-XFR-403-ELC, Station or Unit Auxiliary Transformer Preventive Maintenance, Rev. 3EN-OP-115, Conduct of Operations, Rev. 4IC-PC-I-H1118, Auxiliary Boiler Feedwater Pump No. 32 Speed Control, Rev. 0ONOP-ES-3, Passive Failures During Recirculation, Rev. 9PFM-22E, Inservice Testing Program Basis Document, Rev. 1PNL-001-ELC, Cat 'M' and 'I' Distribution Panel/Breaker Inspection, Rev. 3STR-002-SWS, Service Water Pump Strainer Manual Back-Washing, Rev. 1Miscellaneous Documents0-CY-2655, Electrical Transformer Chemistry Sampling and Analysis, Oil Analysis Results of11/14/05, Rev. 518.0, Main and Reheat Steam System Description, Rev. 521.2, Auxiliary Feedwater System Description, Rev. 327.4, Electrical Systems Medium Voltage 6.9 KV and 480 V, Rev. 19321-05-223-4, Specification for Centrifugal Fans for Containment, Primary Auxiliary, FuelStorage, Control Buildings and Electrical Tunnel, Rev. 0ACT-02-62461,
: 400405, Fire Area/Zone Arrangement - EL. 96', Sh. 1, Rev. 2
: IN-2002-012 Submerged Safety-Related Electrical Cables (7/10/02)Agastat Timing Relays 2400 Series Vendor Manual, 04/1972Agastat Timing Relays 7000 Series Vendor Manual, 04/1972Certificate of Conformance for 3CC-5M Battery, 3/2007CLAS 94-03-021, Equipment and Controls for Control Building Ventilation System, Rev. 0Commonwealth Edison Company (ComEd) Response to NRC Generic Letter (GL) 95-07, "Pressure Locking and Thermal Binding of Safety-Related Power-Operated GateValves," dated August 17, 1995Doble Test Data, Main Transformer 32, 3/27/07Doble Test Data, Main Transformer 31, 4/08/07Doble Test Data, SAT, 9/27/99Engineering Study for Pump Model 267APKD-3, Safety Injection Recirculation Pumps, Preparedby Flowserve Pump Company, December 2006
: 21-F-4022, Flow Diagram Ventilation System Containment, Primary Aux. Building, Sh. 1, Rev. 62A208377-11, Unit 2 One Line Diagram.
: 2AttachmentEntergy Evaluation of NRC
: A208088-42, One Line Diagram of 480 Vac Switchgears 21 and 23.
: IN 2005-30, Safe Shutdown Potentially Challenged by UnanalyzedInternal Flooding Events and Inadequate Design, dated 03/12/06Entergy PM Basis Template, Rev. 0EPRI
: A208064-5, Level and Pressure Instrument for Steam Generator and Pressurizer Arrangement,Piping.
: TR-103232, EPRI MOV Performance Prediction Program: Stem Thrust Prediction Methodfor Anchor/Darling Double Disk Gate Valves, November 1994ER
: A-4AttachmentA208065-11, Level and Pressure Instrument for Steam Generator and PressurizerArrangement, Piping Details - Instrumentation.A209561-5, Steam Generator and Pressurizer Instrumentation Arrangement OutsideContainment.A208247-8, Modification to Pressurizer Level transmitter Cabinet - Rack No. 19Instrumentation.A208248-6, Modification to Steam Generator Level transmitter Rack No. 21. Instrumentation.
: IP3-07-18649, Deferral of Station Aux. Transformer 4Y Pwr Factor (Doble) Test, Rev. 0ER-03-3-107, Modify N2 Backup Supply System for AFWS Valves and Turbine Speed Controller,Rev. 1ER-05-3-017, Replacement of Unit Parallel Relay on the EDGs, Rev. 0ESBU/WOG-96-022, Summary of January 4 & 5, 1996 Pressure Locking & Thermal Binding(PLTB) Task Team Meeting (MUHP-6050)Excerpts from IP3 Systems Interaction Study, dated 1983, (Volume 1-Methodology Chapters 1thru 6, and Interaction Summary Section 6.0, Internally Generated Flooding)IP3-88-004,Indian Point 3 Nuclear Power Plant (IP3) Response to NRC IE Bulletin (IEB) 85-03:"Motor Operated Valve Common Mode Failures During Plant Transients Due to ImproperSwitch Settings," 1/15/88IP3-ECCF-01023, Modification No.
: B225132-12, Elementary Wiring Diagram for Charging Pumps 21 and 23.
: ER-04-3-066, Rev. 0IP3-ECCF-939, W.O.
: B225137-10, Elementary Wiring Diagram for Residual Heat Removal Pumps 21 and 22.
: IP3-02-00498, Rev. 0IP3-GL-89-10, IP3 MOV Program Summary for NRC Generic Letter 89-10, "Safety-RelatedMotor Operated Valve Testing and Surveillance," 7/26/01IP3-RPT-06-00071,
: B225149-1-24, Elementary Wiring Diagram for Service Water Pump 23.
: IP-3 Probabilistic Safety Assessment, Appendix F, Updated Power RecoveryModel, Rev. 0IP3-RPT-HVAC-01904, Maintenance Rule Basis Document for Systems E32-0085, E32-0087,and E32-0089, Rev. 0IP3 Set Point Information Network - EOP Detail Listing
: 308762-0, Instrument Air and Nitrogen Supply to Pressurizer and Steam Generator FlowDiagram.IP2-S-000193-1,
: IP3-LO-2007-00150, IPEC Focused Self-Assessment Report, July 2007IPN-92-006, Indian Point 3 Nuclear Power Plant, Docket No. 50-286, Station Blackout Rule, Response to Safety Evaluation Recommendations, 1/29/92JPM 005A-2, Local Operation of 32 Atmospheric Steam Dump Valve (Alternate Path), 8/21/07JPM 020, Start the Appendix "R" Diesel Generator, 3/13/07JPM 065TCA, Realign the SI System for Cold Leg Recirculation (Alternate Path), 3/14/07Letter
: SWD-Control and Indication Service Water Pump 24
: INT-89-761, Westinghouse
: 21-LL-3118-30, Breaker 52/AF1 Auxiliary Feedwater Pump 21.
: SECL-89-508 Safety Related Pump Miniflow, dated 05/22/89Letter
: 260503-03, Loop Diagram RCS Pressure SSD Level and Pressure, Loop Nos. 3101 and 3105
: INT-91-518, Westinghouse
: A138040-54, Unit 1 One Line diagram, 13.8kV and 440V Systems.
: SECL-91-029 AFW Deadheading & Miniflow, dated 03/08/91Letter
: 244016-19, Unit 1 One Line 440V Switchgear Unit Substation 11RW1, 12RW3, 12FD3, MCC's10M,10N 10Z and 10X.9321-F-36033, IP3 Appendix R On-site Alternate Power Source, Diesel Generator Main One-Line Diagram, Revision10A209762, Rev 67, Flow Diagram Service Water System Nuclear Steam Supply Plant, sheet 2 of
: MNED-94-RCL-1562, SW Hydraulic Analysis Maximum Allowable Deviation of SW PumpCurve, 1/23/94Letter, Washington Power,
: 29321-F-2722-117, Rev 117, Flow Diagram Service Water System Nuclear Steam Supply Plant,sheet 1 of 29321-F-2019, Flow Diagram Boiler Feedwater
: AFP 31 Motor Horsepower, 11/13/2000Letter
: 21-F-3056-41, Rev. 41, Control Building, Elev. 33'-0" Cable Spreading Room Cable Trays -
: DE-35211, M. Delamater, ALCO, to F. Conway, UE&C, EDG Ratings, 01/16/68Letter
: PlanA206640-10, Arrangement of Equipment in Cable Spreading Room, Elev. 33'-0", West Half -Plan &Sects.Pre-Fire PlansPFP-209-FZ-1, Component Cooling Pump Room, Rev. 0PFP-215-FZ-1A, General Floor Plan - Fan House, Rev. 0
: IP3-88-046, W. A. Josiger, NYPA to NRC, NRC Bulletin 88-04 Response, 07/13/88Letter
: PFP-252-FZ-11, Cable Spreading Room, Rev. 0
: IP3-89-036, W. A. Josiger, NYPA to NRC, NRC Bulletin 88-04 Response, 05/12/89Letter
: PFP-264-FZ-22 & 63A, Intake Structure, Rev. 0Fire Brigade TrainingIP-SMM-TQ-122, Fire Brigade Drill Attendance Record, Rev. 1Drill Records 1
: INT-89-867, S. P. Swigart, Westinghouse, to K. Chapple, NYPA, Re-rating Upgrade ofDiesel Generators, 10/27/89Letter
st - 4 th Quarter 2006, 1
: IPN-94-125, L. M. Hill, NYPA to NRC, Bulletin No. 88-04 Response, 10/07/94Letter
st Quarter 2007.
: IUP-8066, J. E. Tompkins, UE&C, to S. Zulla, NYPA, Telcon Notes Regarding SWPerformance Evaluation on EDGs, 04/04/88Letter from Flowserve to V. Cambigians, 267APKD-3, Minimum Flows, 11/09/07Letter from M. J. Clifford, Ingersoll-Rand Pumps to M. Vasely, Consolidated Edison Company,Subject: NRC Bulletin 88-04, Review of Min Flow Rates, 4/7/89LO-OEN-2005-00383, Response to Information Notice 2005-23, 10/22/07
: A-5AttachmentOperator Safe Shutdown TrainingI2LP-ILO-ASSD, Rev. 14, Instructor Lesson Plan: Alternate Safe Shutdown SystemTransient Combustible EvaluationsEN-DC-161, Transient Combustible Evaluation, 07-011 for Unit 2 Intake Structure, 4/26/07  
: A-13AttachmentMartel Laboratory Report 48669, EDG Fuel Oil Sample Analysis, 9/19/07Memorandum, Relay Settings for 6.9kV Auxiliary Power Circuits for Indian Point No.3, 4/13/72
===Miscellaneous===
: NED-E-BQE-90-419 New York Power Authority, Cable Resistances and Reactances to be UsedFor 1) Degraded Grid Voltage, 2) Voltage Drop Study 3) Short Circuit Study, 12/3/1990NSE 92-03-114 EDG, Safety Evaluation of EDG Operability with Tube Plugging, Rev. 2NSE 89-03-093 EDG, Safety Evaluation of EDG Operability with Tube Plugging, Rev. 1Simulator Instructor Guide for NPO Local Tasks, Rev. 1Spec. No. 9321-05-223-4, Specification for Centrifugal Fans, May 9, 1972System Health Reports - 118V 07Q2,
: DocumentsECRIS cable routing data report, 5/14/07ECRIS cable routing data report, 5/15/07
: DC 07Q2 and 480V 07Q2 Tag Number 52/6A, Station Service Transformer Breaker, 6/26/2002Tag Number 52/EG1, Emergency Diesel Generator 31, 6/26/2002Tag Number 52/MCC6B, Feeder to
: TB-04-22, Westinghouse Technical Bulletin: Reactor Coolant Pump Seal Performance -Appendix R Compliance and Loss fo All Seal Cooling, Rev. 1Condition Reports1999-015462002-115362003-018252004-006072004-006092004-014452006-008932006-01212
: MCC 36B, 6/26/2002TB-04-13, Replacement Solutions for Obsolete Classic Molded Case Circuit Breakers, ULTesting Issues, Breaker Design Life and Trip Band Adjustment, 07/16/2004TR-106857-V38, Preventive Maintenance Basis, Transformers, EPRI Report, Rev. 0V-EC-1620, Thermally Induced Pressurization Rates in Gate Valves, 5/1/96Vendor Documents1158-100000844, SW Zurn Strainer Operations and Service, Rev. 0456-100000681, SW Strainer Service Data 590A & 592A Strain-O-Matic, Rev. 0ABB Contact Newsletter, Type "U" Bushings, 03/98ABB I.L. 44-666G, Instructions for Installation, Maintenance and Storage of Type "O" Plus "C"Bushings 115kV and Higher, 02/01/94.C&D Tech LCR and LCY Lead-Calcium, LAR, Lead-Antimony Vendor Tech Sheets, 04/18/1997 Copes-Vulcan, Inc., Addenda 2 to Instruction Manual for New York Power Authority- Indian Point 3 14-Inch Motor Operated Gate Valve, 10/8/98Doble, Report #76069, 7/24/07 Heritage Antimony Flat Plate Batteries Vendor Manual, 1976I.L 32-691C, Cutler-Hammer, Testing of Amptector, 02/98I.L. 33-354-1A, Westinghouse Instructions, Outdoor Condenser Bushings Type "O" , 12/67NUS Instruments Operations and Maintenance Manual, PIDA700 Proportional Integral DerivativeController, Version 4, Rev. 0US-CC-PS-001, PowerSafe Battery Cell Vendor Manual, 04/2006Westinghouse I.L. 41-681.1H, Installation, Operation, Maintenance Instructions, Type CVE andCVE-1 Synchro-Verifier Relays, 11/68Westinghouse I.L. 41-681.1Q, Installation, Operation, Maintenance Instructions, Type CVE,CVE-1,
: 2006-033732006-052992006-068382006-06844
: CVE-2, and
: 2007-001252007-001432007-006362007-00743
: CVE-3 Synchro-Verifier Relays, 11/88
: 2007-009352007-009362007-009582007-01014
: 2007-010542007-010762007-011762007-01254
: 2007-013912007-017552007-017572007-10769
: 2007-017712007-017722007-017812007-02026
: 2007-020392007-020522007-02067Work Orders NP9262151NP9262152NP9157705NP9261088NP9259111NP9262153NP9364109NP9153738
==LIST OF ACRONYMS==
==LIST OF ACRONYMS==
: [[USEDAC]] [[Alternating Current]]
USEDACAlternating CurrentAOPAbnormal Operating Procedure
ADVAtmospheric Dump ValveAFWAuxiliary FeedwaterAOPAbnormal Operating ProcedureAOVAir Operated ValveBHPBrake horsepower
: [[CFRC]] [[ode of Federal Regulations]]
A-14AttachmentCCWComponent Cooling WaterCFRCode of Federal RegulationsCRCondition ReportCSTCondensate Storage TankDCDirect CurrentEDGEmergency Diesel GeneratorEOPEmergency Operating ProcedureGL[NRC] Generic LettergpmGallons per MinuteHzHertzICVIndividual Cell VoltageIEEEInstitute of Electrical and Electronics EngineersIMCInspection Manual ChapterINInformation NoticeIPInspection ProcedureIP-3Indian Point Unit
: [[CO]] [[2Carbon Dioxide]]
: [[3IVSWSI]] [[solation Valve Seal Water Systemk]]
DRSDivision of Reactor Safety
: [[VK]] [[ilovoltkWKilowatt]]
FAFire Area
: [[LOCAL]] [[oss-of-Coolant Accident]]
FHAFire Hazards Analysis
LOOPLoss-of-Offsite PowerMCCMotor Control CenterMDAFWMotor Driven Auxiliary FeedwaterMOVMotor Operated ValveMRMaintenance RuleMSSVMain Steam Safety ValveNCVNon-Cited ViolationNPSHNet Positive Suction HeadNRCNuclear Regulatory CommissionOEOperating ExperiencePABPrimary Auxiliary BuildingP&IDPiping and Instrumentation DrawingPMPreventive MaintenancePRAProbabilistic Risk AnalysispsidPounds per Square Inch (Differential)psigPounds per Square Inch (Gauge)RAWRisk Achievement WorthRCPReactor Coolant PumpRCSReactor Coolant SystemRHRResidual Heat RemovalROPReactor Oversight ProcessRRWRisk Reduction WorthRWSTRefueling Water Storage TankSATStation Auxiliary TransformerSBOStation BlackoutSDPSignificance Determination ProcessSGSteam GeneratorSISafety Injection
FPPFire Protection Program
A-15AttachmentSPARStandardized Plant Analysis RiskSPINSet Point Information Network
FZFire Zone
: [[SPUS]] [[tretch Power Uprate]]
IPInspection Procedure
: [[SRS]] [[urveillance RequirementSSCStructure, System and Component]]
IP2Indian Point Unit 2
: [[SWS]] [[ervice Water]]
A-6AttachmentIPEIndividual Plant ExaminationIPECIndian Point Energy Center
: [[TCVT]] [[emperature Control ValveTDAFWPTurbine Driven Auxiliary Feedwater PumpUATUnit Auxiliary TransformerURIUnresolved ItemVacVolts Alternating CurrentVdcVolts Direct Current]]
IPEEEIndividual Plant Examination of External Events
IRInspection Report
NFPANational Fire Protection Association
NRCNuclear Regulatory Commission
PARPublicly Available Records
P&IDPiping and Instrumentation Drawing
: [[QAQ]] [[uality Assurance]]
: [[SAO]] [[Station Administrative Order]]
: [[SERS]] [[afety Evaluation Report]]
: [[SG]] [[Steam Generator]]
: [[SSAS]] [[afe Shutdown Analysis]]
: [[SSD]] [[Safe Shutdown]]
SUNSISensitive Unclassified Non-Safeguards Information
: [[UFSARU]] [[pdated Final Safety Analysis Report]]
}}
}}

Revision as of 11:42, 23 October 2018

IR 05000247-07-006; on 04/23 - 05/18/2007; Indian Point Nuclear Generating, Unit 2; Triennial Fire Protection Team Inspection
ML071730036
Person / Time
Site: Indian Point Entergy icon.png
Issue date: 06/20/2007
From: Rogge J F
Engineering Region 1 Branch 3
To: Dacimo F
Entergy Nuclear Operations
References
IR-07-006
Download: ML071730036 (21)
v • d • e


Text

June 20, 2007

Mr. Fred DacimoSite Vice President Entergy Nuclear Operations, Inc.

Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249

SUBJECT: INDIAN POINT UNIT 2 - NRC TRIENNIAL FIRE PROTECTION INSPECTIONREPORT 05000247/2007006

Dear Mr. Dacimo:

On May 17, 2007, the NRC completed a triennial fire protection team inspection at your IndianPoint Nuclear Generating Unit 2. The enclosed report documents the inspection results, which were discussed at an exit meeting on May 17, 2007, with you and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, no findings of significance were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/ADAMS.html (the Public Electronic Reading Room).

Sincerely,/RA/John F. Rogge, ChiefEngineering Branch 3 Division of Reactor Safety June 20, 2007Mr. Fred DacimoSite Vice President Entergy Nuclear Operations, Inc.

Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249

SUBJECT: INDIAN POINT UNIT 2 - NRC TRIENNIAL FIRE PROTECTION INSPECTIONREPORT 05000247/2007006

Dear Mr. Dacimo:

On May 17, 2007, the NRC completed a triennial fire protection team inspection at your IndianPoint Nuclear Generating Unit 2. The enclosed report documents the inspection results, which were discussed at an exit meeting on May 17, 2007, with you and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, no findings of significance were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/ADAMS.html (the Public Electronic Reading Room).

Sincerely,/RA/John F. Rogge, ChiefEngineering Branch 3 Division of Reactor SafetySUNSI Review Complete: JFR (Reviewer's Initials

)DOCUMENT NAME: C:\FileNet\ML071730036.wpdAfter declaring this document "An Official Agency Record" it will be released to the Public.To receive a copy of this document, indicate in the box:

" C" = Copy withoutattachment/enclosure " E" = Copy with attachment/enclosure " N" = No copyOFFICERI/DRSNRI/DRPRI/DRSNAMERFuhrmeister/RFECobey/JDO forJRogge/JFRDATE06/7/0706/14/0706/20/07OFFICIAL RECORD COPY* See Previous Concurrence PageADAMS ACC # ML071730036 F. Dacimo2Docket No. 50-247License No. DPR-26

Enclosure:

NRC Inspection Report 05000247/2007006 cc w/encl:G. J. Taylor, Chief Executive Officer, Entergy Operations M. Kansler, President, Entergy Nuclear Operations, Inc.

J. T. Herron, Senior Vice President for Operations M. Balduzzi, Senior Vice President, Northeastern Regional Operations W. Campbell, Senior Vice President of Engineering and Technical Services C. Schwarz, Vice President, Operations Support (ENO)

K. Polson, General Manager Operations O. Limpias, Vice President, Engineering (ENO)

J. McCann, Director, Licensing (ENO)

C. D. Faison, Manager, Licensing (ENO)

R. Patch, Director of Oversight (ENO)

J. Comiotes, Director, Nuclear Safety Assurance P. Conroy, Manager, Licensing T. C. McCullough, Assistant General Counsel, Entergy Nuclear Operations, Inc.

M. Balboni, Deputy Secy, New York State Energy, Research and Development Authority P. Eddy, Electric Division, New York State Department of Public Service C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law D. O'Neill, Mayor, Village of Buchanan J. G. Testa, Mayor, City of Peekskill R. Albanese, Four County Coordinator S. Lousteau, Treasury Department, Entergy Services, Inc.

Chairman, Standing Committee on Energy, NYS Assembly Chairman, Standing Committee on Environmental Conservation, NYS Assembly Chairman, Committee on Corporations, Authorities, and Commissions M. Slobodien, Director, Emergency Planning B. Brandenburg, Assistant General Counsel Assemblywoman Sandra Galef, NYS Assembly County Clerk, Westchester County Legislature A. Spano, Westchester County Executive R. Bondi, Putnam County Executive C. Vanderhoef, Rockland County Executive E. A. Diana, Orange County Executive T. Judson, Central NY Citizens Awareness Network M. Elie, Citizens Awareness Network D. Lochbaum, Nuclear Safety Engineer, Union of Concerned Scientists Public Citizen's Critical Mass Energy Project M. Mariotte, Nuclear Information & Resources Service F. Zalcman, Pace Law School, Energy Project L. Puglisi, Supervisor, Town of Cortlandt Congressman John Hall Congresswoman Nita Lowey Senator Hillary Rodham Clinton Senator Charles Schumer G. Shapiro, Senator Clinton's Staff J. Riccio, Greenpeace F. Dacimo3P. Musegaas, Riverkeeper, Inc.M. Kaplowitz, Chairman of County Environment & Health Committee A. Reynolds, Environmental Advocates M. Jacobs, Director, Longview School D. Katz, Executive Director, Citizens Awareness Network S. Tanzer, The Nuclear Control Institute K. Coplan, Pace Environmental Litigation Clinic M. Jacobs, IPSEC D. C. Poole, PWR SRC Consultant W. Russell, PWR SRC Consultant W. Little, Associate Attorney, NYSDEC M. J. Greene, Clearwater, Inc R. Christman, Manager Training and Development J. Spath, New York State Energy Research, SLO Designee A. J. Kremer, New York Affordable Reliable Electricity Alliance (NY AREA)

F. Dacimo4Distribution w/encl:(via E-mail)

S. Collins, RAM. Dapas, DRA J. Lamb, RI OEDO J. Lubinski, NRR M. Kowal, NRR J. Boska, PM, NRR J. Hughey, NRR E. Cobey, DRP D. Jackson, DRP M. Cox, DRP, Senior Resident Inspector - Indian Point 2 G. Bowman, DRP, Resident Inspector - Indian Point 2 R. Martin, DRP, Resident OA Region I Docket Room (w/concurrences)

ROPreports@nrc.gov M. Gamberoni, DRS J. Rogge, DRS R. Fuhrmeister, DRP EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION IDocket No.50-247 License No.DPR-26 Report No.05000247/2007006 Licensee:Entergy Nuclear Northeast (Entergy)

Facility:Indian Point Nuclear Generating Unit 2 Location:450 Broadway, GSBBuchanan, NY 10511-0249Dates:April 23, 2007 through April 27, 2007 andMay 14, 2007 through May 18, 2007Inspectors:R. Fuhrmeister, Senior Project Engineer, DRPL. Cheung, Senior Reactor Inspector, DRS M. Patel, Reactor Inspector, DRS K. Diederich, Reactor Inspector, DRSApproved by:John F. Rogge, ChiefEngineering Branch 3 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000247/2007006; 04/23 - 05/18/2007; Indian Point Nuclear Generating Unit 2; TriennialFire Protection Team Inspection.The report covered a two-week triennial fire protection team inspection by a Region I seniorproject inspector and three Region I specialist inspectors. The NRC's program for overseeingthe safe operation of commercial nuclear power reactors is described in NUREG-1649,

"Reactor Oversight Process," Revision 3, dated July 2000.A.

NRC-Identified Findings

No findings of significance were identified.

B.Licensee-Identified Violations

None.

Enclosure

REPORT DETAILS

BackgroundThis report presents the results of a triennial fire protection inspection conducted in accordancewith NRC Inspection Procedure (IP) 71111.05T, "Fire Protection." The objective of the inspection was to assess whether Entergy Nuclear Northeast has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are being properly maintained at the Indian Point Energy Nuclear Generating Unit 2 (IP2). The following fire areas (FAs) and fire zones (FZs) were selected for detailed review based on risk insights from the IP2 Individual Plant Examination (IPE) and Individual Plant Examination ofExternal Events (IPEEE):Fire Area P, FZ-1Fire Area A, FZ-1AFire Area A, FZ-11Fire Area I, FZ-22/63AThe inspection team evaluated Entergy's fire protection program (FPP) against applicablerequirements which included facility operating license condition 2.K, NRC safety evaluation reports, 10 CFR 50.48 and 10 CFR 50, Appendix R. The team also reviewed related documents that included the Updated Final Safety Analysis Report (UFSAR), the fire hazards analysis (FHA) and the post-fire safe shutdown analysis (SSA).Specific documents reviewed by the team are listed in the attachment.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems1R05Fire Protection

.01 Post-Fire Safe Shutdown From Outside the Main Control Room (Alternative Shutdown)and Normal Shutdown

a. Inspection Scope

MethodologyThe team reviewed the safe shutdown analysis, operating procedures, piping andinstrumentation drawings (P&IDs), electrical drawings, the UFSAR and other supporting documents to verify that hot and cold shutdown could be achieved and maintained from outside the control room for fires that rely on shutdown from outside the control room.

This review included verification that shutdown from outside the control room could be performed both with and without the availability of offsite power. Plant walkdowns were also performed to verify that the plant configuration was consistent with that described in the safe shutdown and fire hazards analyses. These inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant 2Enclosuremakeup, reactor decay heat removal, process monitoring instrumentation and supportsystems functions. The team verified that the systems and components credited for use during post-fire safe shutdown would remain free from fire damage. The team verified that the transfer of control from the control room to the alternative shutdown locations would not be affected by fire-induced failures.Similarly, for fire areas that utilize shutdown from the control room, the team alsoverified that the shutdown methodology properly identified the components and systems necessary to achieve and maintain safe shutdown conditions. Operational ImplementationThe team verified that the training program for licensed and non-licensed operatorsincluded alternative shutdown capability. The team also verified that personnel required for safe shutdown using the normal or alternative shutdown systems and procedures were trained, available onsite at all times, and exclusive of those assigned as fire brigade members.The team reviewed the adequacy of procedures utilized for post-fire safe shutdown andperformed an independent walk through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also verified that operators could reasonably be expected to perform specific actions within the time required to maintain plant parameters within specified limits. Time critical actions which were verified included restoring alternating current (AC) electrical power, establishing alternate shutdown system operation, establishing reactor coolant makeup and establishing decay heat removal.Specific procedures reviewed for alternative shutdown, including shutdown from outsidethe control room included the following:2-AOP-SSD-1, Rev. 9, Control Room Inaccessibility Safe Shutdown Control2-ONOP-FP-001, Rev. 2, Plant FiresThe team reviewed manual actions to ensure that they had been properly reviewed andapproved and that the actions could be implemented in accordance with plant procedures in the time necessary to support the safe shutdown method for each selected fire area. The team also reviewed periodic testing records of the alternative shutdown transfer capability and instrumentation and control functions to ensure the tests demonstrated the functionality of the alternative shutdown capability.

b. Findings

No findings of significance were identified.

3Enclosure.02Protection of Safe Shutdown Capabilities

a. Inspection Scope

The team reviewed the fire hazards analysis, safe shutdown analyses and supportingdrawings and documentation to verify that safe shutdown capabilities were properly protected. The team ensured that separation requirements of 10 CFR 50, Appendix R, Section III.G, were maintained for the credited safe shutdown equipment includingsupporting power, control and instrumentation cables. This review included an assessment of the adequacy of the selected systems for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring, and associated support system functions.The team reviewed Entergy's procedures and programs for the control of ignitionsources and transient combustibles to assess their effectiveness in preventing fires and controlling combustible loading within limits established in the Combustible Loading Calculation. A sample of hot work and transient combustible control permits were also reviewed. The team performed plant walkdowns to verify that protective features were being properly maintained and administrative controls were being implemented.The team also reviewed Entergy's design control procedures to ensure that the processincluded appropriate reviews and controls to assess plant changes for any potential adverse impact on the fire protection program, post-fire safe shutdown analysis, and procedures.

b. Findings

No findings of significance were identified..03Passive Fire Protection

a. Inspection Scope

The team walked down accessible portions of the selected fire areas to observe materialcondition and the adequacy of design of fire area boundaries (including walls, fire doors and fire dampers) to ensure they were appropriate for the fire hazards in the area.

b. Findings

No findings of significance were identified.

4Enclosure.04Active Fire Protection

a. Inspection Scope

The team reviewed the design, maintenance, testing and operation of the fire detectionand suppression systems in the selected plant fire areas. This included verification that the manual and automatic detection and suppression systems were installed, tested and maintained in accordance with the NFPA code of record and that they would control or extinguish fires associated with the hazards in the selected areas. A review of the design capability of suppression agent delivery systems were verified to meet the code requirements for the fire hazards involved. The team also performed a walkdown of accessible portions of the detection and suppressions systems in the selected areas as well as a walkdown of major system support equipment in other areas (e.g. fire protection pumps, Halon storage tanks and supply system) to assess the materialcondition of the systems and components.The team reviewed electric and diesel fire pump flow and pressure tests to ensure thatthe pumps were meeting their design requirements. The team also reviewed the fire main loop flow tests to ensure that the flow distribution circuits were able to meet the design requirements. The team also assessed the fire brigade capabilities by reviewing training andqualification records, drill critique records, and observing live fire training. The team also reviewed pre-fire plans and smoke removal plans for the selected fire areas to determine if appropriate information was provided to fire brigade members and plant operators to identify safe shutdown equipment and instrumentation, and to facilitate suppression of a fire that could impact post-fire safe shutdown.

b. Findings

No findings of significance were identified.

.05 Protection From Damage From Fire Suppression Activities

a. Inspection Scope

The team reviewed documents and walked down the selected fire areas to verify thatredundant trains of systems required for hot shutdown were not subject to damage from fire suppression activities or from the rupture or inadvertent operation of fire suppression systems. Specifically, the team verified that:A fire in one of the selected fire areas would not directly, through production ofsmoke, heat or hot gases, cause activation of suppression systems that could potentially damage all redundant safe shutdown trains, 5EnclosureA fire in one of the selected fire areas (or the inadvertent actuation or rupture ofa fire suppression system) would not directly cause damage to all redundant safe shutdown trains (e.g., sprinkler caused flooding of other than the locally affected train), and Adequate drainage was provided in areas protected by water suppressionsystems.

b. Findings

No findings of significance were identified..06Alternative Shutdown CapabilityAlternative shutdown capability for the selected fire areas inspection utilizes shutdownfrom outside the control room and is discussed in Section 1R05.01 of this report..07Circuit Analyses

a. Inspection Scope

The team verified that Entergy performed a post-fire safe shutdown analysis for theselected fire areas and that the analysis appropriately identified the structures, systems and components important to achieving and maintaining post-fire safe shutdown.

Additionally, the team verified that Entergy's analysis ensured that necessary electrical circuits were properly protected and that circuits that could adversely impact safe shutdown due to hot shorts, shorts to ground or other failures were identified, evaluated and dispositioned to ensure spurious actuations would not prevent safe shutdown.The team's review considered fire and cable attributes, potential undesirableconsequences and common power supply/bus concerns. Specific items included the credibility of the fire threat, cable construction details, cable failure modes, spurious actuations, actuations resulting in flow diversion or loss of coolant events.The team also reviewed wiring diagrams and routing lists for a sample of componentsrequired for post-fire safe shutdown to verify that cables were routed as described in the cable routing reports.Cable failure modes were reviewed for the following components:

Charging Pumps 21 and 23,Service Water Pump 24,Auxiliary Feedwater Pump 21,Component Cooling Pump 23, andCircuit breakers associated with the 13.8 kV Alternate Safe Shutdown PowerSystem.

6EnclosureThe team reviewed circuit breaker coordination studies to ensure equipment needed toconduct post-fire safe shutdown activities would not be impacted due to a lack of coordination. The team confirmed that coordination studies had addressed multiple faults due to fire. Additionally, the team reviewed a sample of circuit breaker maintenance and records to verify that circuit breakers for components required for post-fire safe shutdown were properly maintained in accordance with procedural requirements.

b. Findings

No findings of significance were identified..08Communications

a. Inspection Scope

The team reviewed safe shutdown procedures, the SSA and associated documents toverify an adequate method of communications would be available to plant operators following a fire. During this review, the team considered the effects of ambient noise levels, clarity of reception, reliability and coverage patterns. The team also inspected the designated emergency storage lockers to verify the availability of portable radios for the fire brigade and plant operators. The team also verified that communications equipment such as repeaters and transmitters would not be affected by a fire.

b. Findings

No findings of significance were identified..09Emergency Lighting

a. Inspection Scope

The team observed the placement and coverage area of eight-hour emergency lightsthroughout the selected fire areas and evaluated their adequacy for illuminating access and egress pathways and any equipment requiring local operation or instrumentation monitoring for post-fire safe shutdown. The team also verified that the battery power supplies were rated for at least an eight-hour capacity. Preventive maintenance procedures, the vendor manual, completed surveillance tests and battery replacement practices were reviewed to verify that the emergency lighting was being maintained in a manner that would ensure reliable operation.

b. Findings

No findings of significance were identified.

7Enclosure.10Cold Shutdown RepairsThe team verified that Entergy had dedicated repair procedures, equipment, andmaterials to accomplish repairs of components required for cold shutdown which might be damaged by the fire to ensure cold shutdown could be achieved within the time frames specific in their design and licensing bases. The inspectors verified that therepair equipment, components, tools and materials (e.g. pre-cut cables with prepared attachment lugs) were available and accessible on site..11Compensatory Measures

a. Inspection Scope

The team verified that compensatory measures were in place for out-of-service,degraded, or inoperable fire protection and post-fire safe shutdown equipment, systems, or features (e.g., detection and suppression systems and equipment, passive fire barriers, pumps, valves or electrical devices providing safe shutdown functions or capabilities). The team also verified that the short term compensatory measures compensated for the degraded function or feature until appropriate corrective action could be taken and that Entergy was effective in returning the equipment to service in a reasonable period of time.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES4OA2Identification and Resolution of Problems.01Corrective Actions for Fire Protection Deficiencies

a. Inspection Scope

The team verified that Entergy was identifying fire protection and post-fire safeshutdown issues at an appropriate threshold and entering them into the corrective action program. The team also reviewed a sample of selected issues to verify that Entergy had completed or planned appropriate corrective actions.

b. Findings

No findings of significance were identified.

8Enclosure4OA6Meetings, Including ExitExit Meeting SummaryOn May 18, 2007, the team presented the inspection results to Mr. F. Dacimo, Site VicePresident, and other members of the site staff. No proprietary information was included in this inspection report.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Entergy Nuclear Operations, Inc.

R. Burroni, Manager, Programs and Components
S. Wilkie, Senior Fire Protection Engineer
J. Cottam, Fire Protection Engineer
K. Elliott, Fire Protection Engineer
J. Etzweiler, Operations Supervisor
A. Singer, Training Supervisor
M. Yee, Electrical Engineer
G. Dahl, Licensing Technical Specialist

NRC

J. Rogge, Chief, Engineering Branch 3, Division of Reactor Safety
W. Cook, Senior Reactor Analyst, Division of Reactor Safety
M. Cox, Senior Resident Inspector, IP2
D. Jackson, Acting Senior Resident, IP3
G. Bowman, Resident Inspector, IP2
B. Wittick, Resident Inspector, IP3

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened NoneOpen and

Closed

None

Closed

None

Discussed

None

A-2Attachment

LIST OF DOCUMENTS REVIEWED

Calculations/Engineering Evaluation ReportsPGI-00577, Evaluation of Cable Spreading Room to CAS Corridor and Stairwell 3 Fire BarrierInterface, Rev. 0FMX-00358-00, Component Cooling Water (CCW) Pump Curbing Volume Calculation, Rev. 4

FLEX-00160-02, Rev. 2, IP2 Evaluation of Alternate Power Supplies
EGP-00150-00, Appendix R Alternate Safe Shutdown System Voltage Drop Analysis, ElectricSupply through Indian Point 1.EGE-00001-02, Class 1E Motor Minimum Starting Voltage and Acceleration Time Calculations
RPT-05-00084, Rev. 0, IP2 10
CFR 50 Appendix R Safe-Shutdown Manual Action FeasibilityReportIP2-RPT-03-00015, Rev. 3, IP2 Fire Hazards Analysis
IP-RPT-04-00188, Rev. 1, Evaluation of Hemyc Wrap Fire Protective Systems
IP-RPT-05-00071, Rev. 1, IP2 10
CFR 50 Appendix R Safe Shutdown Separation Analysis
IP-RPT-05-00071, Rev. 2, Cable Logic Report
NEA-00031-01, Rev. 1, SG Boil-Dry Analysis
IP-CALC-05-01034, Rev. 0, Appendix R Cooldown Benchmark and Sensitivity Analysis UsingRETRAN-3DIP-CALC-06-00029, Rev. 0, Appendix R Cooldown to RHR Initiation Using
RERAN-3DProceduresEN-DC-127, Control of Hot Work and Ignition Sources, Rev. 2SMM-DC-901, IPEC Fire Protection Program Plan, Rev. 2
SA0-703, Fire Protection Impairment Criteria and Surveillance, Rev. 25
2-BRK-020-ELC, Rev. 0, Westinghouse Model 150DH1000E (13.8kV) Air Circuit BreakersMaintenance Circuit Breakers Maintenance Procedure2-PC-R37, Rev. 11, Alternate Safe Shutdown and Remote shutdown Instrument CalibrationProcedures2-SOP-27.1.3, Rev. 30, Operation of 13.8 KV System
EN-OP-115, Rev. 3, Conduct of Operations, Addendum 10.4, IPEC Plant Specific Addendum
OAP-115, Rev. 05, Operations Commitments and Policy Details
2-AOP-SSD-1, Rev. 09, Control Room Inaccessibility Safe Shutdown Control
2-AOP-SSD-1
BGD-R07, Background Document for 2-AOP-SSD-1, Rev. 07
AOI 27.1.9.2, Rev. 0, Providing Appendix R Power from Unit 3
SAO-703, Rev. 25, Fire Protection Impairment Criteria and Surveillance
SMM-DC-901, Rev. 2, IPEC Fire Protection Program PlanCompleted Tests/Surveillances0-PT-M001, Fire Brigade Equipment Inventory and Inspection, Rev. 3, Completed 04/19/072PT-2Y017, Penetration Fire Barrier Seal Inspections, Rev. 0, Completed 12/13/05
PT-EM9, Fire Dampers Operability, Rev. 4, Completed 11/16/06
PT-SA12A, Ionization Type Smoke Detector (Conventional), Rev. 8, Completed 02/06/07
A-3AttachmentPT-SA12B, Ionization Type Smoke Detector (PAB), Rev. 6, Completed 04/09/07PT-SA12C, Ionization Type Smoke Detector (Electrical and Pipe Penetration Area), Rev. 6,Completed 04/10/07PT-SA13, Cable Spreading Room Halon System, Rev. 9, Completed 03/13/07
PT-19, Cable Spreading Room Halon System, Rev. 10, Completed 12/21/06
2-PT-A023, Fire Main Booster Pump Capacity Test, Rev. 10, Completed 06/14/06
PT-A40, Diesel Fire Pump Capacity Test, Rev. 0, Completed 03/08/07
2-PT-3Y015A, Underground Fire Loop Flow, Rev. 2, Completed 09/23/04
PMT-I2-2658, Installation of Halon System in Cable Spreading Room, Completed 12/18/79
IP2-04-23808, 5/22/06 performance of
PC-2Y 1, RCS Alternate Safe Shutdown TemperatureMonitor Calibration, Rev. 6IP2-04-30257, 4/23/06 performance of
PC-2Y70, Source Range Neutron Flux (N-5143)Channel Calibration, Rev. 2IP2-04-31441, 5/5/06 performance of 2-PC-R37, Alternate Safe Shutdown and RemoteShutdown Instruments, Rev. 11IP-06-22688, 4/23/07 performance of 0-PT-M002, Appendix R Equipment Inventory andInspection, Rev. 3QS-2006-IP-04, Surveillance Report: Performance of Appendix R Safe Shutdown Procedure,4/18/06Quality Assurance AuditsAudit Report A03-12-I, IPEC Fire Protection ProgramQA-09-2005-IP-1, IPEC Fire Protection program Audit
QA-09-2006-IP-1, IPEC Fire Protection Program Audit
QS-2006-IP-04, Performance of Appendix R Safe Shutdown Procedure, 2-AOP-SSD-1,Revision 7DrawingsD-8775, Halon System Cable Spreading Room, Sh. 2, Rev. 4D-8775, Halon System Cable Spreading Room, Sh. 3, Rev. 4
D-8775, Halon System Cable Spreading Room, Sh. 4, Rev. 3
D-8775, Halon System Cable Spreading Room, Sh. 5, Rev. 2
D-8775, Halon System Cable Spreading Room, Sh. 6, Rev. 2
D-8677, Halon System Piping Cable Spreading Room, Sh. 4, Rev. 1
400411, Fire Area/Zone Arrangement - EL. 100', Sh. 1, Rev. 1
400403, Fire Area/Zone Arrangement - EL. 53', Sh. 1, Rev. 2
400404, Fire Area/Zone Arrangement - EL. 80', Sh. 1, Rev. 2
400405, Fire Area/Zone Arrangement - EL. 96', Sh. 1, Rev. 2
21-F-4022, Flow Diagram Ventilation System Containment, Primary Aux. Building, Sh. 1, Rev. 62A208377-11, Unit 2 One Line Diagram.
A208088-42, One Line Diagram of 480 Vac Switchgears 21 and 23.
A208064-5, Level and Pressure Instrument for Steam Generator and Pressurizer Arrangement,Piping.
A-4AttachmentA208065-11, Level and Pressure Instrument for Steam Generator and PressurizerArrangement, Piping Details - Instrumentation.A209561-5, Steam Generator and Pressurizer Instrumentation Arrangement OutsideContainment.A208247-8, Modification to Pressurizer Level transmitter Cabinet - Rack No. 19Instrumentation.A208248-6, Modification to Steam Generator Level transmitter Rack No. 21. Instrumentation.
B225132-12, Elementary Wiring Diagram for Charging Pumps 21 and 23.
B225137-10, Elementary Wiring Diagram for Residual Heat Removal Pumps 21 and 22.
B225149-1-24, Elementary Wiring Diagram for Service Water Pump 23.
308762-0, Instrument Air and Nitrogen Supply to Pressurizer and Steam Generator FlowDiagram.IP2-S-000193-1,
SWD-Control and Indication Service Water Pump 24
21-LL-3118-30, Breaker 52/AF1 Auxiliary Feedwater Pump 21.
260503-03, Loop Diagram RCS Pressure SSD Level and Pressure, Loop Nos. 3101 and 3105
A138040-54, Unit 1 One Line diagram, 13.8kV and 440V Systems.
244016-19, Unit 1 One Line 440V Switchgear Unit Substation 11RW1, 12RW3, 12FD3, MCC's10M,10N 10Z and 10X.9321-F-36033, IP3 Appendix R On-site Alternate Power Source, Diesel Generator Main One-Line Diagram, Revision10A209762, Rev 67, Flow Diagram Service Water System Nuclear Steam Supply Plant, sheet 2 of
29321-F-2722-117, Rev 117, Flow Diagram Service Water System Nuclear Steam Supply Plant,sheet 1 of 29321-F-2019, Flow Diagram Boiler Feedwater
21-F-3056-41, Rev. 41, Control Building, Elev. 33'-0" Cable Spreading Room Cable Trays -
PlanA206640-10, Arrangement of Equipment in Cable Spreading Room, Elev. 33'-0", West Half -Plan &Sects.Pre-Fire PlansPFP-209-FZ-1, Component Cooling Pump Room, Rev. 0PFP-215-FZ-1A, General Floor Plan - Fan House, Rev. 0
PFP-252-FZ-11, Cable Spreading Room, Rev. 0
PFP-264-FZ-22 & 63A, Intake Structure, Rev. 0Fire Brigade TrainingIP-SMM-TQ-122, Fire Brigade Drill Attendance Record, Rev. 1Drill Records 1

st - 4 th Quarter 2006, 1

st Quarter 2007.

A-5AttachmentOperator Safe Shutdown TrainingI2LP-ILO-ASSD, Rev. 14, Instructor Lesson Plan: Alternate Safe Shutdown SystemTransient Combustible EvaluationsEN-DC-161, Transient Combustible Evaluation,07-011 for Unit 2 Intake Structure, 4/26/07

Miscellaneous

DocumentsECRIS cable routing data report, 5/14/07ECRIS cable routing data report, 5/15/07
TB-04-22, Westinghouse Technical Bulletin: Reactor Coolant Pump Seal Performance -Appendix R Compliance and Loss fo All Seal Cooling, Rev. 1Condition Reports1999-015462002-115362003-018252004-006072004-006092004-014452006-008932006-01212
2006-033732006-052992006-068382006-06844
2007-001252007-001432007-006362007-00743
2007-009352007-009362007-009582007-01014
2007-010542007-010762007-011762007-01254
2007-013912007-017552007-017572007-10769
2007-017712007-017722007-017812007-02026
2007-020392007-020522007-02067Work Orders NP9262151NP9262152NP9157705NP9261088NP9259111NP9262153NP9364109NP9153738

LIST OF ACRONYMS

USEDACAlternating CurrentAOPAbnormal Operating Procedure

CFRC ode of Federal Regulations
CO 2Carbon Dioxide

DRSDivision of Reactor Safety

FAFire Area

FHAFire Hazards Analysis

FPPFire Protection Program

FZFire Zone

IPInspection Procedure

IP2Indian Point Unit 2

A-6AttachmentIPEIndividual Plant ExaminationIPECIndian Point Energy Center

IPEEEIndividual Plant Examination of External Events

IRInspection Report

NFPANational Fire Protection Association

NRCNuclear Regulatory Commission

PARPublicly Available Records

P&IDPiping and Instrumentation Drawing

QAQ uality Assurance
SAO Station Administrative Order
SERS afety Evaluation Report
SG Steam Generator
SSAS afe Shutdown Analysis
SSD Safe Shutdown

SUNSISensitive Unclassified Non-Safeguards Information

UFSARU pdated Final Safety Analysis Report
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