IR 05000247/2011007

IR 05000247-11-007 and 05000286-11-007, on 11/14/11 - 12/01/11, for Indian Point, Units 2 and 3, NRC Evaluation of Changes, Tests, or Experiments and Permanent Plant Modifications Team

ML12013A162
Person / Time
Site:	Indian Point
Issue date:	01/13/2012
From:	Doerflein L T Engineering Region 1 Branch 2
To:	Ventosa J Entergy Nuclear Operations
References
IR-11-007
Download: ML12013A162 (34)

Text

^*'b,s**' January 13, ?01?Mr. John VentosaSite Vice PresidentEntergy Nuclear Operations, lnc.lndian Point Energy Center450 Broadway, GSBP.O. Box 249Buchanan, NY 1051 1-0249

SUBJECT: INDIAN POINT NUCLEAR GENERATING UNITS 2 AND 3 - NRCEVALUATION OF CHANGES, TESTS, OR EXPERIMENTS AND PERMANENTPLANT MOD I FI CATIONS TEAM I NSPECTION REPORT O5OOO247 I2O1 1 OO7AND 0500028612011007

Dear Mr. Ventosa:

On December 1, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at Indian Point Nuclear Generating Units 2 and 3. The enclosed inspection reportdocuments the inspection results, which were discussed on December 1, 2011, withMr. L. Coyle and other members of your staff, and during a subsequent telephone callwithMr. P. Conroy on January 12,2012.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.ln conducting the inspection, the team reviewed selected procedures, calculations and records,observed activities, and interviewed station personnel.This report documents one NRC-identified finding which was of very low safety significance(Green). The finding was determined to involve a violation of NRC requirements. However,because of the very low safety significance of the violation and because it was entered into yourcorrective action program, the NRC is treating the finding as a non-cited violation (NCV)consistent with Section2.3.2 of the NRC Enforcement Policy. lf you contest the NCV in thisreport, you should provide a response within 30 days of the date of this inspection report, withthe basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: DocumentControl Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator,Region l;the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,Washington, D.C. 20555-0001; and the NRC Senior Resident Inspector at lndian Point NuclearGenerating Unit 2. In addition, if you disagree with the cross-cutting aspect assigned to thefinding in this report, you should provide a response within 30 days of the date of this inspectionreport, with the basis of your disagreement, to the Regional Administrator, Region l, and theNRC Senior Resident lnspector at Indian Point Nuclear Generating Unit 2.+***i J. VentosaIn 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 (PARS) component of theNRC's document system, Agencywide Documents Access and Management System (ADAMS).ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (thePublic Electronic Reading Room).Engineering Branch 2Division of Reactor SafetyDocket No. 50-247, 50-286License No. DPR-26. DPR-64

Enclosure:

I n s pecti o n Re po rt 0 5000247 l 2O I 1 007 ; 05000286 l 20 1 1 007wl

Attachment:

Supplemental Informationcc w/encl: Distribution via ListServ ln 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 (PARS) component of theNRC's document system, Agencywide Documents Access and Management System (ADAMS).ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (thePublic Electronic Reading Room).

Sincerely,/RNLawrence T. Doerflein; ChiefEngineering Branch 2Division of Reactor Safe$Docket No. 50-247, 50-286License No. DPR-26, DPR-64

Enclosure:

f nspection Report 05000247 l2O1 1007 ; 05000286/201 1007M

Attachment:

Supplemental InformationDistribution Mencl:W. Dean, RAD. Lew, DRAD. Roberts, DRPJ. Tappert, DRPJ. Clifford, DRPC. Miller, DRSP. Wilson, DRSM. Franke, Rl OEDOM. Gray, DRPB. Bickett, DRPS. McCarver, DRPM. Jennerich, DRPM. Catts, DRP, SRI- Indian Point 2P. Cataldo, DRP, SRI- Indian Point 3D. Hochmuth, DRP, Resident OARidsNrrPM I ndian Point ResourceRidsNrrDorlLpl 1 -1 ResourceROPreportsResourceL. Doerflein, DRSE. Burket, DRSSUNSI Review Complete: LTD (Reviewe/s Initials)ADAMS ACC #M112013A162DOCUMENT NAME: G:\DRS\Engineering Branch 2\Burket\lPmodsreport2011007.docxAflordodaringtN!document.AnoflidalAgencyRo@td.n*llb6rolsas*dtothepublio.ToE6tF.copyofthl.dooumnt'lhdlo.tolnth.xl'c'=&pyOFFICERI/DRSRI/DRSlRr/DRP I lRl/DRS INAME EBuTkeUECBWSchmidtAlVACI MGray/MG lLDoerflein/LTDDATE 1212Q11112t20t11l 12t21t11 l 1t13112ICIALOFF Docket Nos.:License Nos.:Report No.:Licensee:Facility:Location:Inspection Period:Inspectors:Approved By:U.S. NUCLEAR REGULATORY COMMISSIONREGION I50-247,50-286DPR-26, DPR-6405000247 l 201 1 007 and 05000 286 l 201 1 0OTEntergy Nuclear Northeast (Entergy)f ndian Point Nuclear Generating Units 2 and 3450 Broadway, GSBBuchanan, NY 1051 1-0249November 14,2011 - December 1,2011E. Burket, Reactor Inspector, Division of Reactor Safety (DRS),Team LeaderF. Arner, Senior Reactor Inspector, DRSD. Orr, Senior Reactor lnspector, DRSJ. Richmond, Senior Reactor lnspector, DRSJ. Brand, Reactor Inspector, DRSM. Orr, Reactor lnspector, DRSLawrence T. Doerflein, ChiefEngineering Branch 2Division of Reactor SafetyEnclosure

SUMMARY OF FINDINGS

lR 0500024712011007, 0500028612011007; 1111412011-1210112011; lndian Point NuclearGenerating Units 2 and 3; Evaluations of Changes, Tests, or Experiments and Permanent PlantModifications.This report covers a two week on-site inspection period of the evaluations of changes, tests, orexperiments and permanent plant modifications. The inspection was conducted by six regionbased engineering inspectors. One finding of very low risk significance (Green) was identified.The finding was also considered to be a non-cited violation (NCV). The significance of mostfindings is indicated by their color (Green, White, Yellow, Red) using NRC lnspection ManualChapter (lMC) 0609, "Significance Determination Process" (SDP). The cross-cutting aspectwas determined using IMC 0305, "Operating Reactor Assessment Program." Findings for whichthe SDP does not apply may be Green or be assigned a severity level after NRC managementreview. The NRC's program for overseeing the safe operation of commercial nuclear powerreactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, datedDecember 2006.

Cornerstone: Barrier Integrity.

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion lll,"Design Control," in that Entergy did not ensure that design changes, including fieldchanges, were subject to design control measures commensurate with those applied tothe original design. Entergy implemented an instrument setpoint change, but delayedre-calibration of the in-field setpoint values and did not evaluate the adequacy of thein-field actual setpoints, which were later found outside the value required by the designbasis. Specifically, Entergy revised surveillance procedures for the Unit 2 reactorprotection system (RPS) over-power delta{emperature (OPdT) instrument to use asetpoint value specified in the Core Operating Limits Report (COLR). However, theprocedures were not required to be performed until the next regularly scheduledsurveillance period. Technical Specification 3.3.1 requires the allowable values to be setas specified by the COLR. Two of the four instrument channels had in-field valuesoutside of the required allowable value. Entergy entered this issue into their correctiveaction program and performed an immediate operability evaluation and determined thatthe OPdT instrument was capable of performing its intended functions with the currentin-field values.The team determined that the failure to ensure in-service instrument setpoint valuessatisfied design and licensing basis requirements was a performance deficiency. Thisissue was more than minor because it was associated with the design control attribute ofthe Barrier Integrity Cornerstone and adversely affected the cornerstone objective toprovide reasonable assurance that physical design barriers (e.9., fuel cladding) protectthe public from radionuclide releases caused by accidents or events. The teamperformed a Phase 1 Significance Determination Process screening, in accordance withNRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization ofFindings," and determined the finding was of very low safety significance (Green)because it affected only fuel barrier portion of the barrier integrity cornerstone.Enclosure

The team determined that this finding had a cross-cutting aspect in the area of HumanPerformance, Work Practices because Entergy did not ensure adequate supervisory ormanagement oversight of a design change. IMC 0310, Aspect H.a(c)] (Section1R17.02.1)Other FindinqsNoneillEnclosure

REPORT DETAILS

1. REACTORSAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R17 Evaluations of Chanqes. Tests. or Experiments and Permanent Plant Modifications(rP 71 111.17).1 Evaluations of Chanqes. Tests. or Experiments (Unit 2: 22 samples; Unit 3: 20 samples)a. lnspection ScopeThe team reviewed four safety evaluations (two per unit) to determine whether thechanges to the facility or procedures, as described in the Updated Final Safety AnalysisReport (UFSAR), had been reviewed and documented in accordance with 10 CFR 50.59requirements. ln addition, the team evaluated whether Entergy had been required toobtain NRC approval prior to implementing the changes. The team interviewed plantstaff and reviewed supporting information including calculations, analyses, designchange documentation, procedures, the UFSAR, the Technical Specifications (TS), andplant drawings to assess the adequacy of the safety evaluations. The team comparedthe safety evaluations and supporting documents to the guidance and methods providedin Nuclear Energy Institute (NEl) 96-07, "Guidelines for 10 CFR 50.59 Evaluations," asendorsed by NRC Regulatory Guide 1.187, "Guidance for lmplementation of10 CFR 50.59, Changes, Tests, and Experiments," to determine the adequacy of thesafety evaluations.The team also reviewed a sample of thirty-eight (20 for Unit 2 and 18 for Unit 3)10 CFR 50.59 screenings for which Entergy had concluded that no safety evaluationwas required. These reviews were performed to assess whether Entergy's threshold forperforming safety evaluations was consistent with 10 CFR 50.59. The sample includeddesign changes, calculations, and procedure changes.The team reviewed the safety evaluations that Entergy had performed and approvedduring the time period covered by this inspection (i.e., since the last modificationsinspection) not previously reviewed by NRC inspectors. The screenings and applicabilitydeterminations were selected based on the safety significance, risk significance, andcomplexity of the change to the facility.In addition, the team compared Entergy's administrative procedures used to controlthescreening, preparation, review, and approval of safety evaluations to the guidance in NEI96-07 to determine whether those procedures adequately implemented the requirementsof 10 CFR 50.59. The reviewed safety evaluations and screenings are listed in theAttachment.b. FindinqsNo findings were identified.Enclosure

.2.2 ,1a.2Permanent Plant Modifications (9 samples per unit {18 total})Setpoint Chanoe for Unit 2 Reactor Protection Svstem Over-Power Delta-TemperaturelnstrumentInspection ScopeThe team reviewed a setpoint change associated with Engineering Change (EC)5000034071 that revised the tolerance for a time constant in the Over-PowerDelta-Temperature (OPdT)reactor protection system (RPS) instrument. The timeconstant tolerance was revised to make it consistent with the value specified in the CoreOperating Limits Report (COLR). The setpoint change had been a corrective actionpreviously identified in CR-lP2-2004-06713, to resolve inconsistencies betweenengineering calculations, surveillance tests and calibration procedures, and the COLR.Entergy determined that the actual field setpoint would be adjusted during the nextroutinely scheduled surveillance test.The team assessed Entergy's technical evaluations, calculations, and design details, andinterviewed engineering personnel to determine whether the revised time constanttolerance would allow the OPdT instrument to function in accordance with the design andlicensing bases requirements. Calculations, analyses, and procedures affected by thesetpoint change were reviewed to verify they had been properly updated. In addition, theteam evaluated Entergy's determination that the setpoint change did not requireimmediate implementation. A review of condition reports (CR) was performed todetermine whether there were any reliability or performance issues associated with thenew time constant tolerance. Additionally, the 10 CFR 50.59 screening determinationassociated with this modification was reviewed as described in section 1R17.1of thisreport. The documents reviewed are listed in the Attachment.Findinqslntroduction: The team identified a finding of very low safety significance (Green),involving a non-cited violation of 10 CFR 50, Appendix B, Criterion lll, "Design Control," inthat Entergy did not ensure that design changes, including field changes, were subject todesign control measures commensurate with those applied to the original design.Specifically, Entergy implemented an OPdT instrument setpoint change which revisedprocedures but did not confirm that the in-field actual setpoint values were within thetolerance required by the design change. Entergy subsequently evaluated the adequacyof the in-field actual setpoint values after the team identified that those values wereoutside the value required by the design basis.Description: ln 2003, Unit 2 was transitioned to lmproved Technical Specifications andadopted a COLR, which specified different values and tolerances for some RPSinstrument setpoints than the previous custom technical specifications. In 2004, Entergyimplemented a power up-rate at Unit 2. As part of the up-rate process, Westinghouseanalyzed the setpoints for the OPdT and Over-Temperature Delta'Temperature (OTdT)RPS instruments. During an Entergy staff review of the Westinghouse analysis, Entergyidentified that the OPdT time constant was not set as described in the COLREnclosure

3(CR-lP2-2004-06713). ln 2006, Setpoint Change Request SCR-06-2-009 was issued toresolve the discrepancy. In August 2011, Entergy identified that SCR-06-2-009 had notbeen completely implemented, and the value of the OPdT time constant had not beenrevised as intended. As a result, EC5000034071was prepared and implemented torevise the setpoint of the OPdT time constant to a value consistent with the COLR.EC5000034071 revised the OPdT time constant setpoint value in plant calculations andInstrumentation and Control (l&C) calibration and surveillance procedures to the valuespecified in the COLR. Specifically, the OPdT time constant was revised from a band of9.7 to 10.3 seconds, to a band of 10.0 to 10.6 seconds in the applicable l&C and TSsurveillance procedures. EC topic note detail 1.3 stated that immediate fieldimplementation was not required (i.e., no post-modification surveillance test orre-calibration was needed). Based on interviews with Entergy staff, the team determinedthat Entergy design engineering had not reviewed the actual in-field setpoint valuesduring the preparation or approval of the setpoint modification. Although the modificationapproved implementation of the setpoint change, it allowed the existing in-field actualsetpoints to remain unchanged until the next regularly scheduled surveillance period.Specifically, the COLR documented the design basis requirements for the OPdTinstrument setpoints, but the approved setpoint change did not evaluate a setpoint valuedifferent than specified in the COLR. The team identified that an actual in-field settingcould have been as low as 9.7 seconds verses a required setting of greater than or equalto 10 seconds. Therefore, the team concluded that Entergy had not applied the samelevel of design control to the in-field actual setpoints that had been applied to the originaldesign.The 10 CFR 50.59 screen determined that no safety evaluation was required, in part,because the revised tolerance band for the time constant was equal to or conservative ofthe value provided in the COLR. The team concluded that the 10 CFR 59.59 screen didnot evaluate the impact of allowing the existing setpoint to remain outside the design limitas required by the COLR.The team identified that TS Table 3.3.1-1, Reactor Protection System InstrumentationFunction 6, required the OPdT setpoints to be set as specified in the COLR. The COLR(i.e., 2-GMPH-RPC-6, revision 13) Attachment2, OPdT Allowable Value, specified thatthe OPdT time constant be equal to or greater than 10 seconds. The team reviewed themost recent as-left calibration results and identified that OPdT channels 2 and 4 were leftset at 9.9 and 9.8 seconds, respectively; channels 1 and 3 were set at 10.2 and 10.3seconds, respectively. In follow-up to NRC questions regarding extent-of-condition,Entergy determined that the Unit 3 surveillance procedures would allow the OPdT timeconstants to be set as low as 9.5 seconds; allfour Unit 3 channels had as-left settingsgreater than 10 seconds. Entergy performed an immediate operability evaluation anddetermined that the OPdT instrument was capable of performing its intended functionswith a time constant as short as 9.7 seconds. Entergy entered this issue into theircorrective action program as CR-lP2-201 1-06047 and CR-lP3-201 1 -05353.The team reviewed a Westinghouse assessment, performed as part of Entergy'soperability evaluation. Westinghouse determined that the conclusions of the Unit 2Enclosure 4UFSAR remained valid. To reach its conclusion, Westinghouse evaluated the SteamlineBreak Mass and Energy Release Analysis, Steam Generator Tube Rupture Analysis, andthe Hot Full Power Steamline Break event. The team determined that Entergy'smodification review of EC5000034071and 10 CFR 50.59 screening only documented areview of the Hot Full Power Steamline Break event. In addition, the team notedEntergy's design group did not perform an interface review with either reactor engineering(responsible for assessing core thermal limits), or nuclear analysis (responsible forassessing affects on response time assumptions contained in design and licensing basisanalysis). Entergy added these issues into the corrective action program (CAP) as CR-tP2-2011-06047.Entergy subsequently identified that the l&C procedures for both the Unit 2 and Unit 3OTdT RPS instruments also allowed the time constants to be set outside of the allowablevalues specified in the COLR. The most recent as-left calibration results for the Unit 2OTdT time constants indicated that three of the four instrument channels were out ofspecification; the Unit 3 instrument channels were within allowable values. Entergyperformed an immediate operability evaluation and determined that the Unit 2 OTdTinstrument was capable of performing its intended functions with the as-left values of thetime constants. Entergy entered this issue into their corrective action program ascR-rP2-201 1-06070.Analvsis: The team determined that the failure to apply design control measurescommensurate with those applied to the original design was a performance deficiencythat was reasonably within Entergy's ability to foresee and prevent. Specifically, Entergyimplemented a setpoint change, but allowed the existing in-field actual setpoints toremain unchanged until the next regularly scheduled surveillance period withoutevaluating the adequacy of the in-field actual setpoints, which were later found outsidethe value required by the design and licensing bases.The finding is more than minor because it is associated with the Design Control attributeof the Barrier Integrity Cornerstone and adversely affected the cornerstone objective toprovide reasonable assurance that physical design barriers (e.9., fuel cladding) protectthe public from radionuclide releases caused by accidents or events. ln addition, thisissue was similar to example 3.k of NRC IMC 0612, Appendix E, "Examples of Minorlssues," which determined that calculation errors would be more than minor if, as a resultof the errors, there was reasonable doubt on the operability of the component, or ifsignificant programmatic deficiencies were identified that could lead to worse errors ifuncorrected. For this issue, there was a reasonable doubt on the operability of the OPdTinstrument, in that a knowledgeable engineer could not determine the acceptability of ashorter time constant without a detailed review of transient and accident analyses andanalysis modeling assumptions.The team performed a Phase 1 Significance Determination Process screening, inaccordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening andCharacterization of Findings," and determined the finding was of very low safetysignificance (Green) because it only affected the fuel barrier portion of the barrier integritycornerstone.Enclosure 5This finding had a cross-cutting aspect in the area of Human Performance, WorkPractices, because Entergy did not ensure adequate supervisory or managementoversight of a design change. Specifically, Entergy's design organization that performedthis setpoint change activity considered the time constant value in the COLR to be anominal value without appropriate tolerance. The design organization did not recognizethat the COLR value was a design basis number required to be implemented by ptantTechnical Specifications, Entergy's oversight of this activity also did not identify the needfor interfacing reviews by other organizations, such as reactor engineering or nuclearanalysis. As a result, Entergy's oversight failed to ensure that potential non-complianceswith design and licensing requirements were properly evaluated. IMC 0310, AspectH.4(c)lEnforcement: 10 CFR 50, Appendix B, Criterion lll, "Design Control," requires, in part,that design changes, including field changes, are subject to design control measurescommensurate with those applied to the original design. Contrary to the above, fromDecember 2004 until present, Entergy did not apply the same level of design controlmeasures to the in-field actual setpoint values of the OPdT instrument that had beenapplied to the originaldesign values. Specifically, Entergy implemented an OPdTinstrument setpoint change but allowed the existing in-field actual setpoints to remainunchanged untilthe next regularly scheduled surveillance period and did not evaluate theadequacy of the in-field actual setpoints, which were later found outside the valuerequired by the design basis. Technical Specification Table 3.3.1-1 Function 6 (i.e.,OPdT) specified that the allowable value shall not exceed its computed trip setpoint bymore than 2.4o/o of span, where the time constant value was greater than or equal to thevalue specified in the COLR. The COLR specified that the OPdT time constant begreater than or equal to 10 seconds. EC5000034071 revised the OPdT time constantfrom a band of 9.7 to 10.3 seconds to a band of 10.0 to 10.6 seconds in the applicablel&C and TS surveillance procedures. However, the EC specifically approved a delayedre-calibration of the in-field setpoint values, and did not evaluate the impact of a timeconstant value lower than allowed by the COLR. Specifically, the last performedcalibration had left the time constant set at 9.9 seconds for OPdT channel 2 and 9.8seconds for channel 4. Therefore, Entergy failed to verify the adequacy of design.Because this violation was of very low safety significance (Green) and was entered intoEntergy's corrective action program (CR-lP2-2011-06047), this violation is being treatedas a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV0500024712011007-01, Failure to Correctly lmplement an Approved Setpoint Changeto Reactor Protection System Instruments).2.2 Unit 2 Recirculation Pumps Flow lncrease to Meet ln-Service Testinq CodeRequirementsa. Inspection ScopeThe team reviewed a modification (EC-34089) that replaced the two-inch test line for theinternal safety injection (Sl) recirculation pumps with a six-inch test line. The test line wasreplaced to increase the test flow rate to satisfy new American Society of MechanicalEngineers (ASME) requirements for pump testing. The new requirements include aEnclosure 6comprehensive pump test to be performed at or above 80% of the internal recirculationpump design flow rate of 3000 gallons per minute. The modification included replacing amanual gate valve in the test line along with adding a flow orifice, a ball valve and adischarge sparger with a ring header to reduce the flow velocity to prevent hydraulicdisturbance in the pump suction sump during testing.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the internal Sl recirculation pumps had not been degraded bythe modification. The team interviewed engineering staff and reviewed technicalevaluations associated with the modification to determine if the test line sizing wasappropriate to satisfy the required flow rate and whether the piping stress analysesevaluated both test and accident system operating conditions to ensure the piping stresswould remain within allowable limits. This included a review of an engineering evaluationof the expected heatup rate within the system during full flow testing to ensuresurveillance test temperature conditions would remain consistent with boundingengineering pipe stress analyses. The team reviewed affected drawings, procedures,and calculations to ensure that they were properly identified and revised. The associatedpost-modification test (PMT) results were reviewed to ensure appropriate acceptancecriteria had been identified and satisfied. The team also reviewed condition reports todetermine if there were reliability or performance issues that may have resulted from themodification. Additionally, the 10 CFR 50.59 screening determination associated with thismodification was reviewed as described in section 1R17.1 of this report. The documentsreviewed are listed in the Attachment.b. FindinqsNo findings were identified.,2.3 Unit 2 Service Water Pump Zurn Strainer Backwash Circuit Modificationa. Inspection ScopeThe team reviewed a modification (EC-10675) to the Unit 2 service water (SW) pumpZurn strainer circuitry to provide timed operation of the Zurn strainer backwash armmotor. The service water pumps have basket type motor operated rotary strainers whichinclude a washing system to eliminate fine debris that passes through the intakestructure. Prior to this modification, the Unit 2Zurn strainer wiper arm motors wereoperated continuously whenever their associated SW pump was operating. This createdadditionalwear on the internal components which required replacement on a six-monthinterval. The new timers were installed to provide for optimum intermittent operation ofthe wiper arms and were set to operate for five minutes every two hours. Additionally, themodification removed the strainer differential pressure (DP) signal for the automatic wiperarm motor start logic but maintained the high strainer DP alarm for each pump.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the service water pumps had not been degraded by themodification. The team interviewed engineering staff and reviewed technical evaluationsEnclosure b..2.4a.7to determine whether the service water pump strainers would function in accordance withthe design assumptions, including limiting the strainer DP consistent with assumptions inthe service water engineering hydraulic analyses. The team walked down the Zurnstrainer circuitry to ensure the engineering change was installed in accordance withdesign drawings and instructions. The associated PMT results were reviewed to ensureappropriate acceptance criteria had been met. The team also reviewed affectedprocedure revisions to ensure consistency with the design change. The team discussedthe change with engineering and operations personnel to determine if there werereliability or performance issues that may have resulted from the modification.Additionally, the 10 CFR 50.59 screening determination associated with this modificationwas reviewed as described in Section 1R17.1 of this report. The documents reviewed inassociation with this modification are listed in the Attachment.FindinqsNo findings were identified.Evaluation of Procedure Chanqes to Address Pressure Lockino Conditions for ResidualHeat Removal Valve MOV-744Inspection ScopeThe team reviewed procedure revisions associated with EC-24005. The revision involvedthe normal post accident positioning of the residual heat removal (RHR) system motoroperated common discharge isolation valve, MOV-744, on both Unit 2 and Unit 3. Thechange maintained MOV-744 in a de-energized normally open position during therecirculation phase of an accident and provided for closing the valve if required byoperating procedures. The valve is normally de-energized open per TechnicalSpecification requirements during plant operation and had previously remained openduring the injection phase of a loss-of-coolant-accident (LOCA) but was manually re-energized and closed after shutdown of the RHR pumps during the establishment of therecirculation phase of operation. The revision to the emergency operating proceduresreduced the number of potential active position changes of the valve and precluded thepotentialfor pressure locking issues associated with the valve.The team reviewed the procedure revisions to verify that the design basis, licensing basisand performance capability of equipment during the recirculation phase of operation hadnot been degraded by the operational change. The team interviewed Entergy personnel,and reviewed calculations and technical evaluations to verify that the internal recirculationpumps and RHR system recirculation capability would still be able to perform theirfunction in accordance with design assumptions. The team reviewed various operatingprocedures to ensure they appropriately reflected the revised strategy. This included areview of the containment leakage rate testing program document and in-service testing(lST) program documents to ensure they were revised to reflect the new position ofMOV-744. Additionally, the Unit 2 post-LOCA dose calculations were reviewed to ensurethe change had not affected the conclusions within the analyses. The procedurechanges were performed on both Unit 2 and Unit 3. The team walked down the locationEnclosure 8of the valve and the valve motor control center in Unit 3, which was representative of Unit2, in order to gain a relative understanding of the path required by an operator to gainaccess to the components. This included discussions with plant operators on theirunderstanding of the purpose of the change and their familiarity with the revisedprocedures. Additionally, the 10 CFR 50.59 screening determination associated with thismodification was reviewed as described in Section 1R17

.1 of this report. The documentsreviewed are listed in the Attachment.b. FindinosNo findings were identified..2.5 lnstallation of Hiqh Point Vent in the Unit 2 Residual Heat Removal Svstema. Inspection ScopeThe team reviewed a modification (EC-16920) to the Unit 2 RHR system that installed anew high point vent on the 14-inch suction line from the reactor coolant system 22hotleg, downstream of primary containment isolation valve AC-732. During monthlysurveillance checks on Unit 3, the presence of a gas void in the same location hadoccasionally been detected. The potential existed for a similar gas void in Unit 2 becausethe Unit 2 piping arrangement and source for potential gas in-leakage was similar to thatin Unit 3. Therefore, this modification added a vent connection downstream of AC-732,similar to Unit 3, to mitigate a potential gas void and ensure the RHR suction piping wouldremain full of water. Installation of the vent connection was performed withoutdepressurizing or draining the RHR system by utilizing a hot tap process.The team evaluated the modification to determine whether the design basis, licensingbasis, or performance capability of the RHR system had been degraded by themodification. The team assessed Entergy's technical evaluations and design details,including installation specifications and foreign materialexclusion (FME) control, andinterviewed engineering personnel to determine whether the RHR system would functionin accordance with the design assumptions and whether the specified FME controls wereadequate to prevent foreign material, such as drill shavings, from entering the reactorcoolant system. Drawings and procedures were reviewed to verify they were properlyupdated. The team also reviewed the completed work order and interviewedmaintenance personnel to assess whether installation activities were performed asspecified by the design. Post-modification test results were reviewed to verify theacceptance criteria had been met. ln addition, the team walked down the new RHR ventvalve to independently evaluate material condition and to ensure it was installed inaccordance with design instructions. A review of condition reports was performed todetermine whether there were any reliability or performance issues associated withinstallation of the new vent valve. Additionally, the 10 CFR 50.59 screeningdetermination associated with this modification was reviewed as described in section1R17.1 of this report. The documents reviewed are listed in the Attachment to this report.Enclosure

b..2.69FindinqsNo findings were identified.Unit 2 Residual Heat Removal Pump Motor Flood ProtectionInspection ScopeThe team reviewed a modification (EC5000034211) that installed a float operated drainvalve and drain line in the primary auxiliary building (PAB). The drain line penetrated thePAB exterior wall and was routed below grade to a nearby storm drain manhole in thetransformer yard. The drain line was designed to protect the RHR pump motors fromdamage due to a postulated internalflooding event in the PAB. Entergy performed anevaluation of current offsite dose calculation requirements and determined the extra floodprotection would not create a new effluents pathway nor significantly increase the doseconsequences of existing pathways due to a postulated internalflooding event.The team evaluated the modification to determine whether the design basis, licensingbasis, or performance capability of systems, structures, or components (SSCs) located inthe PAB, including the RHR system, had been degraded by the modification. The teamassessed Entergy's calculations, radiological dose assessment analysis, and engineeringevaluations for the sizing and placement of the float valve and associated drain piping toverify the adequacy of the design. Drawings, procedures, and preventive maintenancetasks were reviewed to verify they had been properly updated. The team also reviewedthe completed work order and interviewed Entergy personnel to assess whetherinstallation activities were performed as specified by the design. PMT results wereevaluated to determine whether the float valve and drain line would function inaccordance with the design assumptions. In addition, the team walked down the floatvalve and drain line penetration into the yard manhole to independently evaluate materialcondition and to verify it was installed in accordance with design instructions. A review ofcondition reports was performed to determine whether there were any reliability orperformance issues associated with installation of the new drain line and float valve.Additionally, the 10 CFR 50.59 screening determination associated with this modificationwas reviewed as described in section 1R17.1 of this report. The documents reviewed arelisted in the Attachment to this report.b. FindinosNo findings were identified..2.7 Modification of Pipinq Connection and Support Associated with Unit 2. 23 Charoinq PumpSuction Stabilizer Vent Linea. lnspection ScopeThe team reviewed a modification (EQ-2259) in Unit 2 that modified the existing 3/4 inchvent connection on the 23 charging pump suction stabilizer. Entergy performed thismodification to address repeated leakage at the threaded coupling. The suction stabilizerEnclosure 10and corresponding pulsation dampener were designed to prevent vibration induced pipefailure and charging pump cavitation. The modification removed the existing screwedcoupling welded to the stabilizer and replaced it with a fully welded joint. An additionalsupport was installed on the vent piping to reduce vibration.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the charging system had not been degraded by themodification. The team interviewed engineering staff and reviewed technical evaluationsassociated with the modification to determine if the charging pump would function inaccordance with the design assumptions. The team reviewed drawings and proceduresto ensure that they were properly updated. In addition, the inspectors performed fieldinspections and system walk downs to evaluate the installation and material condition.The associated PMT results were reviewed to ensure appropriate acceptance criteria hadbeen met. The team also reviewed condition reports to determine if there were reliabilityor performance issues that may have resulted from the modification. Additionally, the10 CFR 50.59 screening determination associated with this modification was reviewed asdescribed in Section 1R17.1 of this report. The documents reviewed are listed in theAttachment.b. FindinssNo findings were identified.,2.8 Unit 2 Service Water Bav Water Level lndicatorsa. Inspection ScopeThe team reviewed a modification (EC-5828) that upgraded the service water levelindicators from a manual method of measuring SW level to an electronic system. Themodification used the existing leveltransmitters, LE-7607-2 and LE-7608-2, and installednew digital level indicators. The modification was implemented to alleviate operatorburden and to eliminate personnel safety concerns associated with taking manualreadings within the SW bay area. ln addition, the modification provided local SW baywater level indication to the control panels for traveling water screens 27 and 28, analarm on the annunciator panel EPR 10 located in the control building, and an alarm inthe main control room. The modification also corrected a non-conservative six-inch waterlevel error due to improper installation of the existing SW bay level indicators.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the safety-related SW system had not been degraded by themodification. The team interviewed engineering staff and reviewed technical evaluationsto determine if the new SW level electronic indicators would function in accordance withthe design assumptions. The associated work order instructions and documentationwere reviewed to verify that maintenance personnel implemented the modification asdesigned. The team walked down the accessibte portions of the Unit 2 SW system andnew level indicators to assess their material condition and to ensure the level indicatorswere installed in accordance with design instructions. The team reviewed the PMTEnclosure

.2.91 1results to ensure the appropriate acceptance criteria had been met and that the testsdemonstrated the adequacy of the new design. A review of the condition reportsassociated with the SW system was also performed to determine if there were reliabilityor performance issues that may have resulted from the modification. Additionally, the10 CFR 50.59 screening determination associated with this modification was reviewed asdescribed in Section 1R17.1of this report. The documents reviewed are listed in theAttachment.FindinqsNo findings were identified.Revise Setpoint for Unit 2 Emeroencv Diesel Generator Jacket Water TemperatureControllersInspection ScopeThe team reviewed a modification (EC-2603) that changed the setpoint for the jacketwater temperature controllers, TC-5001, -5002, and -5003, for each of the emergencydiesel generators (EDG) in Unit 2. The setpoint for each controller was changed 10degrees Fahrenheit ("F) from 125"F +/- 3"F to 135'F +/- 3"F. Entergy performed thismodification to prevent jacket water temperature readings below the administrative lowtemperature limit of 120"F. Specifically, the 23 EDG jacket water temperature indicator(Tl-5046) was found to read approximately 112'F during the winter seasons due to lowerambient temperatures. Similar concerns were also identified on the 21 and 22 EDGs.Entergy determined there were no operability concerns with the EDGs because thetemperatures never dropped below the recommended vendor minimum limit of 90'F. Byincreasing the setpoint by 10 degrees, the jacket water heater temperature control switchwould maintain the heaters energized longer, resulting in higher jacket watertemperatures.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the EDGs had not been degraded by the jacket water controllersetpoint change. The team interviewed engineers, and reviewed applicable technicalevaluations and design drawings to verify that the jacket water system would function inaccordance with design assumptions. The team reviewed the associated PMT results toensure the appropriate acceptance criteria had been met. ln addition, the team walkeddown the EDGs and jacket water system components to assess their material condition.The team also confirmed that surveillance tests, operational procedures, and drawingshad been appropriately updated to reflect the change. Additionally, the 10 CFR 50.59screening determination associated with this modification was reviewed as described inSection 1R17.1of this report. The documents reviewed are listed in the Attachment.FindinqsNo findings were identified.b.Enclosure

12.2.10 Unit 3 Refuelino Water Storaoe Tank Low Low Level Alarm Switch Modificationa. lnspection ScopeThe team reviewed a modification (EC5000041964) on Unit 3 to replace an existingrefueling water storage tank (RWST) low low level alarm switch (LlC-921) with a smallerrange level alarm switch (LC-923), The smaller range dedicated LC-923 alarm switchprovides better resolution and more accuracy compared to the original alarm switch. Thealarm function of LIC-921 was removed but the local indicating dial of LIC-921 wasretained at the instrument panel at the RWST. LC-923 was supplied by a different vendorand utilized a different sensor technology than the original LIC-921. The LC-923 alarmswitch provides an input to one of two annunciators in the control room that cue operatorsto align the safety injection system to recirculation mode prior to the RWST reaching alevel too low to support safety injection pump operation.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the RWST level indication and alarms had not been degradedby the modification. Specifically, the team verified that seismic and environmentalqualification, instrument accuracy and setpoint drift, instrument redundancy and diversity,and operating characteristics and requirements were equivalent or improved. The teaminterviewed design engineers and reviewed drawings, calculations, evaluations, vendordata, PMT results, and associated maintenance work orders to verify that the LC-923installation and LIC-921 modification was appropriately implemented. Finally, the teamwalked down the RWST level and alarm instruments with the design engineer to verifythey had been installed in accordance with design instructions. The 10 CFR 50.59screening determination associated with this modification was also reviewed as describedin section 1R17.1 of this report. The documents reviewed are listed in the Attachment.b. FindinqsNo findings were identified..2.11 32 Emerqencv Diesel Generator Control Relav Modificationa. lnspection ScopeThe team reviewed a Unit 3 modification (98-3-040-EDG) that replaced several 125 voltdirect current (VDC) control relays on the 32 emergency diesel generator. Thereplacement control relays included the engine start relays, run relay, cranking relays,and the shutdown relay. The 32 EDG control relay replacements were intended toimprove reliability of the EDG and were replacements for an obsolete relay model.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the 32 EDG had not been degraded by the modification.Specifically, the team reviewed attributes such as minimum and maximum operatingvoltages, amperage requirements, relay response timing, and seismic qualification toverify the new relays were equivalent or improved when compared to the previous relays.The team interviewed design engineers, and reviewed evaluations, calculations, vendorEnclosure 13information, wiring and schematic diagrams, PMT results, and associated maintenancework orders to determine whether the 32 EDG control relay replacements wereappropriately implemented. Finally, the team walked down the 32 EDG control cabinetwith the design engineer to evaluate material condition. The 10 CFR 50,59 screeningdetermination associated with this modification was also reviewed as described in section1R17.1 of this report. The documents reviewed are listed in the Attachment.b. FindinssNo findings were identified..2.12 Unit 3 Pressurizer Backup Heater Group 32 Bank 8.9.31 Retire-ln-Place Modificationa. lnspection ScopeThe team reviewed a Unit 3 modification (EC-14246) to retire-in-place pressurizer backupheater group 32 bank 8.9.31. Backup heater bank 8.9.31 was determined to begrounded during a troubleshooting maintenance activity using work order 51485917.Pressurizer heaters maintain a constant pressure for the reactor coolant system and aminimum required available capacity is required by Technical Specification 3.4.9.b.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the Unit 3 pressurizer heaters was maintained within TechnicalSpecification requirements. The team verified that operators administratively tracked theavailable capacity of pressurizer heaters and that the simulator was appropriatelymodeled for the loss of pressurizer backup heater group 32 bank 8.9.31, The teaminterviewed design engineers, and reviewed evaluations, wiring and schematic diagrams,and the associated maintenance work order to ensure all aspects of the modification andits potential impact on plant and electrical system operation were appropriatelyconsidered and implemented. Additionally, the 10 CFR 50.59 screening determinationassociated with this modification was reviewed as described in section 1R17.1 of thisreport. The documents reviewed are listed in the Attachment.b. FindinqsNo findings were identified..2.13 Replacement of Unit 3 Control Room Air Conditioner Service Water Temperature ControlValvesInspection ScopeThe team reviewed a modification (EC-7854) that replaced the 1-114 inch temperaturecontrol valves, SWN-TCV-1310, -1 311, -1312, and -1313, installed in the service wateroutlet lines from each control room air conditioning system (CRACS) condenser withsmaller 3/4 inch control valves. Entergy replaced these valves to address excessive seatwear associated with the larger valves which was experienced during periods of low flowEnclosure 14and high pressure such as during winter months. The seat wear resulted in leakage thatallowed cold service water to flow through and cool the condenser and the refrigerant.The cool, low-pressure refrigerant was attributed to low suction pressure trips of thecompressor upon system startup. Entergy determined that the use of smaller valveswould minimize seat wear because they would operate at increased seat openings.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the control room air conditioning system had not beendegraded by the modification. The team interviewed engineering staff, and reviewedtechnical evaluations associated with the modification to determine if the newtemperature control valves would function in accordance with the design assumptions.The team reviewed drawings, procedures, and calculations to ensure that they wereproperly updated. The associated PMT results were reviewed to ensure appropriateacceptance criteria had been met. The team also reviewed condition reports todetermine if there were reliability or performance issues that may have resulted from themodification. Additionally, the team walked down the temperature controlvalves toassess their material condition and to verify they were installed in accordance with designinstructions. The 1O CFR 50.59 screening determination associated with this modificationwas also reviewed as described in section 1R17.1 of this report. The documentsreviewed are listed in the Attachment.b. FindinosNo findings were identified..2.14 lnstallation of Vortex Suppressors in the Unit 3 Vapor Containmenta. Inspection ScopeThe team reviewed a modification (EC-14974) that installed vortex suppressors within theUnit 3 vapor containment (VC) above the internal recirculation sump strainer and abovethe VC sump strainer. Each vortex suppressor consists of a stainless steel framestructure that supports sections of grating that provide the vortex suppression function.Entergy personnel implemented this change to address the generic industry concernassociated with the potential for vortex formation at the strainer inlet during certain loss-of-coolant accident scenarios. Specifically, engineering personnel determined that thevortex suppressors were required to mitigate potential reliability and operational concernsassociated with air ingestion during post-LOCA recirculation operation.The inspectors reviewed the modification to verify that the design basis, licensing basis,and performance capability of the internal recirculation and VC sumps had not beendegraded by the modification. The inspectors reviewed several related calculationsassociated with sump strainer performance and post-LOCA debris loading to ensure thatEntergy used conservative assumptions and appropriate inputs to adequately evaluatethe modification. The inspectors reviewed Entergy's completed installation work ordersincluding the associated drawings, weld specification sheets, weld maps, and completedweld data sheets. The inspectors also reviewed condition reports to determine if thereEnclosure 15were reliability or performance issues that may have resulted from the modification. The10 CFR 50.59 screening determination associated with this modification was alsoreviewed as described in section 1R17.1 of this report. The documents reviewed arelisted in the Attachment.b. FindinqsNo findings were identified..2,15 Unit 3 Residual Heat Removal Pump Coolino Evaluationa. lnspection ScopeThe team reviewed an evaluation (EC-25886) that analyzed a statement in the UFSARwhich asserted cooling was not needed to the Unit 3 residual heat removal pumps for 24hours in an accident condition. During research performed for a calculation of coolingflow to the Unit 2 RHR pumps, Entergy identified that this statement in the Unit 3 UFSARmay not be valid. Entergy performed this evaluation based on results of seal testingconducted by the RHR pump seal manufacturer which showed that some cooling wouldbe required prior to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to ensure adequate seal performance in an accidentscenario. Specifically, the results concluded the RHR pump seals require a cooling waterrecirculation flush provided by the component cooling water (CCW) system be maintainedat 150oF or below to ensure no seal degradation occurs. There is a potential that duringsome scenarios which involve a loss of CCW, the RHR pump sealtemperature mayexceed 150oF less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the event. The evaluation analyzed RHR pumpfunction during a large break LOCA, a small break LOCA, a main steam line break, asteam generator tube rupture, an Appendix R event, and normal plant operating modes.Entergy concluded that seal performance during these conditions would be eitherunaffected or impacted negligibly, and therefore, the RHR pumps would maintaincapability to perform their intended design functions.The team reviewed the evaluation and associated calculations to verify that assumptionsand parameters used were valid and considered bounding scenarios. The parametersincluded RHR pump suction temperature, availability of cooling water, and the durationthat cooling was unavailable to the pumps. Additionally, the team verified that affectedprocedures were updated to include caution statements associated with operating RHRpumps without CCW available. The 10 CFR 50.59 screening determination associatedwith this modification was also reviewed as described in section 1R17.1 of this report.The documents reviewed are listed in the Attachment.b. FindinqsNo findings were identified.Enclosure 16.2.16 31 EDG Jacket Water Pressure Switch Setpoint Chanqea. lnspection ScopeThe team reviewed a modification (EC-7202) that changed the emergency dieselgenerator jacket water (JW) pressure switch setpoint associated with starting andstopping the EDG pre-lubrication (pre-lube) oil pump. Specifically, the design objective ofthe change was to ensure the pre-lube oil pump starts, as required, after the EDG isstopped. The modification was implemented because Entergy determined that the JWpressure switch trip setpoint had not accounted for the static head of the JW system. Themodification installed a like-in-kind switch with a 12 +l- 0.5 psig decreasing setpoint, aconservative change from the original setpoint of 8 +l- 0.5 psig. The switch also performsa secondary function to stop the pre-lube oil pump on increasing pressure of the JWsystem after the EDG is started.The team reviewed the modification to verify that the design basis, licensing basis, andperformance capability of the EDG had not been degraded by the modification. The teamassessed whether the modification was consistent with requirements and assumptions inthe design and licensing bases. The team reviewed calculations and technicalevaluations to assess whether the modification was consistent with design assumptions.Post-modification testing data was reviewed to verify the operating jacket water pressurerange of the EDGs. The team performed walk downs of the 31,32 and 33 EDGs, andobserved the 32 EDG while running, to assess operation of the equipment while inservice and the material condition. The team conducted interviews with engineering staffto determine if the EDGs would function in accordance with the design assumptions.Additionally, the 10 CFR 50.59 screening determination associated with this modificationwas also reviewed as described in section 1R17.1 of this report. The documentsreviewed are listed in the Attachment.b. FindinosNo findings were identified..2.17 Hiqh Point Vent Valve lnstallation on Unit 3 Containment Sprav Svstem Pipinqa. Inspection ScopeThe team reviewed a modification (EC-17096) that installed a system high point ventvalve (Sl-208) on the Unit 3 containment spray system (CSS) piping. The new valveprovides the capability to vent and eliminate potential gas accumulation within the 12-inchcommon suction header to the CSS pumps. In response to NRC Generic Letter 2008-01,"Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, andContainment Spray Systems," Entergy identified the location as having the potentialforgas accumulation and subsequent gas binding or damage to the pumps, with noprovision to eliminate the void.Enclosure 17The team reviewed the modification to verify that the design basis, licensing basis, andperformance capability of the CSS had not been degraded by the modification. The teamassessed if the modification was consistent with requirements in the design and licensingbases. The team reviewed the stress analysis calculation and technical evaluations toassess whether the modification was consistent with design assumptions. Componentsand materials were reviewed to ensure that the modification conformed to the designspecifications and to verify that the system was seismically qualified. Designassumptions were reviewed to evaluate whether they were technically appropriate andconsistent with the UFSAR. The team also verified that selected drawings, calculationsand procedures were properly updated based on the new configuration. The teamreviewed the installation details and work order process to ensure control of FME duringinstallation. The team reviewed the PMT results and data sheets to verify the systemwould function in accordance with design requirements. The team performed a walkdown of the system to verify the vent was installed in accordance with design instructions.Additionally, the team conducted interviews with engineering staff to determine whetherthe affected SSCs functioned in accordance with the design assumptions and to verify ifthe modification corrected the previously identified problem. Additionally, the10 CFR 50.59 screening determination associated with this modification was alsoreviewed as described in section 1R17.1 of this report. The documents reviewed arelisted in the Attachment.b. FindinqsNo findings were identified..2.18 Installation of lnternal Pipe Mechanical Seals at Pipe Weld Connections withinUnderqround Service Water Linea. Inspection ScopeThe team reviewed a modification (EC-24032) on Unit 3 that installed internal pipemechanical seals to prevent further corrosion at the weld seams in the underground 24-inch service water system line from the SW pump discharge to the primary auxiliarybuilding. The 24-inch SW pipe line is a butt welded, cement-lined carbon steel pipe withgaps at the circumferentialweld locations. The modification was designed to act aswaterproof barriers to protect the internal welded seam surface from further corrosion anderosion due to exposure of the welds to brackish river water. The seals are a vendorsupplied and installed product manufactured of ethylene propylene rubber with corrosionresistant stainless steel retaining bands.The team reviewed the modification to verify that the design basis, licensing basis andperformance capability of the SW System had not been degraded by the modification.Specifically, the team verified that the installation of the seals would have negligible effecton the margin for flow requirements and the seismic qualification of the piping. The teaminterviewed design and system engineers, and reviewed evaluations, vendor informationand procedures, post-modification testing results, and associated maintenance workorders to verify that the modification was appropriately implemented. The 10 CFR 50.59Enclosure 18screening determination associated with this modification was also reviewed as describedin section 1R17.1 of this report. The documents reviewed are listed in the Attachment.b. FindinqsNo findings were identified.4.

4OA2 ldentification and Resolution of Problems (lP 71152)a. Inspection ScopeThe team reviewed a sample of condition reports associated with 10 CFR 50.59 and plantmodification issues to determine whether Entergy was appropriately identifying,characterizing, and correcting problems associated with these areas, and whether theplanned or completed corrective actions were appropriate. ln addition, the team reviewedcondition reports written on issues identified during the inspection to verify adequateproblem identification and incorporation of the problem into the corrective action system.The condition reports reviewed are listed in the Attachment.b. FindinqsNo findings were identified.4OAO Meetinqs. includinq ExitOn December 1, 2011, the team presented the preliminary inspection results toMr. L. Coyle, and other members of Entergy's staff. The final inspection results werediscussed with Mr. P. Conroy in a telephone call on January 12,2012. The teamreturned the proprietary information reviewed during the inspection and verified that thisreport does not contain proprietary information.Enclosure

A-1ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Enterqv Personnel

E. Bauer, Design Engineer

J. Bencivenga, Design Engineer

F. Bloise, Design Engineer

C. Bristol, Design Engineer

J. Bubniak, Design Engineer

T. Chan, System Engineering Supervisor

P. Conroy, Director of Nuclear Safety Assurance

L. Coyle, General Manager, Plant Operations

G. Dahl, Specialist, Licensing

K. Elliott, Fire Protection Engineer

T. Galati, Design Engineer

J. Hill, l&C Design Engineering Supervisor

A. Kaczmarek, Design Engineer

J. Kaczor, Design Engineer

A. King, Design Engineer

L. Liberatori, Design Engineer

T. McCaffrey, Manager, Design Engineering

R. Motko, Reactor Engineer

J. Raffaele, Supervisor, Design Engineering

R. Sergi, Design Engineer

J. Whitney, System Engineer

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSEDOpened and

Closed

0500024712011007-01 NCV Failure to Correctly lmplement an ApprovedSetpoint Change to Reactor ProtectionSystem lnstruments (Section 1R17.02.1)

LIST OF DOCUMENTS REVIEWED

10

CFR 50.59 Evaluations09-2001-00-Eval, Temporary Operating Procedure 2-TOP-014, Contingency Actions forDegraded Recirculation Line to CST, Rev. 010-300'1-00 EVAL, Procedure Changes to Address Pressure Locking Conditions for RHR ValveMOV-744 (Engineering Change Evaluation

EC-24005), Rev. 010-2001-00 EVAL, Procedure Changes to Address Pressure Locking Conditions for RHR ValveMOV-744 (Engineering Change Evaluation

EC-24005), Rev. 011-3001-00 EVAL, Allow Testing of the Manipulator Crane with a Dummy Fuel Assembly in theReactor, Rev.0Attachment

CFR 50.59 Screened-out Evaluations3-AOP-RHR-1, Loss of RHR, Rev. 93-E-0, Reactor Trip or Safety lnjection, Rev. 23-E-3, Steam Generator Tube Rupture, Rev. 23-ECA-1.1, Loss of Emergency Coolant Recirculation, Rev. 2EC-09063, Accept Flowserve Report

EC 1180 and Drawing with Minimum Submergence Levelfor Sl Recirculation Pumps, Rev. 0EC-09743, Delete Containment Sump Level Transmitters

LT-3304 &

LT-941 from the List ofCredited RCS Leakage Detection lnstruments, Rev.0EC-12166, Refurbishment of River Water Pumps, Rev. 0EC-14686, lP2 RHR System Valve 745 A&B Redundant Valve Position lndication, Rev. 0EC-15086, Equivalent Change Evaluation for Replacement of

GT-2 Battery, Rev. 0EC-15137, Evaluate and Accept Repairs on Valve

FP-900 Gland Follower, Rev.OEC-15308, SQUG Evaluation for CRACS Seismic Capability, Rev. 0EC-15883, Install New High Point Vent Valve in Sl System, Rev. 0EC-16001, Equivalent Change Evaluation for Replacement of Electronic Circuit Boards in theLeading Edge Flow Measurement System, Rev. 0EC-16284, Evaluation of Freeze Seal for Repair of Valve 816, Rev. 0EC-16701, Flood Gates on Doors

DR-224 andDR-226, Rev. 0EC-17784, Repair of Unit 2 Refueling Cavity Liner Plates, Rev. 0EC-18904, Vortex and Critical Submergence Evaluations for RWST and CST, Rev. 0EC-19083, Evaluation of Tornado Passage Effect on the EDG HVAC System, Rev. 0EC-19489, Flowserve Report to Evaluate Minimum Flows and Associated Expected Service Lifefor Auxiliary Component Cooling Pumps, Rev. 0EC-19779, Revision of lP3-CALC-RPC-00298 - lnst. Loop Accuracy and Setpoint Calculation forlP3 RCS Loop Low Flow for Inclusion of

DCP 01-3-058 RCS,

DC 97-3-039, and ChangesPreviously Made to Associated Surveillance Procedures, Rev' 0EC-19816, Service Water System Refurbishment Project, Rev. 0EC-19959, Modify the Required Action Statement for TRO 3.8.B Condition A to lnclude an ORStatement to Establish an lndependent Power Supply if the Appendix R Diesel GeneratorCannot be Restored to OPERABLE Status Within 30 Days, Rev. 0EC-20030, Engineering Evaluation of Ultrasonic Thickness Measurements on Various PipingSystems for Flow Accelerated Corrosion Program, Rev. 0EC-21406, Evaluation of Stainless Steel Bolting Material for 2" Flanges in SW System, Rev. 0EC-22784, Equivalent Change Evaluation for Replacement of a Resistance to Current Converter(R/lAction Pak) Module, Rev. 0EC-22830, Evaluate the IPEC Unit 2 & 3 RHR Systems per Westinghouse

NSAL-09-8 RegardingPotentialVoiding Under Postulated Modes 3 & 4 LOCA Conditions, Rev. 9EC-23379, Clarification of lP3 UFSAR Regarding Service Water System ComponentRealignment during Post-LOCA Recirculation, Rev. 0EC-24491, Evaluate Use of Enecon MetalOlad CeramAlloy and Coating Compounds for Use onStainless Steel Piping and Fittings in the Service Water System, Rev. 0EC-24608, 3R16 Replacement of Valve

SWT-235-2, Rev. 0EC-25145, Blocking Open of ClVs During Electrical Testing of #31 DC Bus During Plant Modes 5and/or 6, Rev. 1EC-25423, Main Steam lsolation Valve Limit Switch Equivalency Change, Rev. 0EC-25920, Alternate Pole Arrangement on 23 EDG

JWPS-6-2, Rev. 0Attachment

A-3EC-28201, Revise Procedure

ONOP-CVCS-3, Emergency Boration, to Increase the BoronRequirements for Shutdown Margin in the Event of a Cooldown, Rev, 0EC-28424,33 EDG Cables Equivalency Change, Rev. 0EC-28546, Provide Temporary Source for Cooling Seal Oil Unit in lieu of Service Water, Rev. 0EC-30396, lRPl System Fuse Replacement with Time Delay Fuses, Rev. 0EC-31238, SW Strainer Blowdown Setting Change, Rev. 0EC-32102, Replacing Two Service Water Strainer Supports, Rev. 0Modification Packaqes98-3-040-EDG, Replacement of EDG GE Model CR120A262-41 Relays, Rev. 1EC-10675, Unit 2 Service Water Pump Zurn Strainer Backwash Circuit Modification, Rev. 0EC-14246, Retire-ln-Place Pressurizer Backup Heater Group 32 Heater Bank 8.9.31, Rev, 0EC-14974,lnstall Vortex Suppressors Over the VC and Recirc Sumps at Unit 3, Rev, 0EC-16920, lnstall New High Point Vent Valve in RHR System Downstream of Valve 732, Rev. 0EC-17096, Install a High Point Vent Valve on the Unit 3 Containment Spray System Piping,Rev.0EC-2259, Modification of Piping Connection and Support Associated With Unit 2 Charging Pump23 Suction Stabilizer Vent Line, Rev. 0EC-24005, Evaluation of Procedure Changes to Address Pressure Locking Conditions for RHRValve

MOV-744, Rev. 0EC-24O32,lnstallation of Internal Pipe Mechanical Seals at Pipe Weld Connections withinUnderground Service Water Line, Rev. 0EC-25886, RHR Pump Cooling Evaluation, Rev. 0EC-2603, Revise Setpoint for Unit 2 EDGs Jacket Water Temperature Controllers, Rev. 0EC-34089, Unit 2 Recirculation Pumps Flow lncrease to Meet In-Service Testing CodeRequirements, Rev.0EC500003 407 1, Over-Power Delta-Temperature Tolerance Changes, Rev. 0EC5000034211, Design Permanent Solution to Protect RHR Pump Motors from InternalFlooding, Rev. 0EC5000041964, Replace

LIC-921 RWST Lo Lo LevelAlarm Switch with a New RWST Lo LoLevelAlarm Switch

LC 923, Rev. 0EC-5828, Modification to the Service Water Bay Water Level lndicators, Rev. 0EC-7202, EDG Jacket Water Pressure Switch Associated with the Pre-Lube Pump SetpointChange, Rev.0EC-7854, Replace 1/a"valves

SWN-TCV-1310, 1311,1312,and 1313with Smaller (314")Valves, Rev.0Calculations. Analvsis. and Evaluations97-126-SP, EDG Jacket Water Pressure Switches Setpoint Change, Rev' 0lP3-CALC-STR-03334, Qualification of Internal Mechanical SealAssembly, Rev. 1lP3-CALC-SWS-03312, Evaluation of Hydraulic lmpact of Mechanical (lnternal) Seals Installed in24" SWS Line 408 - Non-Essential Header Operation, Rev. 0lP-CALC-04-01806, Over-Power Delta-Temperature & Over-Temperature Delta-TemperatureLoop Accuracy, Rev. 0lP3-RPT-ED-00922, Appendix R Diesel Generator System Evaluation, Rev. 4IP3-CALC-SI-00725, lnstrument Loop Accuracy lSetpoint Calc i RWST Level (lP3), Rev. 3Attachment

A-4FFX-00706-00, Analysis to Demonstrate the Pressure Boundary Integrity of the Fire ProtectionPiping in the PAB, Rev.0GCC-569-001-0, Analysis of HP Motor Mounting and Panel Support in Zurn Strainer Pit, Rev. 0lP3-CALC-RPC-00298, Indian Point 3 - Instrument Loop Accuracy / Setpoint Calculation / RCSLoop Low Flow, Rev. 1lP3-CALC-268, Emergency Diesel Generator/Jacket Cooling Water Tank Static HeadCalculation, Rev.0lP-CALC-09-00235, Stress Analysis for the Addition of Vent Valve Sl-208 Load on Line 181,Rev. 0lP-CALC-09-00179, Indian Point ECCS Sump Strainer Certification Calculation Based on NPSH,Minimum Flow, Structural Limit and Void Fraction Requirements, Rev. 3IP3-CALC-EL-00184, 125 VDC Component Sizing, Rev. 3lP-CALC-07-00153, Evaluation of Pipe Support

SIH-365 through

SIH-371 Recirculation PumpTest Line, Rev. 0lP-CALC-07-00123, Stress Analysis of Sl Line #293, Rev. 1FIX-00099-00, Emergency Diesel Generator Accuracy of Lube Oil & Jacket Water TemperatureSwitches, Rev.000-086, Hydraulic lmpact of Installing Mechanical Seals in the Essential Service Water Header atIndian Point 3, Rev. 1CN-CRA-03-55, lP2 LOCA Doses for Stretch Power Uprate, Rev. 0lP-RPT-09-00046, Indian Point Units 2 and 3 Design and Evaluation of Vortex SuppressionGrating, Rev. 1CN-TA-03-041, Unit-2 OTDT/OPDT Setpoint Analysis for 4.7o/o Power Up-rate Program, Rev. 2f P-CALC-08-00031, Misc, Structural Evaluation for lP2 & lP3 RHR Pump Motor Flood Protection,Rev.0lP-CALC-08-00024, Sizing Calculation for RHR Pump Flooding Line, Rev. 089-03-084 EDG, 480 Volt Emergency Diesel Generators Control Circuit Timing Relays andPressure Switch Setpoint Determination, Rev. 1Condition ReportscR-lP2-1 999-07141cR-rP2-2000-05387cR-rP2-2001-01 133cR-tP2-2001-00301cR-tP2-2004-04889cR-tP2-2004-06713cR-rP3-2006-03692cR-tP2-2007-02965cR-rP2-2007-02986cR-rP2-2008-00013cR-tP2-2008-03676cR-rP2-2008-03705cR-rP2-2008-04020cR-lP2-2008-04622cR-rP2-2008-04653cR-rP3-2008-00909cR-tP2-2009-05399cR-tP2-2009-00567cR-tP2-2009-00817cR-rP3-2009-04226cR-lP2-2010-02570cR-lP2-2010-04322cR-tP2-2010-06861cR-tP3-2010-00504cR-tP3-2010-00588cR-lP3-2010-02142cR-rP3-2010-00045cR-tP2-2011-02937cR-tP2-201

1-05785.cR-lP2-2011-05787-cR-lP2-2011-05792.cR-tP2-201

1-05852.cR-lP2-201

1-05855"cR-tP2-201

1-05862.cR-lP2-2011-06041.cR-tP2-201

1-06043.cR-1P2-2011-06047.cR-tP2-201

1-06070.cR-tP2-201

1-06087-cR-tP2-201

1-06071-cR-tP3-201

1-00989cR-lP3-2011-01255cR-rP3-201

1-01546cR-lP3-2011-02783cR-lP3-201

1-03776cR-tP3-201

1-04993cR-lP3-201

1-05136.cR-tP3-201

1-05302.cR-tP3-201

1-05309.cR-lP3-2011-05327*cR-tP3-201

1-05353.Attachment

cR-lP3-2011-05502*A-5cR,lP3-201

1-10869cR-lP3-2011-05297(* denotes NRC identified during this inspection)Drawings8206298, List of Cabte Connections to Control Panel, Rev. 0lP3V-91-0068, General Plan 40'-0 DIA X 42' - 3 High Dome Roof Tank - Refueling WaterStorage Tank, Rev. 2lP3V-13-0006, Diagram of Conn. for Diesel Gen #31 ,32 & 33 DC Wiring Panel 32, Rev. 7lP3V-13-0002, Breaker Control Schematic, Rev.

198225132, Elementary Wiring Diagram for Charging Pumps 21 &23, Rev.

128227984, Type I Fire Barriers (3 Hr. Rated) General Notes, Repair Codes for Penetration,Rev.

108228043, Fire Barrier Penetration Schedule, Rev. 78,228015, Fire Barrier Penetrations, Charging Pump Rooms, Rev.

68228050, Fire Barrier Penetration Schedule, Rev. 6B,228014, Fire Barrier Penetrations, Charging Pump Rooms, Rev.

58228016, Fire Barrier Penetrations, Charging Pump Rooms, Rev. 52006MD0152, Nozzle Type Relief Valve 234, Rev. 09321-F-1006, lntake Structure Platform Framing Plan and Details, Rev' 99321-F-1461, Diesel Generator Building Concrete Foundation Plan, Rev.109321-F-2736, Chemical& Volume Control System, Rev. 1299321-F-4046, Diesel Generator Building Floor Drains & Vent. Control Air Piping Plans andSections, Rev. 19FP 9321-01 20193, Primary Water Makeup Pumps, Gould Pump Curves, Rev. 09321-F-20333, Flow Diagram Service Water System, Unit 3, Sh. 1, Rev. 509321-F-20333, Flow Diagram Service Water System, Unit 3, Sh' 2, Rev. 289321-F-20343, Flow Diagram City Water, Unit 3, Sh. 1, Rev. 369321-F-20343, Flow Diagram City Water, Unit 3, Sh. 2, Rev' 219321-F-20983, Turbine Building and Heater Bay Service & Cooling Water Piping, River WaterSystem, Unit 3, Sh. 2, Rev. 129321-F-27223, Flow Diagram Service Water System, Rev. 459321-F-27503, Flow Diagram Safety lnjection System, Sh' 1, Rev' 429321-F-27503, Flow Diagram Safety Injection System, Sh. 2, Rev' 539321-F-27513, Flow Diagram Auxiliary Coolant System, Sh. 1, Rev' 319321-LL-30412,Pr2r Backup Heaters Distribution Panel 32, Sh. 22,Rev' 49321-F-38244, Wiring Diagram 480V Pressurizer Heaters, Fuse Boxes & Distribution Panels,Rev.39321-F-38245, Pressurizer Heater System One-Line Diagram, Rev' 39321-F-55133, Primary Auxiliary Building Restraint & Support Design Line 181 & 314, Rev.

6242514, Engineering Change Markup, Rev.

4400404, lP2-Fire ArealZone Arrangement, Rev.

1502408, Containment Building lR Sump Vortex Suppressor Plan & Sections, Rev.

0502410, Containment Building VC Sump Vortex Suppressor Plan & Sections, Rev.

0502972, Yard Area lnstallation of Mechanical Seals in Service Water Piping Line No. 409 -Piping lsometric - Mechanical, Rev. 0Attachment

A-6503396, Elite Pipeline Retaining Band, ALOXN 1 Piece Bands, Rev.

0503397, Elite Pipeline Retaining Band, AL6XN 1 Piece Bands, Rev.0501603

ECN 10573, PAB lnternal Flood Control, Rev. 0Procedures0-CY-1510, Storm Drain Sampling, Rev. 90-NF-203, Internal Transfer of Fuel Assemblies and lnserts, Rev, 22-AOP-FLOOD-1, Flooding, Rev. 72-ARP-003, High Jacket Water Temperature, Rev. 92-ARP-004, Waste Disposal Panel, Rev. 32-ARP-014, PAB Flooding, Rev. 22-ARP-SJF, Cooling Water and Air, Rev. 392-COL-10.1.1, Safety Injection System, Rev. 342-COL-3.1, Chemical and Volume Control System, Rev. 402-COL-4.2.1, Residual Heat Removal System Check Off List, Rev. 282-ECA-1.3, Loss of Emergency Coolant Recirculation Caused By Sump Blockage, Rev. 22-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 62-ES-1.4, Transfer to Hot Leg Recirculation, Rev. 32-lC-PC-I-T-21 EDG, Emergency Diesel Generator No. 21 Temperature lnstruments Calibration,Rev,82-PC-EM37, Over-Temperature Delta-T and Over-Power Delta-T Setpoint Generators, Rev. 11z-PT-2Y017, Penetration Fire Barrier Seal lnspection, Rev. 12-PT-A048, Rollup Fire Doors, Rev. 02-PT-M108, RHRySI/CS System Venting, Rev. 102-PT'R016, Recirculation Pumps, Rev. 212-PT-V11A-1, Recalibration of NIS and OT/OP T Parameters - Channel 1, Rev. 392-PT-V11A-2, Recalibration of NIS and OTIOP T Parameters - Channel 2, Rev. 392-PT-V11A-3, Recalibration of NIS and OT/OP T Parameters - Channel 3, Rev. 342-PT-V11A-4, Recalibration of NIS and OT/OP T Parameters - Channel 4, Rev. 402-SOP-24.1, Service Water System Operation, Rev. 592-SOP-4.3.1, Residual Heat Removal System Operation, Rev.632-TOP-008, Contingency Actions for PAB Flooding, Rev. 12-TOP-014, Compensatory Actions for Repairs to the Recirculation Line to CST, Rev. 03-AOP-ANNUN-1, Failure of Flight or Supervisory Panel Annunciators, Rev. 43-AOP-SSD-1, Control Room lnaccessibility Safe Shutdown Control, Rev. 133-ARP-005, Panel

SBF-2-SAFEGUARDS, Rev. 353-COL-CS-001, Containment Spray System, Rev. 153-COL-CSV-OO1, Containment Spray Verification, Rev. 73-COL-RCS-001, Reactor Coolant System, Rev. 303-COL-SI-001, Safety lnjection System, Rev. 423-ES-1.3, Transfer to Cold Leg Recirculation, Rev. 73-FR-C.1, Response to Inadequate Core Cooling, Rev. 13-FR'C.2, Response to Degraded Core Cooling, Rev. 23-FR-H.1, Response to Loss of Secondary Heat Sink, Rev. 43-GRAPH-EL-4, EOP Equipment Load List, Rev. 33-GRAPH-RPC-16, Core Operating Limits Report, Rev.4ONOP-CVCS-3, Emergency Boration, Rev. 11Attachment

A-73-lC-PC-l-P-31DJW, Diesel Generator No. 31 Jacket Water Pressure, Rev.1 13-OSP-TG-002, City Water Cooling of Seal Oil Unit during an Outage, Rev. 03-PT-M108, RHRySI/CS System Venting, Rev. 143-PT-Q83, RWST Level lnstrument Check and Calibration (LlC-921 and

LC-923), Rev. 343-PT-R010A, Residual Heat Removal System Leakage Test, Rev. 143-PT-V11A, Calibration of OTdT & OPdT Dynamic Setpoint Compensators, Rev. 133-SOP-CSS-O01, Containment Spray System Operation, Rev. 33-SOP-EL-O15, Operation of Non-Safeguards Equipment during Use of EOPs, Rev. 203-SOP-ESP-0O1, Local Equipment Operation and Contingency Actions, Rev. 213-SOP-RHR-001, Residual Heat Removal System Operation, Rev. 423-SOP-Sl-002, Filling the Refueling Water Storage Tank, Rev. 11ELITE-PROC-O1, Elite Pipeline Services Seal Installation Procedure, Rev. 2EN-DC-1 15, Engineering Change Process, Rev. 12EN-DC-117, Post Modification Testing and Special Instructions, Rev. 4EN-DC-134, Design Verification, Rev. 4EN-DC-315, Flow Accelerated Corrosion Program, Rev. 6EN-DC-319, lnspections and Evaluation of Boric Acid Leaks, Rev. 7EN-LI-100, Process Applicability Determination, Rev. 10EN-Ll-101, 10

CFR 50.59 Evaluations, Rev.7lP2-RPT-03-0001 5, lP2 Fire Hazard Analysis, Rev. 2lP-SMM-AD-102, Diesel Generator No. 23 Jacket Water Pressure, Rev. 6LARP-028, Unit 2 Service Water Screen Trouble Bldg., Rev. 5OAP-007, Containment Entry and Egress, Rev. 23OAP-017, Plant Surveillance and Operator Rounds, Rev. 6PT-EM-9, Fire Dampers Operability, Rev. 4PT-SA1 1, Diesel Generator Building Fire Detection System, Rev. 5Work Orders131377 32112 52193256147007

51324292 52214688168963-09

51451678 52214810206242

51479747 52261358213490

51485917 52267012213491

51565373 52267017226647

51794538 52309613249668

51800931 52318311Vendor ManualsForm 651, SOR Switches for the Nuclear Power Industry, (05.07) dated 2007Form 654, Nuclear-Qualified SOR Pressure Switches, (02.1 1) dated 2011UEC Cat 54-8-02, United Electric Controls 54 Series Pressure, Vacuum and TemperatureSwitches, Rev.2Audits and Self-AssessmentsIP3LO-2009-00032-CA1, Plant Modifications and 50.59 Evaluations, performed 5115109-5121109IP3LO-2011-00013-CA3, Plant Modifications and 50.59 Evaluations, performed 4113111-5102111QA-04-2010-lP-1, Engineering Design Control Audit, dated 5127110Attachment

A-8Miscellaneous2-GRAPH-RPC-6, Cycle 20 Core Operating Limits Report (COLR), Rev. 133-GRAPH-RPC-16, Cycle 17 Core Operating Limits Report (COLR), Rev. 4EC-15966, EC for Replacement of Critical (Non-UPR) Relays on 32 EDG, Rev. 0EC-31159, EC for Replacement of

SDR-2 Relay on 32 EDG, Rev. 0EGP-91-07056-E, Modify EDG Transfer Switches & Control Circuits, Rev.0Elite Pipeline Services Seal lnstallation Verification Forms for Seals 1 thru 55, dated

3120111 to3121111ENN-IC-G-003, lnstrument Loop Accuracy and Setpoint Calculation Methodology, Rev. 0Fairbanks Morse Letter Regarding lP2 EDG's Minimum Jacket Water Temperature, dated 519194Fire Hazards Analysis lP2-RPT-03-00015, Rev. 2I0LP-LOR-OUTMOD, Training of Vortex Suppressor Modification, Rev. 1l3LP-lLO-RHRO1, Training for RHR Pump Seal Heat Exchangers, Rev. 1lP-2-AFW DBD, Design Basis Document for Auxiliary Feedwater System, Rev. 2lP2-SW-DBD, Service Water System, Rev. 1IP3-DBD-302, Design Basis Document for Residual Heat Removal System (RHRS), Rev. 4lP3-DBD-307, Design Basis Document for 480VAC, 125VDC, 120V Vital AC ElectricalDistribution System, Rev. 3lP3-DBD-314, Design Basis Document for the Reactor Coolant System, Rev, 2lP3-DBD-323, Design Basis Document for the Containment Spray System, Rev. 1lP3-DBD-324, Design Basis Document for the Emergency Diesel Generators and Appendix RDiesel Generator, Rev. 1Letter, NRC to Consolidated Edison, Safety Evaluation for Indian Point 2 Susceptibility of Safety-related Equipment to Flooding from Non-seismic Systems Outside Containment(ML1 00321 278), dated 1 2-1 8-1 980NL-72-81 3, lP-2 Review of Non-Seismic Equipment Failures, dated 12118172NL-73-A45, Investigation on Effects of Postulated Break in a Main Steam or Feedwater Line onthe Auxiliary Feedwater System, dated 419173PA-80-C04, Safety Evaluation Report Susceptibility of Safety-Related Systems to Flooding fromFailure of Non-Category 1 Systems for lP 2, dated 12118180PD-95-034, lP-2 Individual Plant Examination of External Events, dated 12195Pl-V17, Penetration Fire Barrier Seal Inspections, Rev. 6, dated 4111103PMT Plan for

EC 10675, Test of Zurn Strainer Circuits, Rev. 0SEP-AP-J-006, Primary Containment Leakage Rate Program, Rev. 1TEAR IPEC 2011-24,Training Evaluation for

EC-26647 Replacement of 33 EDG ShutdownRelayTechnical Requirements ManualsTechnical SpecificationsTS-MS-027, Specification for Service Water Piping & Piping Components, Rev. 3Updated Final Safety Analysis Report, lndian Point Unit 2, Rev. 22Updated Final Safety Analysis Report, Indian Point Unit 3, Rev. 3Westinghouse letter to Mr. J.F. Conway, Manager Nuclear Fuel Supply Consolidated Edison Co.of New York, lnc., lndian Point Unit 3 Dummy Fuel Assembly Offer, dated 07125173Attachment

A-9Surveillance and Modification Acceptance Tests2-lC-PC-l-T-22EDG, Emergency Diesel Generator No. 22 Temperature lnstruments Calibration,performed 31301 1 1 and 91201 1 12-lC-PC-I-P-23DJW, Diesel Generator No. 23 Jacket Water Pressure, performed 11191103-PT-CS032A, Flow Test of SW HDR CK VLVS and Flow Test of Underground Portions of Line409, performed 4131113-PT-M079A, 31 EDG FunctionalTest, performed 4111108Attachment

ADAMSASMECAPccwCFRCOLRCRCRACSCSSDBADBDDPDRSECEDGFMEr&ctMcIPISTJWLOCAMOVNCVNEINRCOPdTOTdTPABPARSPMTRHRRPSRWSTSDPSISSCSWTSUFSARVCVDCA-10

LIST OF ACRONYMS

Agencyruide Documents Access and Management SystemAmerican Society of Mechanical EngineersCorrective Action ProgramComponent Cooling WaterCode of Federal RegulationsCore Operating Limits ReportCondition ReportControl Room Air Conditioning SystemContainment Spray SystemDesign Basis AccidentDesign Basis DocumentDifferential PressureDivision of Reactor SafetyEngineering ChangeEmergency Diesel GeneratorForeign Material Exclusionlnstrumentation and ControlInspection Manual Chapterlnspection ProcedureIn-service TestingJacket WaterLoss-of-Coolant AccidentMotor Operated ValveNon-cited ViolationNuclear Energy lnstituteNuclear Regulatory CommissionOver-Power Delta-TemperatureOver-Tem perature Delta-Tem peraturePrimary Auxiliary BuildingPublicly Available RecordsPost-Modification TestResidual Heat RemovalReactor Protection SystemRefueling Water Storage TankSignificance Determination ProcessSafety lnjectionStructure, System and ComponentService WaterTech nica I SpecificationsUpdated Final Safety Analysis ReportVapor ContainmentVolts Direct CurrentAttachment