IR 05000247/2011008

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July 11, 20LlMr. Joseph Pollock, Site Vice PresidentEntergy Nuclear OPerations, lnc.lndian Point Energy Center450 Broadway, GSBP.O. Box 249Buchanan, NY 1051 1-0249

SUBJECT: INDIAN POINT NUCLEAR GENERATING UNIT 3 - NRC TRIENNIAL FIREPROTECTION AND INDIAN POINT NUCLEAR GENERATING UNITS 2 AND 3'ANNUAL FOLLOW-UP OF SELECTED ISSUES (OPEMTOR MANUALACTIONS) INSPECTION REPORTS 05000247 t2011010 AND05000286/201 1 008

Dear Mr. Pollock:

On May 27 ,2011, the U.S. Nuclear Regulatory Commission (NRC) completed a triennial fireprotection inspection at Indian Point Nuclear Generating Unit 3 and an annual follow-up ofselected issues inspection at Units 2 and 3. The enclosed inspection report documents theinspection results, which were discussed on May 27 ,2011, with Mr. Patric Conroy and othermembers of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commissions rules and regulations, and with the conditions of your license.The ieam reviewed selected procedures and records, observed activities, and interviewedpersonnel.Based on the results of this inspection, one finding of very low safety significance (Green) wasidentified. This finding was also determined to be a violation of NRC requirements. However,because of the very low safety significance, and because the finding was entered into yourcorrective action piogram, the NRC is treating this finding as a non-cited violation (NCV)consistent with Sectio n 2.3.2 of the NRC Enforcement Policy. lf you contest the NCV in thisreport, you should provide a written response within 30 days of the date of this inspection reportwiin tne basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document ControlDesk, Washington D.C. 20555-OOO1; with copies to the Regional Administrator, Region l; theDirector, Office of Enforcement; and the NRC Senior Resident lnspector at Indian Point NuclearGenerating Unit 3. In addition, if you disagree with the characterization of any finding in thisreport, you should provide a response within 30 days of the date of this inspection report, withthe basls for your disagreement, to the RegionalAdministrator, Region l, and the SeniorResident Inspector at lndian Point Nuclear Generating Unit 3. The information you provide willbe considered in accordance with Inspection Manual Chapter 0305. In accordance with Title 10 of the Code of Federal Regulations Part 2.390 of the NRC's "Rulesof Practice," a copy of this letter, its enclosure, and your response (if any) will be availableelectronically for public inspection in the NRC Public Document Room or from the PubliclyAvailable Records (PARS) component of the NRC's document system, Agencywide DocumentsAccess and Management System (ADAMS). ADAMS is accessible from the NRC Web Site athttp://www.nrc.qov/readins-rm/adams.html (the Public Electronic Reading Room).

Sincerely,%v@t/John F. Rogge, ChiefEngineering Branch 3Division of Reactor SafetyDocketNos. 50-247,50-286License Nos. DPR-26, DPR-64

Enclosure:

f nspection Report Nos. 0500024712011010 and 05000286/2011008

w/Attachment:

Supplemental lnformationcc w/encl: Distribution via ListServ

SUMMARY OF FINDINGS

lR 0500024712011010,0500028612011008; 0510912011 -0512712011; Indian Point NuclearGenerating Units 2 and 3; Unit 3 Triennial Fire Protection Team and Units 2 and 3 AnnualFollow-up of Selected lssues Inspections.The report covered a two-week triennialfire protection team inspection and annualfollow-up ofselected issues inspection by specialist inspectors. One finding of very low significance wasidentified. This finding was determined to be a non-cited violation. The significance of mostfindings is indicated by their color (Green, White, Yellow, Red) using Inspection ManualChapter 0609, "Significance Determination Process" and the cross-cutting aspect wasdetermined using IMC 0305, "Operating Reactor Assessment Program." Findings for which thesignificance determination process (SDP) does not apply may be Green or be assigned aseverity level after NRC management review. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "ReactorOversight Process," Revision 4, dated December 2006.

Cornerstone: Mitigating Systems.

Green.

The team identified a Green, Non-Cited Violation (NCV) of Indian Point NuclearGenerating Unit 3 Operating License Condition 2.H, in that Entergy did not establish anappropriate interim compensatory measure for several fire areas where 10 CFR 50Appendix R paragraph lll.G.2 fire protection deficiencies associated with the fireprotection of service water (SW) strainer motors and backwash valves existed.Specifically, Entergy in response to Regulatory lssue Summary (RlS) 2006-10,"Regulatory Expectations with Appendix R Paragraph lll.G.2 Operator ManualActions,"dated June 30, 2006, identified on September 5, 2006, that operator manual actions(OMAs) were being utilized in several fire areas instead of the fire protection optionsspecified in paragraph lll.G.2 and without an exemption from the NRC staff. For fireareas that potentially impacted the electrical circuits to the SW strainers, Entergycontinued to maintain the OMA to manually backwash SW strainers as an interimcompensatory measure while seeking NRC staff approval through the exemptionprocess. The team identified that the interim compensatory measure was inappropriatebecause it was too complex and beyond the limited scope of an OMA to achieve andmaintain postfire hot shutdown. Entergy entered the Unit 3 SW strainer OMA issue intoits corrective action program for long term resolution as condition report CR-lP3-2011-02951 and promptly established an hourly fire watch in fire areas where SW strainercircuits may be affected.This finding is more than minor because it is associated with the External Factorsattribute (fire) of the Mitigating Systems Cornerstone and adversely affected its objectiveof ensuring the availability, reliability, and capability of systems that respond to initiatingevents to prevent undesirable consequences. Specifically, the reliability of SW was notensured for fire scenarios that damage circuits to the SW strainer motor or backwashvalve. The team evaluated this issue using Phase 1 of IMC 0609, Appendix F, FireProtection Significance Determination Process (SDP), and determined that the issuescreened to Green because a low degradation factor was assigned. The team assigneda low degradation factor because although the manual actions were beyond the scope of" =nclosure an OMA and Entergy did not appropriately evaluate feasibility, the team determinedseveral hours would likely exist to complete the action before strainer differentialpressure (d/p) challenged SW flow to the emergency diesel generators and the OMAwould be successful to maintain adequate SW flow.The team determined that this finding has a cross-cutting aspect in the area of Problemldentification and Resolution associated with the attribute of the corrective actionprogram because Entergy personnel did not thoroughly evaluate necessaryconsiderations associated with the Unit 3 SW strainer OMA. Specifically, Entergywalked down all OMAs on May 20, 2011, to evaluate feasibility but did not identify issuesrelated to incomplete pre-staged tools, an OMA procedure with steps associated withnormal maintenance conditions that would delay implementation, and control roomannunciator circuits that may be affected by the fire. (P.1(c) per IMC 0310) (Section4cA2.2)

REPORT DETAILS

BackoroundThis report presents the results of a Unit 3 triennial fire protection inspection conducted inaccordance with NRC Inspection Procedure (lP) 71111.05T, "Fire Protection." Additionally, thereport documents the observations and findings of a Units 2 and 3 annual follow-up of selectedissues in accordance with NRC lP 71152, "Problem ldentification and Resolution," regardingoperator manual actions interim compensatory measures for documented corrective actionsrelated to 10 CFR 50 Appendix R paragraph lll.G.2 fire protection deficiencies. The objective ofthe triennialfire protection inspection was to assess whether Entergy has implemented anadequate fire protection program and that post-fire safe shutdown capabilities have beenestablished and are being properly maintained at the lndian Point Nuclear Generating Unit 3.The following fire areas (FAs) and fire zones (FZs)were selected for detailed review based onrisk insights from the Indian Point Unit 3 Individual Plant Examination of External Events:o FA CTL-3, FZ 11;r FA CTL-3, FZ 14;. FAPAB-2, FZ1;and. FA PAB-2, FZ 59A.lnspection of these areas/zones fulfills the inspection procedure requirement to inspect aminimum of three samples.The inspection team evaluated the licensee's fire protection program (FPP) against applicablerequirements which included plant Technical Specifications, Operating License Conditions 2.H,NRC Safety Evaluations, 10 CFR 50.48, 10 CFR 50, Appendix R and Branch Technical Position(BTP) 9.5-1. The team also reviewed related documents that included the Updated Final SafetyAnafysis Report (UFSAR), Section 9.6.2, the fire hazards analysis (FHA), and the post-fire safeshutdown analyses.Unit 2 and Unit 3 licensee mitigating strategies for addressing large fires and explosions wereevaluated during the Unit 2 Triennial Fire Protection Inspection in February 2010 and weredocumented in NRC Inspection Report 0500024712010006 and 0500028612010006. Unit 2 andUnit 3 licensee mitigating strategies were reviewed in April 2011 as part of the Temporaryf nstruction 25151183 inspections and were documented in NRC Inspection Reports050002471201 1009 and 0500028612011009. These inspections complete the inspectionsample requirements for the triennial fire inspection procedure cycle.Specific documents reviewed by the team are listed in the attachment.Enclosure 1 R05.01a..02b.a.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier IntegrityFire Protection (lP 7111 1.05T)Protection of Safe Shutdown Capabilitieslnspection ScopeThe team reviewed the fire hazards analysis (FHA), safe shutdown analyses, andsupporting drawings and documentation to verify that safe shutdown capabilities wereproperly protected. The team ensured that applicable separation requirements ofSection lll.G of 10 CFR 50, Appendix R and the licensee's design and licensing baseswere maintained for the credited safe shutdown equipment and their supporting power,control and instrumentation cables. This review included an assessment of theadequacy of the selected systems for reactivity control, reactor coolant makeup, reactorheat removal, process monitoring, and associated support system functions.FindinqsNo findings were identified.Passive Fire ProtectionInspection ScopeThe team walked down accessible portions of the selected fire areas to observe materialconditions and the adequacy of design of fire area boundaries (including walls, ceilings,floors, fire doors and fire dampers), electrical raceway fire barriers, and equipment firebarriers to ensure they were appropriate for the fire hazards in the area.The team reviewed installation, repair and qualification records for a sample of openingsand/or penetration seals to ensure the fill material was of the appropriate fire rating andthat the installation met the engineering design. The team reviewed similar records forthe fire protection wraps to ensure the material was of an appropriate fire rating and thatthe installation met the engineering design. The team also reviewed completedsurveillance and maintenance procedures for selected passive fire protection features toverify that maintenance and inspection activities are adequate.FindinqsNo findings were identified.b.Enclosure

.033 Active Fire ProtectionInspection ScopeThe team reviewed the design, maintenance, testing, and operation of the fire detectionand suppression systems in the selected plant fire areas. This included verification thatthe manual and automatic detection and suppression systems were installed, tested,and maintained in accordance with the National Fire Protection Association (NFPA) codeof record, or as NRC approved exemptions, and that each suppression system wouldcontrol or extinguish fires associated with the hazards in the selected areas. A review ofthe design capabilities of the suppression agent delivery systems were verified to meetthe code requirements for the hazards involved. The team also performed a walkdownof accessible portions of the detection and suppression systems in the selected areas aswell as a walkdown of major system support equipment in other areas (e.9. fire pumpsand carbon dioxide storage tanks and supply system) to assess the material conditionand the operational lineup and availability of the systems and components.The team reviewed electric and dieselfire pump flow and pressure tests to ensure thatthe pumps were meeting their design requirements. The team also reviewed the firemain loop flow tests to ensure that the flow distribution circuits were able to meet thedesign requirements.The team assessed the flre brigade capabilities by reviewing training, qualification, anddrill critique records. The team also compared pre-fire plans for the selected fire areaswith as-built plant conditions and fire response procedures to verify fire-fighting pre-fireplans are consistent with the fire protection features and potential fire conditionsdescribed in the FPP. In addition, the team inspected the fire brigade equipment(including smoke removal equipment) to determine operational readiness for fire fighting.FindinqsNo findings were identified.Protection From Damaqe From Fire Suppression ActivitiesInspection ScopeThe team performed document reviews and plant walkdowns to verify that redundanttrains of systems required for hot shutdown, which are located in the same fire area, arenot subject to damage from fire suppression activities or from the rupture or inadvertentoperation of fire suppression systems. Specifically, the team verified that:. A fire in one of the selected fire areas would not indirectly, through production ofsmoke, heat or hot gases, cause activation of suppression systems that couldpotentially damage redundant safe shutdown trains;b..04Enclosure

b.a..054. A fire in one of the selected fire areas (or the inadvertent actuation or rupture of afire suppression system) would not indirectly cause damage to redundant trains(e.g. sprinkler caused flooding of other than the locally affected train); and,r Adequate drainage is provided in areas protected by water suppression systems.FindinqsNo findings were identified.Shutdown Capabilitv - Normal and AlternativeInspection ScopeThe team reviewed the safe shutdown analysis, operating procedures, piping andinstrumentation drawings (P&lDs), electrical drawings, the UFSAR and other supportingdocuments for the selected fire areas to verify that the licensee had properly identifiedthe systems and components necessary to achieve and maintain safe shutdownconditions. The team assessed the adequacy of the selected systems and componentsfor reactivity control, reactor coolant makeup, reactor heat removal, process monitoring,and support system functions. This review included verification that alternative post-fireshutdown could be performed both with and without the availability of offsite power.Plant walkdowns were also performed to verify that the plant configuration wasconsistent with that described in the safe shutdown and fire hazards analyses. Theteam verified that the systems and components credited for use during shutdown wouldremain free from fire damage.The team verified that the training program for licensed and non-licensed operatorsincluded alternative shutdown capability. The team also verified that personnel requiredfor safe shutdown using the normal or alternative shutdown systems and procedureswere trained and available onsite at all times, exclusive of those assigned as fire brigademembers.The team reviewed the adequacy of procedures utilized for post-fire shutdown andperformed an independent walk through of procedure steps to ensure theimplementation and human factors adequacy of the procedures. The team also verifiedthat the operators could be reasonably expected to perform specific actions within thetime required to maintain plant parameters within specified limits.Specific procedures reviewed for normal and alternative post-fire shutdown included thefollowing:. 3-AOP-SSD-1, Control Room lnaccessibility Safe Shutdown Control, Rev. 11 and12:. 3-ELC-004-FlR, Appendix "R" Repair, Rev. 12;. 3-ONOP-FP-1, Plant Fires, Rev. 27;o 3-SOP-EL-012, Operation of the Alternative Safe Shutdown Equipment, Rev. 17;Enclosure b.a..065. 3-SOP-EL-013, Appendix R Diesel Generator Operation, Rev. 24; and. 3-SOP-ESP-OO1, Local Equipment Operation and Contingency Actions, Rev. 19.The team reviewed manual actions to ensure that they had been properly reviewed andapproved and that the actions could be implemented in accordance with plantprocedures in the time necessary to support the safe shutdown method for each firearea. The team also reviewed the periodic testing of the alternative shutdown transfercapability and instrumentation and controlfunctions to ensure the tests are adequate toensure the functionality of the alternative shutdown capability.FindinqsNo findings were identified.Circuit Analvsislnspection ScopeThe team verified that the licensee performed a post-fire safe shutdown analysis for theselected fire areas and the analysis appropriately identified the structures, systems, andcomponents important to achieving and maintaining safe shutdown. Additionally, theteam verified that the licensee's analysis ensured that necessary electrical circuits wereproperly protected and that circuits that could adversely impact safe shutdown due to hotshorts or shorts to ground were identified, evaluated, and dispositioned to ensurespurious actuations would not prevent safe shutdown.The team's review considered fire and cable attributes, cable routing, potentialundesirable consequences and common power supply/bus concerns. Specific itemsincluded the credibility of the fire threat, cable insulation attributes, cable failure modes,and actuations resulting in flow diversion or loss of coolant events.The team also reviewed cable raceway drawings and/or cable routing databases for asample of components required for post-fire safe shutdown to verify that cables wererouted as described in the safe-shutdown analysis. The team also reviewed equipmentimportant to safe shutdown, but not part of the success path, to verify that the licenseehad taken appropriate actions in accordance with the design and licensing basis andNRC Regulatory Guide 1.189.Cable failure modes were reviewed for the following components:. 31 charging pump;o 32 charging pump;. 32 component cooling water pump;. Ll-459 pressurizer level instrument;. Ll-417D 31 steam generator wide level instrument; and,. Pl402B, reactor coolant system loop 1 pressure instrument.Enclosure b..076The team reviewed a sample of circuit breaker coordination studies to ensure equipmentneeded to conduct post-fire safe shutdown activities would not be impacted due to a lackof coordination that could result in a common power supply or common bus concern.The team verified that the transfer of control from the control room to the alternativeshutdown location(s) would not be affected by fire-induced circuit faults (e.9., by theprovision of separate fuses and power supplies for alternative shutdown control circuits).FindinqsNo findings were identified.CommunicationsInspection ScopeThe team reviewed safe shutdown procedures, the safe shutdown analysis, andassociated documents to verify an adequate method of communications would beavailable to plant operators following a fire. During this review the team considered theeffects of ambient noise levels, clarity of reception, reliability, and coverage patterns.The team also inspected the designated emergency storage lockers to verify theavailability of portable radios for the fire brigade and for plant operators. The team alsoverified that communications equipment such as repeaters and transmitters would not beaffected by a fire.FindinosNo findings wereEmerqencv Lightinolnspection ScopeThe team observed the placement and coverage area of eight-hour emergency lightsthroughout the selected fire areas to evaluate their adequacy for illuminating access andegress pathways and any equipment requiring local operation or instrumentationmonitoring for post-fire safe shutdown. The team also verified that the battery powersupplies were rated for at least an eight-hour capacity. Preventive maintenanceprocedures, the vendor manual, completed surveillance tests, and battery replacementpractices were also reviewed to verify that the emergency lighting was being maintainedconsistent with the manufacturer's recommendations and in a manner that would ensurereliable operation.FindinosNo findings were identified.b..08b.Enclosure 09a.7Cold Shutdown RepairsInspection ScopeThe team verified that the licensee had dedicated repair procedures, equipment, andmaterials to accomplish repairs of components required for cold shutdown which mightbe damaged by the fire to ensure cold shutdown could be achieved within the timeframes specified in their design and licensing bases. The team verified that the repairequipment, components, tools, and materials (e.9., pre-cut cables with preparedattachment lugs) were available and accessible on site.FindinosNo findings were identified.Compensatorv Measureslnspection ScopeThe 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.9. detection and suppression systems and equipment, passive firebarriers, or pumps, valves or electrical devices providing safe shutdown functions orcapabilities). The team also verified that the short term compensatory measurescompensated for the degraded function or feature until appropriate corrective actioncould be taken and that the licensee was effective in returning the equipment to servicein a reasonable period of time.The team reviewed compensatory measures in the form of manual actions for10 CFR Part 50 Appendix R, Section lll.G.2 areas to verify that there is reasonableassurance that manual actions can be accomplished. Specific attributes reviewedinclude diagnostic instrumentation, environmental consideration, staffing,communications, equipment availability, training, procedures, and verification andvalidation. On September 5, 2006, Entergy documented in condition reports CR-lP2-2006-05299 and CR-lP3-2006-02747 that operator manual actions were inappropriatelycredited in lieu of one of the means of fire protection required by 10 CFR 50 Appendix R,paragraph lll.G.2 in several Unit 2 and Unit 3 fire areas. A detailed follow-up of thisissue is documented in section

4OA2 of this inspection report.FindinqsSee section 4OA2 of this inspection report.b..10a.Enclosure

8.11 Fire Protection Proqram Chanoesa. Inspection ScopeThe team reviewed recent changes to the approved fire protection program to verify thatthe changes did not constitute an adverse effect on the ability to safely shutdown.b. FindinssNo findings were identified..12 Control of Transient Combustibles and lqnition Sourcesa. lnspection ScopeThe team reviewed the licensee's procedures and programs for the control of ignitionsources and transient combustibles to assess their effectiveness in preventing fires andin controlling combustible loading within limits established in the FHA. A sample of hotwork and transient combustible control permits were also reviewed. The teamperformed plant walkdowns to verify that transient combustibles and ignition sourceswere being implemented in accordance with the administrative controls.b. FindinqsNo findings were identified.4. OTHER ACTTVTTTES IOAI4OA2 ldentification and Resolution of Problems.01 Corrective Actions for Fire Protection Deficienciesa. Inspection ScopeThe team verified that the licensee was identifying fire protection and post-fire safeshutdown issues at an appropriate threshold and entering them into the corrective actionprogram. The team also reviewed a sample of selected issues to verify that the licenseehad taken or planned appropriate corrective actions.b. FindinqsNo findings were identified.Enclosure

.29 Selected lssue Follow-up Inspection: lndian Point Units 2 and 3 Operator ManualActionslnspection ScopeOn June 30, 2006, the NRC issued Regulatory lssue Summary (RlS) 2006-10,"Regulatory Expectations with Appendix R paragraph lll.G.2 Operator ManualActions(OMAs)," which provided guidance for the resolution of OMAs in lieu of one of the meansspecified in Appendix R paragraph lll.G.2 to ensure a train is free of fire damage whenredundant trains were in the same fire area. In accordance with RIS 2006-10 andEnforcement Guidance Memorandum (EGM)98-002, Revision 2, Supplement 1 -"Disposition of Violations of 10 CFR Part 50, Appendix R, Sections lll.G and lll.L,Regarding Circuit Failures," Entergy submitted exemption requests for OMAs atlndian Point Units 2 and 3. Also, in accordance with EGM 98-002, Entergy implementedOMAs as interim compensatory measures while the exemption requests were beingreviewed by the NRC's Office of Nuclear Reactor Regulation (NRR).The team performed a focused inspection of the OMAs that were being credited asinterim compensatory actions pending NRC review of OMAs submitted as part of theirexemption requests. This inspection assessed the adequacy of the OMAs as interimcompensatory actions. The review of OMAs associated with exemption requests isbeing conducted by NRR staff under the NRC exemption review process in accordancewith 10 CFR 50.12. The team interviewed associated engineers to understand thespecific required actions and time margins for, the OMAs. The team independentlyreviewed the procedures that would be used to implement the OMAs. Finally, the teamwalked down all of the OMAs being credited as interim compensatory measures fordeficient lll.G.2 Unit 2 and Unit 3 fire areas with plant operators to assess the feasibilityof the actions using the guidance in lP 71111.05T, Section 02.02'i.2.Findinqslntroduction: The team identified a Green, Non-Cited Violation (NCV) of lndian PointNuclear Generating Unit 3 Operating License Condition 2.H, in that Entergy did notestablish an appropriate interim compensatory measure for several fire areas where10 CFR 50 Appendix R, paragraph lll.G.2 fire protection deficiencies associated with thefire protection of service water (SW) strainer motors and backwash valves existed.Specifically, Entergy in response to RIS 2006-10, identified on September 5, 2006, thatoperator manual actions (OMAs) were being utilized in several fire areas instead of thefire protection options specified in paragraph lll.G.2 and without an exemption from theNRC staff. For fire areas that potentially impacted the electrical circuits to the SWstrainers, Entergy continued to maintain the OMA to manually backwash SW strainersas an interim compensatory measure while seeking NRC staff approval through theexemption process. The team identified that the interim compensatory measure wasinappropriate because it was too complex and beyond the limited scope of an OMA toachieve and maintain post fire hot shutdown.Enclosurea.b.Function

10Description: 10 CFR 50 Appendix R paragraph lll.G.2 requires that where cables orequipment, including associated non-safety circuits that could prevent operation orcause maloperation due to hot shorts, open circuits, or shorts to ground, of redundanttrains of systems necessary to achieve and maintain hot shutdown conditions arelocated within the same fire area outside of primary containment, one of three means ofprotecting cables to ensure that one of the redundant trains is free of fire damage shallbe provided. The three acceptable means described in paragraph lll.G.2 to ensure oneof the redundant trains in the same fire area is free of fire damage are based on the useof physical barriers, spatial separation, or fire detection and an automatic firesuppression system. RIS 2006-10, an NRC generic communication to licensees,described how licensees historically and inappropriately compensated for the lack oflll.G.z protection methods by relying on OMAs which had not been reviewed andapproved by the NRC through the 10 CFR 50.12 exemption process. RIS 2006-10 alsoprovided information useful to licensing and engineering staffs at operating reactors inachieving compliance with paragraph lll.G.2 if unapproved OMAs in lieu of lll.G.2 fireprotection methods were identified by licensees. For plants licensed to operate beforeJanuary 1, 1979, such as lndian Points Units 2 and 3, the use of OMAs in lieu of one ofthe means specified in lll.G.2, requires an exemption under 10 CFR 50.12.Entergy reviewed RIS 2006-10 and on September 5, 2006, identified several lll.G.2 non-compliances at both Unit 2 and Unit 3 where OMAs were being relied upon and were notapproved by the NRC. Entergy entered the issues into the corrective action program asCR-lP2-2006-05299 and CR-lP3-2006-02747. Entergy further evaluated each existingOMA using guidance to inspectors on compensatory measures and specifically OMAs inNRC lnspection Procedure 71 11 1.05T, Fire Protection (Triennial), Section 02.02.i.2. OnSeptember 8, 2006, Entergy concluded the OMAs in non-compliant lll.G.2 fire areaswere acceptable as interim compensatory measures. Entergy documented theevaluations of each Unit 2 and Unit 3 OMA in condition reports, CR-lP2-2006-05299 andCR-lP3-2006-02747. Consistent with the guidance in RIS 2006-10, Entergy alsosubmitted an exemption request under 10 CFR 5A12 for NRC approval of each OMA.The team similarly reviewed the guidance in lP 71111.05T, Section02.02.i.2butdetermined an interim compensatory measure or OMA for manually backwashing Unit 3SW strainers was inappropriate. SW provides the necessary cooling for emergencydiesel generator (EDG) operation during postfire safe shutdown. Entergy's safeshutdown analysis credited the EDG's for the affected lll.G.2 fire ardas. The SWstrainers clean the Hudson River water removing small debris and detritus. The SWstrainer function is important and prevents SW cooled components, such as the EDGs,from being fouled and a subsequent loss in heat removal capability. During normaloperation, the SW strainers automatically backwash 5 minutes for every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> ofoperation. Backwash is automatically accomplished when an air operated backwashvalve opens and a motor at the top of the SW strainer rotates the backwash arm. Debrisor detritus that collected on the strainer is removed and eliminated through thebackwash valve. The OMA compensated for the fire induced loss of automatic functionby performing the same backwash action. However an operator must manually open thebackwash valve and manually rotate the SW strainer backwash arm. Each is rotated bya wrench that is placed on an extruding stem flat. Prior to rotating the backwash valve,instrument air lines to the backwash valve actuator must also be removed with a wrench.Enclosure 11Additionally, the motor actuator to the backwash arm must be disengaged. Requiredtools include various size wrenches, needle nose pliers, a flat head screwdriver, and aruler which is used to measure the backwash arm to the proper height and clearance.The team reviewed the OMA considerations in ]P 71111.05T Section 02.02.j.2 anddetermined those not appropriately considered by Entergy included diagnosticinstrumentation, eq uipment availabil ity, and procedures.o Diagnostic Instrumentation was inadequately considered because Entergy didnot verify that the control.room high differential pressure (d/p) annunciator circuitswere not affected by the fire or did not provide compensatory measures tofrequently backwash the SW strainers. Entergy relied on an initial localobservation of SW strainer d/p and provided instructions inprocedure 3-ONOP-FP-1, Plant Fires, Rev. 27, to manually backwash thestrainer if d/p exceeded 6 pounds per square inch differential (psid), however,after the initial reading, no further procedure instructions existed to monitor thelocal d/p indicator.o Equipment availability was inadequately considered because the necessary toolswere not dedicated and readily available. Only one wrench was provided whichwas sized to rotate the valve actuator and it was either too big or too small for allother required wrench operations. Additionally, Entergy did not evaluate thetorque required to rotate the SW strainer with a wrench and evaluate thefeasibility of an operator completing the rotation for a given length wrench.r Procedures were inadequately considered because 3-STR-0002-SWS, Main andBack-Up Service Water Pump Strainer Manual Backwashing (ln the Event ofAppendix R Loss of Strainer Power Supply), Rev. 2 did not appropriatelyexpedite the manual action for the postfire safe shutdown circumstances.3-STR-0002-SWS included unnecessary steps such as requiring planningdepartment involvement and a work order, reading through Attachment 1,Industry Experiences prior to the start of work, establishing a clean work area,and other normal work controls that would inappropriately delay the OMA.Additionally, the team further determined that the manual actions to backwash a SWstrainer were too complex for the limited scope of an OMA. Regulatory Guide (RG)1.189, Fire Protection for Nuclear Power Plants, Rev. 2, defined OMAs as actions thatare performed by operators to manipulate components and equipment from outside thecontrol room to achieve and maintain postfire hot shutdown, not including repairs.RG 1.189 included examples of OMAs as the manual operation of valves, switches, andcircuit breakers to operate equipment and isolate systems and is not considered arepair. The team concluded Entergy's actions to manually backwash a SW strainer weresignificantly beyond actions comparable to these and were too complex to be an OMA.The team also noted that Entergy had an opportunity to recently identify the inadequateOMA considerations. On May 18,2011, Entergy initiated condition reports CR-lP2-2011-02417 and CR-lP3-2011-02853 to re-evaluate the feasibility of OMAs. Entergywalked down all OMAs on May 20, 2011, but did not identify these issues related toUnit 3 SW strainer OMA. Finally, the team noted that because there are distinctEnclosure 12differences in FPP designs between Unit 2 and Unit 3, a Unit 2 SW strainer OMA in lieuof paragraph lll.G.2 protection methods was not in place. Nonetheless, Entergy initiateda corrective action with CR-lP3-2011-029511o evaluate this issue for extent of conditionapplicability to Unit 2.Entergy entered the Unit 3 SW strainer OMA issue into its corrective action program forlong term resolution as condition report CR-lP3-2011-02951and promptly establishedan hourly fire watch in fire areas where SW strainer circuits may be affected: ETN-4,TBL-5, and YARD-7. The team concluded that the establishment of an hourly fire watchin the affected fire areas as an interim compensatory measure was commensurate withthe risk significance. The team also noted that all other Unit 2 and Unit 3 OMAs werejudged as feasible interim compensatory measures for non-compliant lll.G.2 fire areas.Analvsis: Entergy's failure to establish an adequate interim compensatory measure forthe Unit 3 SW strainer lll.G.2 non-compliance is a performance deficiency. This findingis more than minor because it is associated with the External Factors attribute (fire) ofthe Mitigating Systems Cornerstone and adversely affected its objective of ensuring theavailability, reliability, and capability of systems that respond to initiating events toprevent undesirable consequences. Specifically, the reliability of SW was not ensuredfor fire scenarios that damage circuits to the SW strainer motor or backwash valve.The team evaluated this issue using Phase 1 of IMC 0609, Appendix F, Fire ProtectionSignificance Determination Process (SDP), and determined that the issue screened toGreen because a low degradation factor was assigned. The team assigned a lowdegradation factor because although the manual actions were beyond the scope of anOMA and Entergy did not appropriately evaluate feasibility, the team determined severalhours would exist to complete the action before strainer d/p challenged SW flow to theEDGs and the OMA would be successful to maintain adequate SW flow. The timeinterval was based on historic plant data that charted very low strainer buildup within theautomatic two hour interval and a maintenance activity when the strainers were operatedwithout the backwash function, in one case for about 62 hours7.175926e-4 days <br />0.0172 hours <br />1.025132e-4 weeks <br />2.3591e-5 months <br />. The strainers are ratedto 17 psid and adequate SW cooling was evaluated to exist at this d/p. Typical strainerbuildup is 1 to 2 psid within the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> interval prior to automatic backwash. Additionally,although the proper tools and an expeditious procedure were not staged for the SWstrainer OMA, the tools were ordinary and would be readily available on site and themanual backwash procedure instructions were consistent with those also described inthe vendor manual. The team considered the worst case torque (138 foot-pounds) torotate the strainer and it was within reason to be rotated by hand with a long wrench.Finally, the team determined that the expected slow debris buildup and resultantincrease in SW strainer d/p would be sufficiently monitored during operator rounds.Based on these considerations, a low degradation factor was assigned and the issuescreened to very low safety significance (Green).As stated above, Entergy entered this issue into the corrective action program (referenceCR-lP3-2011-02951) and promptly initiated hourly fire watches in fire areas whereSW strainer circuits may be affected. The team concluded that Entergy's compensatorymeasures were commensurate with the risk significance.Enclosure 13The team determined that this finding has a cross-cutting aspect in the area of Problemldentification and Resolution associated with the attribute of the corrective actionprogram because Entergy personnel did not thoroughly evaluate necessaryconsiderations associated with the Unit 3 SW strainer OMA. Specifically, Entergywalked down all OMAs on May 20,2A11, to evaluate feasibility but did not identify theissues related to incomplete pre-staged tools, the cumbersome 3-STR-002-SWSprocedure, and d/p annunciator circuits that may be affected by the fire. (P.1(c) perrMc o31o)Enforcement. lndian Point Unit 3 Operating License Condition 2.H requires, in part, thatEntergy shall implement and maintain in effect all provisions of the approved FPP asdescribed in the UFSAR. UFSAR Section 9.6.2, Fire Protection, Rev. 03, 2009, includesthe lndian Point Energy Center (IPEC) FPP Plan as part of the FPP. SMM-DC-901,IPEC FPP Plan, Section 6.4.1, Rev. 7, states that impairment of fire protection featuresshall be compensated for by measures appropriate to the conditions. Contrary to theabove, on May 26,2011, the NRC identified that Entergy did not meet this requirementand had not historically met this requirement for three fire areas: ETN-4, TBL-S, andYARD-7. Entergy failed to protect the SW strainer motor and backwash valve circuitsfrom a postulated fire-induced circuit failure and implemented an operator manual actionin lieu of fire protection that was not appropriate to the conditions because it was notproperly evaluated for feasibility. Because this finding was of very low safetysignificance and was entered into Entergy's corrective action program (CR-lP3-2011-02951), this violation is being treated as a non-cited violation, consistent with Section2.3.2. of the NRC Enforcement Policy. (NCV 05000286/2011008-001, InappropriateInterim Compensatory Measure for Service Water Strainer Backwash Function)4046 Meetinqs, Includinq ExitExit Meetinq SummarvThe team presented their preliminary inspection results to Mr. Patric Conroy, Director,Nuclear Safety Assurance, and other members of the site staff at an exit meeting onMay 27, 2011. No proprietary information was included in this inspection report.ATTACHMENT: