IR 05000298/2010006: Difference between revisions

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{{Adams
{{Adams
| number = ML110760579
| number = ML110890962
| issue date = 03/17/2011
| issue date = 03/28/2011
| title = IR 05000298-10-006, on October 18,2010 - March 14, 2011, Nebraska Public Power District; Cooper Nuclear Station: Triennial Fire Protection Team Inspection, Preliminary White Finding
| title = IR 05000298-10-006, Cooper Nuclear Station Errata, Errata Triennial Fire Protection
| author name = Vegel A
| author name = O'Keefe N F
| author affiliation = NRC/RGN-IV/DRS
| author affiliation = NRC/RGN-IV/DNMS
| addressee name = O'Grady B J
| addressee name = O'Grady B J
| addressee affiliation = Nebraska Public Power District (NPPD)
| addressee affiliation = Nebraska Public Power District (NPPD)
Line 10: Line 10:
| license number = DPR-046
| license number = DPR-046
| contact person =  
| contact person =  
| case reference number = EA-11-024
| document report number = IR-10-006
| document report number = IR-10-006
| document type = Enforcement Action, Inspection Report, Letter
| document type = Letter
| page count = 55
| page count = 4
}}
}}


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=Text=
=Text=
{{#Wiki_filter:EA 11-024 March 17, 2011 Brian J. O'Grady, Vice President-Nuclear and Chief Nuclear Officer Nebraska Public Power District Cooper Nuclear Station 72676 648A Avenue Brownville, NE 68321
{{#Wiki_filter:
[[Issue date::March 28, 2011]]


SUBJECT: COOPER NUCLEAR STATION -NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000298/2010006; PRELIMINARY WHITE FINDING
Brian J. O'Grady, Vice President-Nuclear and Chief Nuclear Officer Nebraska Public Power District Cooper Nuclear Station 72676 648A Avenue Brownville, NE 68321
 
SUBJECT: ERRATA FOR NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000298/2010006, COOPER NUCLEAR STATION


==Dear Mr. O'Grady:==
==Dear Mr. O'Grady:==
On November 5,2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Cooper Nuclear Station. The enclosed inspection report documents the inspection results, which were discussed in an exit meeting on [[Exit meeting date::March 14, 2011]], with Mr. D. Buman, Director of Engineering, and other members of your staff. During this inspection, the NRC staff examined activities conducted under your license as they relate to public health and safety and compliance with the Commission's rules and regulations and with the conditions of your license. Within these areas, the inspection consisted of selected examination of procedures and representative records, observations of activities, and interviews with personnel. Based on the results of this inspection, the NRC has identified two findings that were evaluated for risk under the Significance Determination Process. Violations were associated with each of the findings. The attached report discusses a finding that was preliminarily determined to be a White finding, a finding with low-to-moderate increased safety significance which may require additional NRC inspections. This finding was assessed based on the best available information, including influential assumptions, using the applicable Significance Determination Process (SOP). As described in Section 1 R05.01 of the attached report, this finding involves the failure to verify that procedure steps to safely shutdown the plant in the event of a fire would actually reposition three motor operated valves to the required positions and the concurrent failure to address a previous finding that involved the same procedure steps. This finding has preliminary moderate safety significance because it involves llJultiple fire areas and risk factors that were not dependent on specific fire damage. The scenarios of concern involve larger fires in specific areas of the piant which trigger operators to implement fire response procedures to place the plant in a safe shutdown condition. Since performing some of those actions using the Nebraska Public Power District 2-procedures as not have aligned three valves to their required positions, this would challenge the operators' ability to establish adequate core cooling. This finding does not represent an immediate safety concern because your staff promptly changed the procedures to !ocally reposition position the valves. This finding is also an apparent violation of NRC requirements and is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy. The current Enforcement Policy is included on the NRC's web site at In accordance with Inspection Manual Chapter 0609, we intend to complete our evaluation using the best available information and issue our final determination of safety significance within 90 days of this letter. The significance determination process encourages an open dialog between the staff and the licensee; however the dialogue should not impact the timeliness of the staff's final determination. Before we make a final decision on this matter, we will hold a Regulatory Conference to provide you an opportunity to present to the NRC your perspectives on the facts and assumptions used by the NRC to arrive at the finding and assess its significance. The Regulatory Conference should be held within 30 days of the receipt of this letter and we encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. This Regulatory Conference will be open for public observation. At the Regulatory Conference, in addition to providing your perspectives on the finding and the significance, please be prepared to discuss (1) the cause(s) for the performance deficiency, (2) corrective actions taken or planned for the performance deficiency, and (3) the reasons why your corrective actions for Violation 05000298/2008008-01, a finding with low-to-moderate safety significance, were not adequate to verify that the procedure would have worked as intended. Please contact Neil O'Keefe at (817) 860-8137 within 10 days of receipt of this letter to schedule a date for the Regulatory Conference. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision. The final resolution of this matter will be conveyed in separate correspondence. Because the NRC has not made a final determination for this matter, no Notice of Violation is being issued for this inspection finding at this time. In addition, please be advised that the characterization of the apparent violation described in the enclosed inspection report may change as a result of further NRC review. Based on the results of this inspection, the NRC has also identified one additional issue that was evaluated under the risk significance determination process as having very low safety significance (Green). The finding was determined to involve a violation of NRC requirements. However, because it was entered into your corrective action program, the NRC is treating the finding as a noncited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy. The NCV is described in the subject inspection report. If you contest the noncited violation or the significance of the noncited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, A TIN: Document Control Desk, Washington DC 20555-0001, with copies to: (1) the Regional Administrator, Region IV; (2) the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and (3) the NRC Resident Inspector at Nebraska Public Power District -3 -Cooper Nuclear Station. addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at Cooper Nuclear Station. The information you provide wil! be considered in accordance with Inspection Manual Chapter 0305. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure(s), and your response, if you choose to provide one, will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's document system (ADAMS), accessible from the NRC Web site at To the extent possible, your response should not include any personal privacy or proprietary, information so that it can be made available to the Public without redaction. Docket No. 50-298 License No. DPR-46
This Errata corrects the tracking numbers and a title for the violations in the subject report issued by our letter (ML110760579) (A. Vegel to B. O'Grady, dated March 17, 2011). Please replace Page 18 of the Enclosure and Page A-2 of Attachment 1 with the enclosed revised pages. We regret any inconvenience this may have caused. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure(s), and your response, if you choose to provide one, will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html.


Sincerely,Anton Vegel, Division of Reactor Safety  
Sincerely,/RA/ Neil F. O'Keefe, Chief Engineering Branch 2 Division of Reactor Safety Docket No. 50-298 License No. DPR-46


===Enclosure:===
===Enclosure:===
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===w/Attachments:===
===w/Attachments:===
Supplemental Information Final Significance Determination Summary cc w/enclosure: Distribution via ListServ for CNS Docket: License: Report Nos.: Licensee: Facility: Location: Dates: Team Leader: Inspectors: Approved By: U 50-298 DPR-46 05000298/2010006 Nebraska Public Power District Cooper Nuclear Station 72676 648A Avenue Brownville, NE 68321 COMMISSION October 18, 2010 through March 14, 2011 J. Mateychick, Senior Reactor Inspector, Engineering Branch 2 S. Alferink, Reactor Inspector, Engineering Branch 2 E. Uribe, Reactor Inspector, Engineering Branch 2 J. Watkins, Reactor Inspector, Engineering Branch 2 G. George, Reactor Inspector, Engineering Branch 1 Anton Vegel, Director n;\I;",jnn nf RQ<:>f'tnr <::<:>fQt\l 1-01'1 v IVlVI I VI 1' ...... c..tVLVI "-'''-Alw''] -1 -Enclosure
Supplemental Information Final Significance Determination Summary cc w/enclosure: Distribution via ListServ for CNS Nebraska Public Power District - 2 - Electronic distribution by RIV: Regional Administrator (Elmo.Collins@nrc.gov) Deputy Regional Administrator (Art.Howell@nrc.gov) DRP Director (Kriss.Kennedy@nrc.gov) DRP Deputy Director (Troy.Pruett@nrc.gov) DRS Director (Anton.Vegel@nrc.gov) DRS Deputy Director (Vacant) Senior Resident Inspector (Jeffrey.Josey@nrc.gov) Resident Inspector (Michael.Chambers@nrc.gov) Branch Chief, DRP/C (Vincent.Gaddy@nrc.gov) Senior Project Engineer, DRP/C (Bob.Hagar@nrc.gov) Project Engineer, DRP/C (Rayomand.Kumana@nrc.gov) CNS Administrative Assistant (Amy.Elam@nrc.gov) Public Affairs Officer (Victor.Dricks@nrc.gov) Public Affairs Officer (Lara.Uselding@nrc.gov) Project Manager (Lynnea.Wilkins@nrc.gov) Branch Chief, DRS/TSB (Michael.Hay@nrc.gov) RITS Coordinator (Marisa.Herrera@nrc.gov) Regional Counsel (Karla.Fuller@nrc.gov) Congressional Affairs Officer (Jenny.Weil@nrc.gov) RES Branch Chief (MarkHenry.Salley@nrc.gov) OEMail Resource@nrc.gov OEWEB Resource OEDO RIV Coordinator (Nathan.Sanfilippo@nrc.gov) DRS/TSB STA (Dale.Powers@nrc.gov) R:\ ADAMS ML ADAMS: No Yes SUNSI Review Complete Reviewer Initials: NFO Publicly Available Non-Sensitive Non-publicly Available Sensitive RIV/DRS/EB2 RIV/DRS/BC J.Mateychick N. O'Keefe /RA/ /RA/ 3/23/11 3/26/11 OFFICIAL RECORD COPY  T=Telephone E=E-mail F=Fax
 
-18- Enclosure The licensee entered this issue into their corrective action program as Condition Reports CR-CNS-2010-08014 and CR-CNS-2010-08250. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program, this violation is being treated as a noncited violation, consistent with the Enforcement Policy: NCV 05000298/2010006-02, Failure to Monitor the Performance of the Emergency Lights Against the Maintenance Rule Criteria. .9 Cold Shutdown Repairs a. Inspection Scope The team verified that the licensee identified repairs needed to reach and maintain cold shutdown and had dedicated repair procedures, equipment, and materials to accomplish these repairs. Using these procedures, the team evaluated whether these components could be repaired in time to bring the plant to cold shutdown within the time frames specified in the design and licensing bases. The team verified that the repair equipment, components, tools, and materials needed for the repairs were available and accessible on site. b. Findings No findings were identified. .10 Compensatory Measures a. Inspection Scope The team verified that compensatory measures were implemented for out-of-service, degraded, or inoperable fire protection and postfire safe shutdown equipment, systems, or features (e.g., detection and suppression systems and equipment; passive fire barriers; or pumps, valves, or electrical devices providing safe shutdown functions). The team also verified that the short-term compensatory measures compensated for the degraded function or feature until appropriate corrective action could be taken and that the licensee was effective in returning the equipment to service in a reasonable period of time. b. Findings A finding related to this review was documented in Section 1R05.01. No additional findings were identified. .11 B.5.b Inspection Activities a. Inspection Scope The team reviewed the licensee's implementation of guidance and strategies intended to maintain or restore core, containment, and spent fuel pool cooling capabilities under the circumstances associated with loss of large areas of the plant due to explosions or fire as required by Section B.5.b of the Interim Compensatory Measures Order, EA-02-026, dated February 25, 2002 and 10 CFR 50.54(hh)(2).
=SUMMARY=
IR 05000298/2010006; October 18,2010 -March 14, 2011, Nebraska Public Power District; Cooper Nuclear Station: Triennial Fire Protection Team Inspection. This report covers a two week fire protection team inspection, follow-up inspection and significance determination effort by specialist inspectors from Region IV. One finding was identified with an associated apparent violation, vvhich was preliminary determined to have to-moderate safety significance (White). Two Green findings, which were noncited violations (NCVs), were also identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 0609, "Significance Determination Process." Findings for which the significance determination process (SOP) does not apply may be Green or be assigned a severity level after NRC management review. The crosscutting aspects, where applicable, were determined using Inspection Manual Chapter 0310, "Components Within the Cross Cutting Areas." The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.
 
===A. NRC-Identified and Self-Revealing Findings===
 
===Cornerstone: Mitigating Systems .. Apparent Violation. An apparent violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," and Criterion XVI, "Corrective Action," with a preliminary white significance, was identified for failure to ensure that some steps contained in Emergency Procedures at Cooper Nuclear Station would work as written and the concurrent failure to assure that a condition adverse to quality was promptly identified and corrected, respectively. Specifically, steps in Emergency Procedure 5.4 POST-FIRE, "Post-Fire Operational Information," and Emergency Procedure 5.4 FIRE-SID, "Fire Induced Shutdown From Outside Control Room," intended to reposition motor operated valves from the motor starter cabinet, would not have worked as written because the steps were not appropriate for the configuration of three valve motor starters. This finding was entered into the licensee's corrective action program under Condition Reports CR-CNS-201 0-08193 and CR-CNS-2010-08242, however the licensee failed to adequately correct the procedure and the procedure remained unworkabie. The failure to verify that procedure steps needed to safely shutdown the plant in the event of a fire would actually reposition motor operated valves to the required positions and the simultaneous failure to address the previous finding that the same procedure steps would not work as written, was a performance deficiency. This finding was more than minor safety significance because it impacted the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to external events (such as fire) to prevent undesirable consequences. This finding affected both the procedure quality and protection against external factors (such as fires) attributes of this cornerstone objective. This finding was determined to have a preliminary lovv-to-moderate safety significance (===
White) during a Phase 3 evaluation using best available information. This problem, which has existed since 1997, involves risk factors that were not dependent on specific fire damage. The scenarios of concern involve larger fires in specific areas of the plant which trigger operators to implement fire response procedures to place the plant in a safe shutdown condition. Since some of those actions could not be completed using the procedures as written, this would challenge the operators' ability to establish adequate core cooling. This finding had a crosscutting aspect in the Corrective Action Program component, under the Problem Identification and Resolution area (P.1 (c) -Evaluation), because the licensee failed to properly evaluate the circuit operation or conduct verification tests to ensure that corrective actions for a previous violation would reliably position the three valves. Upon identification of this issue, both emergency procedures were revised to assure correct valve alignment by manually operating the valve locally. Therefore, this finding does not represent a current safety concern. (Section 1 R05.1)
: '''Green.'''
A noncited violation of 10 CFR 50.65(a)(2) was identified for the failure to monitor the performance of the emergency lighting system against the established performance criteria. The licensee included the emergency lighting system in the Maintenance Rule program and specified that the emergency light batteries must be capable of 8 hours of operation, as required by 10 CFR Part 50, Appendix R, Section iii.J. The team identified that the licensee did not perform tests that demonstrated the capability of the emergency lights to last for 8 hours; therefore, the licensee failed to monitor the performance of the emergency lights against the established performance criteria. This finding was entered into the licensee's corrective action program under Condition Reports CR-CNS-201 0-08014 and CR-CNS-2010-08250. The failure to monitor the performance of the emergency lighting system against the performance criteria stated in the Maintenance Rule program was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to ensure that emergency lights would last for 8 hours could adversely affect the ability of operators to perform all of the manual actions required to support safe shutdown in the event of a fire. The significance of this finding was evaluated using Inspection Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," because the performance deficiency affected fire protection defense-in-depth strategies invoiving post fire safe shutdown systems. The finding was assigned a low degradation rating since the finding minimally impacted the performance and reliability of the fire protection program element. Specifically, the team determined that the licensee's preventive maintenance strategy provided reasonable assurance that the emergency lights would last sufficiently long for the operators to perform the most time-critical manual actions required to support safe shutdown in the event of a fire. The team also noted that operators were required to obtain and carry flashlights. Therefore, the finding screened as having very low safety significance (Green). This finding had a crosscutting aspect in the area of Human Performance associated with Decision Making because the licensee failed to identify possible unintended consequences of the decision to change the maintenance program for the emergency lights. Specifically, the licensee failed to identify that deleting light testing impacted (Section 1 R05.B)
 
===B. Licensee-Identified Violations===
None
 
=REPORT DETAILS=
i.
 
==REACTOR SAFETY==
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1 ROS Fire Protection (71111.0STTP) This report presents the results of a triennial fire protection inspection conducted in accordance with NRC Inspection Procedure 71111.0STTP, "Fire Protection-NFPA Transition Period (Triennial)," at Cooper Nuclear Station. The licensee committed to adopt a risk informed fire protection program in accordance with National Fire Protection Association Standard 80S (NFPA-80S), but had not yet completed the program transition. The inspection team evaluated the implementation of the approved fire protection program in selected risk-significant areas, with an emphasis on the procedures, equipment, fire barriers, and systems that ensure the post-fire capability to safely shut the plant down. Inspection Procedure 71111.0STTP requires selecting three to five fire areas for review. The inspection team used the fire hazards analysis section of the Cooper Nuclear Station Individual Plant Examination of External Events to select the following five risk-significant fire zones (inspection samples) for review:
* Fire Area I / Fire Zone 2A Control Rod Drive Units -North Reactor Building Elevation 903' 6"
* Fire Area I / Fire Zone SB Reactor Motor Generator Set Area Reactor Building Elevation 976' 0"
* Fire Area II I Fire Zone 3A Switchgear Room 1 F Reactor Building Elevation 931' 6"
* Fire Area IX / Fire Zones 14A Diesel Generator 1A Room Diesel Generator Building Elevation 903' 6"
* Fire Area IX / Fire Zones 14C Diesel Oil Day Tank Room Diesel Generator Building Elevation 903' 6" The inspection team evaluated the licensee's fire protection program using the applicable requirements, which included plant Technical Specifications, Operating License Condition 2.C.(S); NRC safety evaluations; 10 CFR S0.48; Branch Technical Position 9.S-1; and 10 CFR SO, Appendix R. The team also reviewed related documents that included the Final Safety Analysis Report (FSAR), Section 9.S; the fire hazards analysis; and the post-fire safe shutdown analysis. Specific documents reviewed by the team are listed in the attachment. Five fire area inspection samples were completed. Also, one B.S.b strategy review sample was completed. -S -Enclosure
 
===.1 Protection of Safe Shutdown Capabilities===
 
====a. Inspection Scope====
The team reviewed the piping and instrumentation diagrams, safe shutdown equipment list, safe shutdown design basis documents, and the post fire safe shutdown analysis to verify that the licensee properly identified the components and systems necessary to achieve and maintain safe shutdown conditions for fires in the selected fire areas. The team observed walkdowns of the procedures used for achieving and maintaining safe shutdown in the event of a fire to verify that the procedures properly implemented the safe shutdown analysis provisions. For each of the selected fire areas, the team reviewed the separation of redundant safe shutdown cables, equipment, and components located within the same fire area. The team also reviewed the licensee's method for meeting the requirements of 10 CFR 50.48; Branch Technical Position 9.5-1, Appendix A; and 10 CFR Part 50, Appendix R, Section III.G. Specifically, the team evaluated whether at least one post-fire safe shutdown success path would remain free of fire damage in the event of a fire. In addition, the team verified that the licensee met applicable license commitments.
 
====b. Findings====
 
=====Introduction.=====
An apparent violation of 10 CFR Part 50, Appendix B, Criterion Vand Criterion XVI, with a preliminary White significance, was identified for the repeated failure to ensure that some steps contained in emergency procedures at Cooper Nuclear Station would work as written. Specifically, steps in Emergency Procedure 5.4 FIRE, "Post Fire Operational Information," and Emergency Procedure 5.4 FIRE-SID, "Fire Induced Shutdown From Outside Control Room," intended to reposition motor operated valves at the motor starter cabinet, would not have worked as written because the steps were not appropriate for the configuration of the motor starters.
 
=====Description.=====
Post-fire safe shutdown strategies at the Cooper Nuclear Station require equipment operations to be performed in accordance with one of two emergency procedures. For most fire areas, plant shutdown is performed using Emergency Procedure 5.4 POST-FIRE, "Post-Fire Operational Information," Revision 37, in conjunction with other plant procedures. For areas where fires might necessitate evacuation of the control room, alternative shutdown is performed using Emergency Procedure 5.4 FIRE-SID, "Fire Induced Shutdown From Outside the Control Room," Revision 38. The team performed a walkthrough of Emergency Procedure 5.4 POST-FIRE for selected fire areas by observing plant operators simulate actions required by the procedure. This procedure required operators to reposition multiple motor-operated valves (MOVs) from each valve's motor starter cabinet. The procedure steps direct operators to open the motor starter cabinet, remove the control power fuses, then press designated contactors for a specified amount of time to reposition the valve to the required position. -6 -Enclosure The team was concerned that some of the procedure steps might not be reliably performed by the operators because bulky electrical safety gloves might not allow access to recessed contactors. When the licensee attempted to demonstrate their method, they identified that it would not work for one type of contactor. The internal configuration of the contactor would not complete the power circuit by depressing it. The manufacturer describes the design as having "direct magnet drive with positive pull-in of contactors." Since control power was removed by pulling fuses before operating the contactors, the magnet system would not engage the power contacts to the valve motor. The inspectors noted that the operator performing the procedure steps would have no indication that the valve(s) did not reposition. Because the procedures do not specifically require checking the valve positions for most fire locations, the failure to reposition would not be readily apparent. The three valves with this type of contactor were residual heat removal (RHR) system valves RHR-MO-25A and RHR-MO-25B, Train A and B Inboard Injection Isolation Valves, and reactor recirculation (RR) system valve RR-MO-53A, Reactor Recirculation A Pump Discharge Valve. The procedural deficiency in Emergency Procedure 5.4 POST-FIRE impacted the response to fires in 11 fire areas, each involving one valve. One of the valves, RHR-MO-25B, is operated in the same manner during alternative shutdown in accordance with Emergency Procedure 5.4 FIRE-SID, which contained the same procedural deficiency, for fires in two additional fire areas. The 13 affected fire areas are listed below: Fire Area CB-A CB-A-1 CB-B CB-C CB-D RB-DI (SE) RB-Di (SW) RB-FN RB-J RB-K RB-M RB-N TB-A Control Building Reactor Protection System Room 1A, Seal Water Pump Area, and Hallway Control Building Division 1 Switchgear Room and Battery Room Control Building Division 2 Switchgear Room and Battery Room Control Building Reactor Protection System Room 1 B Control Room, Cable Spreading Room, Cable Expansion Room, and Auxiliary Relay Room Reactor Building RHR Pump B/HPCI Pump Room Reactor Building South/Southwest 903, Southwest Quad 889 and 859, and RHR Heat Exchanger Room B Reactor Building 903, Northeast Corner Reactor Building Critical Switchgear Room 1 F Reactor Building Critical Switchgear Room 1 G Reactor Building North/Northwest 931 and RHR Heat Exchanger Room A Reactor Building South/Southwest 931 and RHR Heat Exchanger Room B Turbine Building (multiple areas) Opening either valve RHR-MO-25A or valve RHR-MO-25B is necessary to establish alternative shutdown cooling. Alternative shutdown cooling involves using a train of RHR to take suction from the suppression pool, inject the low pressure water to flood the reactor vessel, and recirculate the water through the safety relief valves (SRVs) back to the suppression pool. Establishing alternative shutdown cooling can be very sensitive. If high-pressure coolant injection (HPCI) is not available, the licensee -7 -Enclosure provided calculations that show that core damage can occur in as little as 15 minutes after valve RHR-MO-258 fails to open. Valve RR-MO-53A is the discharge isolation valve for Reactor Recirculation Pump 1-A. This valve is only required for cold shutdown. For some fire areas, the normal shutdown cooling mode of RHR system operation was credited in the fire safe shutdown analysis to be available. In shutdown cooling mode, the RHR system takes suction from the suction pipe of reactor recirculation system loop "A". The reactor coolant is then cooled and returned to a reactor recirculation loop discharge pipe. The failure to close either valve RR-MO-53A or RR-MO-43A would result in a short circuit of the shutdown cooling flow, bypassing the reactor vessel. The cool down from hot shutdown conditions and the transition to normal shutdown cooling allows time to close either valve RR-MO-53A or RR-MO-43A using local manual operation. In 2004, a related but separate violation (NCV 05000298/2004008-01) was issued for failure to protect cables from fire damage for MOVs required to be available for post fire safe shutdown. The licensee committed to adopt a risk-informed fire protection program in accordance with 10 CFR 50.48(c) and NFPA-805, and planned to address the 2004 violation through their NFPA-805 conversion. To be able to delay correcting the 2004 violation, the licensee was required to verify that the compensatory measures for the violation (the operator manual actions) were adequate to ensure safety, in this case to be able to safely shut the plant down in the event of a fire. Inspection Report 05000298/2004008 noted reliability concerns with the method of operating the MOVs. These included the fact that the contactors were not labeled to ailow operators to know which contactors the procedure instructed them to operate, no indication was available at the motor starter cabinet for the operator to know the valves had reached their required position, and valve position was not verified locally at the valves. As part of corrective action, the licensee installed "open" and "closed" labels near contactors in the motor starter cabinets. In 2007, inspectors identified that some of the operator manual actions used as compensatory measures for the 2004 violation would not have repositioned 10 of the MOVs. The procedures did not account for the fact that these 10 MOVs had different motor starter circuits than most valves. Despite installing labels following the 2004 violation, the licensee failed to recognize that these 10 MOVs had a more complex circuit design which required two or three contactors to be operated at the same time, while the procedures only required operating one "open" or one "close" contactor. A White finding with an associated violation (Violation 05000298/2008008-01, EA 07-204) was issued for having an inadequate procedure and failing to verify that the procedure would work. Inspection Report 05000298/2008007 again documented the reliability concerns that there were no valve position indications at the MOV motor starter cabinets, and the procedures did not direct local valve position checks. Additional reliability concerns were also documented concerning the adequacy of the procedures and the instrumentation available to diagnose the failure of an MOV to reposition. The licensee took corrective actions to change and verify the procedures to address the 2008 finding; however the licensee's efforts again failed to identify details of the -8 -Enclosure electrical design which would result in the procedure steps not repositioning three MOVs.
 
=====Analysis.=====
The failure to verify that procedure steps needed to safely shutdown the plant in the event of a fire would actually reposition motor operated valves to the required positions, and to address a previous finding that the same procedure steps would not work as written, was a performance deficiency. This performance deficiency is of more than minor safety significance because it impacted the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to external events (such as fire) to prevent undesirable consequences. This finding affected both the procedure quality and protection against external factors (such as fires) attributes of this cornerstone objective. The significance determination process (SOP) Phase 1 Screening Worksheet (Manual Chapter 0609, Attachment 4), Table 3b directs the user to Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," because it affected fire protection defense-in-depth strategies involving post fire safe shutdown systems. However, the Assumptions and Limitations section of Appendix F states that finings involving multiple fire areas are beyond the scope of Appendix F, and findings involving control room evacuation are not explicitly treated in Appendix F. Therefore, a Phase 3 analysis was performed. The license claimed that the issue involved a performance deficiency that only impacted cold shutdown, and therefore should be screened as Green during a Phase 1 SOP. The NRC concluded that this finding cannot be screened out because the complexity of the issue (e.g., multiple fire areas affected) precludes simple screening, and because the plant conditions and system dependencies prevent a conclusion that only cold shutdown is affected. Manual Chapter 0308 describes the basis for Appendix F screening out issues involving only cold shutdown as follows: The second question screens findings to green that impact only the ability of the plant to achieve cold shutdown. This is consistent with the common risk analysis practice of defining hot shutdown as success. That is, both fire PRAs [probabilistic risk assessments] and Internal Events PRAs typically assume that achieving a safe and stable hot shutdown state constitutes success and the end state for accident sequence analyses. Note that this screening step applies only to findings against 10CFR50 Appendix R, Section III.G.1.b. All other regulatory provisions are considered to involve, in part or in whole, measures provided for preservation and protection of the post-fire hot shutdown capability and will not be screened in this step (e.g., fire prevention, fire suppression, fire brigade, fire barriers, etc.). The licensee's fire safe shutdown strategy and implementing procedures for the scenarios of concern direct operators to proceed to cold shutdown within a few hours. Operation in hot shutdown and cold shutdown rely on the suppression pool with limited capability for cooling the suppression pool. This strategy is too complex to allow simple risk screening for this finding. -9-Enclosure A risk analysis was performed previously for the 2008 procedural problems that affected ten valves, including the three valves addressed by this performance deficiency. This was documented in Inspection Report 05000298/2008008 (EA 07-204). In both the 2008 and current cases, valves RHR-MOV-25A, RHR-MOV-25B, and RHR-MOV-53A were incapable of being remotely operated from the motor starter as prescribed by Procedures 5.4 POST-FIRE and 5.4 FIRE-SID. Therefore, the linked event tree model developed for the risk estimate performed in 2008 was used to assess the significance of the current issue for these three valves. Fires that do not require control room evacuation are addressed in Procedure 5.4 POST-FIRE. For fire areas that do not involve control room evacuation, the analyst concluded that the risk for the current finding is less than 1.0E-7 (this is unchanged from 2008 evaluation). The risk attributable to post fire remote shutdown (control room abandonment sequences) results predominantly from the failure of Valve RHR-MOV-25B to open as described in Procedure 5.4 FIRE-SID. This is the credited train and the only procedural means for initiating alternative shutdown cooling during the recovery actions. Changes were made to Procedure 5.4 FIRE-SID subsequent to the 2008 issue which were credited in the current analysis and resulted in a decrease in the risk significance of the subject valves. The non-recovery probability was decreased by a factor of 78 for the current finding because of changes that were made to Procedure 5.4 FIRE-SID. These changes in Attachment 1 of the procedure directed the operator at the remote shutdown panel to close SRVs if RHR injection was not observed to be successful and stabilize conditions using high pressure injection. Also, it directed operators to delay securing HPCI (if it was running) until RHR injection is confirmed. Additionally, Attachment 2 to the procedure directed the reactor building operator to open valve RHR-MOV-25B manually if the valve did not operate. However, there is limited instrumentation available at the remote shutdown panel to be able to recognize and diagnose that the valve did not open, and no available indications at the motor starter cabinet. Therefore, the operator who might be able to diagnose the failure of RHR-MO-25B did not have a procedure with the critical recovery step, and the operator with the correct recovery step in his procedure did not have the capability to know whether it was needed. Using the linked event tree model and a period of exposure of one year, the analyst calculated the f..CDF to be 2.0E-6/yr for postulated fires leading to the abandonment of the main control room. The analyst concluded that the performance deficiency was of low to moderate significance (White). A more detailed description to the Phase 3 analysis is attached to this report. The NRC expects that licensees will ensure that issues potentially impacting nuclear safety are promptly identified, fully evaluated, and that actions are taken to address safety issues in a timely manner, commensurate with their significance. Additionally, the NRC expects that for significant problems, licensees will conduct effectiveness reviews of corrective actions to ensure that the problems are resolved. Because the licensee -10-Enclosure failed to properly evaluate the circuit operation or conduct verification tests to ensure that corrective actions for a previous violation would reliably position the three valves, the team concluded that this finding has a crosscutting aspect in the Corrective Action Program component, under the Problem Identification and Resolution area (P.1 (c) -Evaluation).
 
=====Enforcement.=====
Title 10 of the Code of Federal Regulations, Part 50, Appendix S, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Title 10 of the Code of Federal Regulations, Part 50, Appendix S, Criterion XVI requires, in part: Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. In the case of Significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Emergency Procedure 5.4 POST-FIRE, "Post-Fire Operational Information," Revision 37, and Emergency Procedure 5.4 FIRE-SID, "Fire Induced Shutdown From Outside the Control Room," Revision 38, were designated as quality-related procedures used to implement operator actions to safely shutdown the plant in response to a fire. Violation 05000298/2008008-01 (EA 07-204) documented a significant condition adverse to quality in that steps in Emergency Procedure 5.4 POST-FIRE and Emergency Procedure 5.4 FIRE-SID would not achieve and maintain a safe shutdown condition in the event of certain fires. Contrary to the above, between July 1997 and November, 2010, the licensee failed to ensure that activities affecting quality were prescribed by documented procedures appropriate to the circumstances, and to assure that a significant condition adverse to quality was promptly corrected. Specifically, Emergency Procedure 5.4 POST-FIRE and Emergency Procedure 5.4 FIRE-SID were changed in 1997 to add steps that were inappropriate to the circumstances because they would not work as written to reposition three motor operated valves needed to establish core cooling. The licensee failed to properly verify and validate procedure steps when the procedure changes were made and on multiple occasions between July 1997 and November 2010, including verification and validation actions performed in response to Violation 05000298/2008008-01 .. In addition, contrary to the above, between July 2008 and November 2010, the licensee failed to identify, correct, and preclude repetition of a Significant condition adverse to quality. Specifically, Violation 05000298/2008008-01 identified a significant condition adverse to quality in that Emergency Procedure 5.4 POST-FIRE and Emergency Procedure 5.4 FIRE-SID would not work as written and the licensee had failed to verify and validate procedure steps to ensure that they would work to accomplish the necessary tasks. While addressing that violation, the licensee failed to perform sufficient -11 -Enclosure circuits to identify and correct a problem with valves RHR-MOV-25A, RHR-MOV-25B, and RHR-MOV-53A. The licensee entered this issue into their corrective action program as Condition Reports CR-CNS-2010-08193 and CR-CNS-2010-08242. This violation is being treated as an apparent violation (AV) , consistent with the Enforcement Policy: AV 05000298/2010006-01, Inadequate Post-Fire Safe Shutdown Procedures. Because the licensee failed to correct this condition as part of Violation 05000298/2008008-01, and because Violation 05000298/2008008-01 did not receive enforcement discretion, this finding was not appropriate for enforcement discretion . . 2 Passive Fire Protection
 
====a. Inspection Scope====
The team walked down accessible portions of the selected fire areas to observe the material condition and configuration of the installed fire area boundaries (including walls, fire doors, and fire dampers) and verify that the electrical raceway fire barriers were appropriate for the fire hazards in the area. The team compared the installed configurations to the approved construction details, supporting fire tests, and applicable license commitments. The team reviewed installation, repair, and qualification records for a sample of penetration seals to ensure that the fill material possessed an appropriate fire rating and that the installation met the engineering design. The team also reviewed similar records for the rated fire wraps to ensure the material possessed an appropriate fire rating and that the installation met the engineering design.
 
====b. Findings====
No findings were identified . . 3 Active Fire Protection
 
====a. Inspection Scope====
The team reviewed the design, maintenance, testing, and operation of the fire detection and suppression systems in the selected fire areas. The team verified that the manual and automatic detection and suppression systems were installed, tested, and maintained in accordance with the National Fire Protection Association code of record or approved deviations, and that each suppression system was appropriate for the hazards in the selected fire areas. The team performed a walkdown of accessible portions of the detection and suppression systems in the selected fire areas. The team also performed a walkdown of major system support equipment in other areas (e.g., fire pumps) to assess the material condition of these systems and components. The team reviewed the electric and diesel fire pump flow and pressure tests to verify that -12 -Enclosure the pumps met their design requirements. The team also reviewed high pressure carbon dioxide suppression system functional tests and inspections to verify that the system capability met the design requirements. The team assessed the fire brigade capabilities by reviewing training, qualification, and drill critique records. The team also reviewed pre-fire plans and smoke removal plans for the selected fire areas to determine if appropriate information was provided to fire brigade members and plant operators to identify safe shutdown equipment and instrumentation, and to facilitate suppression of a fire that could impact post-fire safe shutdown capability. In addition, the team inspected fire brigade equipment to determine operational readiness for fire fighting. The team observed an unannounced fire drill, conducted on November 1, 2010, and the subsequent drill critique using the guidance contained in Inspection Procedure 71111.05AQ, "Fire Protection Annual/Quarterly." The team observed fire brigade members fight a simulated fire in the Reactor Building, located in a switchgear room. The team verified that the licensee identified problems, openly discussed them in a self-critical manner at the drill debrief, and identified appropriate corrective actions. Specific attributes evaluated were: (1) proper wearing of turnout gear and self-contained breathing apparatus; (2) proper use and layout of fire hoses; (3) employment of appropriate fire fighting techniques; (4) sufficient fire fighting equipment was brought to the scene; (5) effectiveness of fire brigade leader communications, command, and control; (6) search for victims and propagation of the fire into other areas; (7) smoke removal operations; (8) utilization of pre-planned strategies; (9) adherence to the planned drill scenario; and (10) drill objectives.
 
====b. Findings====
No findings were identified .
 
===.4 Protection From Damage From Fire Suppression Activities===
 
====a. Inspection Scope====
The team performed plant walkdowns and document reviews to verify that redundant trains of systems required for hot shutdown, which are located in the same fire area, would not be subject to damage from fire suppression activities or from the rupture or inadvertent operation of fire suppression systems. Specifically, the team verified that:
* A fire in one of the selected fire areas would not directly, through production of smoke, heat, or hot gases, cause activation of suppression systems that could potentially damage all redundant safe shutdown trains.
* A fire in one of the selected fire areas or the inadvertent actuation or rupture of a fire suppression system would not directly cause damage to all redundant trains.
* Adequate drainage was provided in areas protected by water suppression systems.
 
====b. Findings====
-13 -Enclosure No findings were identified, ,5 Alternative Shutdown Capability a, Inspection Scope Review of Methodology The team reviewed the safe shutdown analysis, operating procedures, piping and instrumentation drawings, electrical drawings, the Final Safety Analysis Report, and other supporting documents to verify that hot and cold shutdown could be achieved and maintained from outside the control room for fires that require evacuation of the control room, with or without offsite power available, Plant walkdowns were conducted to verify that the plant configuration was consistent with the description contained in the safe shutdown and fire hazards analyses, The team focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor decay heat removal, process monitoring instrumentation, and support systems functions. The team also verified that the systems and components credited for shutdown would remain free from fire damage. Finally, the team verified that the transfer of control from the control room to the alternative shutdown location would not be affected by fire-induced circuit faults (e.g., by the provision of separate fuses and power supplies for alternative shutdown controi circuits). Review of Operational Implementation The team verified that licensed and non-licensed operators received training on alternative shutdown procedures. The team also verified that sufficient personnel to perform a safe shutdown were trained and available onsite at all times, exclusive of those assigned as fire brigade members. A walkthrough of the post fire safe shutdown procedure with licensed and non-licensed operators was performed to determine the adequacy of the procedure, The team verified that the operators could be reasonably expected to perform specific actions within the time required to maintain plant parameters within specified limits. Time critical actions that were verified included restoring electrical power, establishing control at the remote shutdown and local shutdown panels, establishing reactor coolant makeup, and establishing decay heat removal. The team reviewed manual actions to ensure that they had been properly reviewed and approved and that the actions could be implemented in accordance with plant procedures in the time necessary to support the safe shutdown method for each fire area. The team also reviewed the periodic testing of the alternative shutdown transfer capability and instrumentation and control functions to verify that the tests are adequate to demonstrate the functionality of the alternative shutdown capability, -14 -Enclosure
 
===.6 b.===
 
====a. Findings====
No findings were identified. Circuit Analysis I nSl2ection SCOl2e This segment of inspection is suspended for plants in transition to a risk-informed fire protection program in accordance with NFPA 805. Therefore, the team did not evaluate this area.
 
====b. Findings====
No findings were identified . . 7 Communications
 
===.8 a. Insl2ection Scol2e===
b. a. The team inspected the contents of designated emergency storage lockers and reviewed the alternative shutdown procedure to verify that portable radio communications and fixed emergency communications systems were available, operable, and adequate for the performance of designated activities. The team verified the capability of the communication systems to support the operators in the conduct and coordination of their required actions. The team also verified that the design and location of communications equipment such as repeaters and transmitters would not cause a loss of communications during a fire. The team discussed system design, testing, and maintenance with the system engineer. The team reviewed the licensee's response to Condition Report CR-CNS-201 0-07848. The team verified the licensee properly implemented the Maintenance Rule program with respect to the communications systems required for alternative shutdown. Findings No findings were identified. Emergency Lighting Insl2ection Scol2e The team reviewed the portion of the emergency lighting system required for alternative shutdown to verify that it was adequate to support the performance of manual actions required to achieve and maintain hot shutdown conditions and to illuminate access and egress routes to the areas where manual actions would be required. The team evaluated the locations and positioning of the emergency lights during a walkthrough of the alternative shutdown procedure. -15 -Enclosure The team verified that the licensee installed emergency lights with an 8-hour capacity, maintained the emergency light batteries in accordance with manufacturer recommendations, and tested and performed maintenance in accordance with piant procedures and industry practices. The team also verified the licensee properly implemented the Maintenance Rule program with respect to the emergency lighting systems required for alternative shutdown. The team identified several concerns with the adequacy of the emergency lights during the walkthrough of the alternative shutdown procedure. In response to these concerns, the licensee performed blackout tests to demonstrate the adequacy of the installed emergency lights. The team observed blackout tests in the following areas:
* Control Building Corridor, 903' Elevation
* Control Building Basement, 881' Elevation
* Diesel Generator 2 Room
 
====b. Findings====
 
=====Introduction.=====
The team identified a Green noncited violation of 10 CFR 50.65(a)(2) for the failure to monitor the performance of the emergency lighting system against the established performance criteria.
 
=====Description.=====
During the inspection, the team reviewed the licensee's maintenance program for the emergency lighting system. The team determined that the licensee did not perform tests that demonstrated the capability of the emergency lights to last 8 hours. Instead, the licensee replaced each emergency light battery at a prescribed frequency. The licensee previously demonstrated the capability of the emergency lights to last 8 hours via the performance of internal resistance measurements. In 2008, the licensee modified their maintenance program to remove the internal resistance measurements and rely upon the prescribed replacement strategy. The team also reviewed the licensee's implementation of their Maintenance Rule program with respect to the emergency lighting system. The licensee included the emergency lighting system into the Maintenance Rule program and included a performance criterion for the emergency light batteries to support 8-hours of operation, as required by 10 CFR Part 50, Appendix R, Section III.J. Since the licensee did not perform tests that demonstrated the capability of the emergency lights to last 8 hours, the team determined that the licensee failed to monitor the performance of the emergency lights against the established performance criteria.
 
=====Analysis.=====
The failure to monitor the performance of the emergency lighting system against the performance criteria stated in the Maintenance Rule program was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure of the emergency lights to last 8 hours could adversely affect the ability of operators to perform the manual actions required to support safe shutdown in the event of a fire. -16 -Enclosure The significance of this finding was evaluated using Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," because the performance deficiency affected fire protection defense-in-depth strategies involving post-fire safe shutdown systems. The team assigned the performance deficiency to the Post-fire Safe Shutdown category since it affected systems or functions relied upon for post-fire safe shutdown. The finding was assigned a low degradation rating since the finding minimally impacted the performance and reliability of the fire protection program element. Specifically, the team determined that the licensee's preventive maintenance strategy provided reasonable assurance that the emergency lights would last sufficiently long for the operators to perform the most time critical manual actions required to support safe shutdown in the event of a fire. The team also noted that operators were required to obtain and carry flashlights. Therefore, the finding screened as having very low safety significance (Green). The NRC expects that licensee decisions demonstrate that nuclear safety is an overriding priority and to conduct effectiveness reviews of safety-significant decisions to identify possible unintended consequences. Because the licensee failed to identify that deleting emergency light testing impacted Maintenance Rule performance monitoring, the team concluded that this finding had a crosscutting aspect in the area of human performance associated with decision making. Specifically, the licensee failed to identify possible unintended consequences of the decision to change the maintenance program for the emergency lights. [H.1 (b)]
 
=====Enforcement.=====
Title 10 of the Code of Federal Regulations, Part 50, Section 65, Paragraph (a)(1), requires, in part, that licensees shall monitor the performance or conditions of structures, systems, or components (SSCs) within the scope of the maintenance rule as defined by 10 CFR 50.65 (b), against licensee established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions. Title 10 of the Code of Federal Regulations, Part 50, Section 65, Paragraph (a)(2) states, in part, that monitoring as specified in 10 CFR 50.65 (a)(1) is not required where it has been demonstrated that the performance or condition of a SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function. The licensee's Maintenance Rule program included the emergency lighting system and established a performance criterion that the emergency lighting system batteries support 8-hours of operation, as required by 10 CFR Part 50, Appendix R, Section IILJ. Contrary to the above, from October 3, 2008 to November 5, 2010, the licensee failed to demonstrate that the performance of the emergency lighting system was effectively controlled through the performance of appropriate preventive maintenance and did not smonitor the emergency lighting system against licensee established goals. Specifically, the licensee failed to demonstrate that the emergency lighting system remained capable of providing 8 hours of illumination for post-fire safe shutdown. -17 -Enclosure The licensee entered this issue into their corrective action program as Condition Reports CR-CNS-2010-08014 and CR-CNS-2010-08250. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program, this violation is being treated as a noncited violation, consistent with the Enforcement Policy: NCV 05000298/2010006-03, Failure to Monitor the Performance of the Emergency Lights Against the Maintenance Rule Criteria . . 9 Cold Shutdown Repairs
 
====a. Inspection Scope====
The team verified that the licensee identified repairs needed to reach and maintain cold shutdown and had dedicated repair procedures, equipment, and materials to accomplish these repairs. Using these procedures, the team evaluated whether these components could be repaired in time to bring the plant to cold shutdown within the time frames specified in the design and licensing bases. The team verified that the repair equipment, components, tools, and materials needed for the repairs were available and accessible on site.
 
====b. Findings====
No findings were identified . . 10 Compensatory Measures
 
====a. Inspection Scope====
The team verified that compensatory measures were implemented for out-of-service, degraded, or inoperable fire protection and postfire safe shutdown equipment, systems, or features (e.g., detection and suppression systems and equipment; passive fire barriers; or pumps, valves, or electrical devices providing safe shutdown functions). The team also verified that the short-term compensatory measures compensated for the degraded function or feature until appropriate corrective action could be taken and that the licensee was effective in returning the equipment to service in a reasonable period of time.
 
====b. Findings====
A finding related to this review was documented in Section 1 R05.01. No additional findings were identified . . 11 B.5.b Inspection Activities
 
====a. Inspection Scope====
The team reviewed the licensee's implementation of guidance and strategies intended to maintain or restore core, containment, and spent fuel pool cooling capabilities under the circumstances associated with loss of large areas of the plant due to explosions or fire as required by Section B.5.b of the Interim Compensatory Measures Order, EA-02-026, dated February 25: 2002 and 10 CFR 50.54(hh)(2). -18 -Enclosure The team reviewed a licensee's strategy to verify that they continued to maintain and implement procedures, maintain and test equipment necessary to properly implement the strategy, and to ensure that station personnel are knowledgeable and capable of implementing the procedure. The team performed a visual inspection of portable equipment used to implement the strategy to ensure availability and material readiness of the equipment, including the adequacy of portable pump trailer hitch attachments, and verify the availability of onsite vehicles capable of towing the portable pump. The team assessed the offsite ability to obtain fuel for the portable pump, and foam used for firefighting efforts. The team reviewed the following strategy as an inspection sample:
* 5.3 Alt-Strategy, "Alternative Core Cooling Mitigating Strategies," Revision 023, Attachment 4, "Manual Operation of RCIC [reactor core isolation cooling]."
 
====b. Findings====
No findings were identified.
 
==OTHER ACTIVITIES==
[OA] 40A2 Identification and Resolution of Problems Corrective Actions for Fire Protection Deficiencies
 
====a. Inspection Scope====
The team selected a sample of condition reports associated with the licensee's fire protection program to verify that the licensee had an appropriate threshold for identifying deficiencies. In addition, the team reviewed the corrective actions proposed and imolemented to verifv that thev were effective in correctina irlentifierl rlefir.ienr.ie!=: The * " ------.-----_. --. _. ---. -----'.;;I -_. -** _ *.* ----** _. _ ** _. --* * ** --team also evaluated the quality of recent engineering evaluations through a review of condition reports, calculations, and other documents during the inspection.
 
====b. Findings====
Findings related to this review are documented in Sections 1 R05.01 and 1 R05.05. No additional findings were identified. -19 -Enclosure 40A6 Meetings, Including Exit Exit Meeting Summary The team presented the inspection results to Mr. D. Willis, General Manager, Plant Operations, and other members of the licensee staff at a debrief meeting on November 5, 2010. The licensee acknowledged the findings presented. The team presented the inspection results to Mr. D. Suman, Director of Engineering, and other members of the licensee staff at an exit meeting on March 14, 2011. The licensee acknowledged the findings presented. The inspectors confirmed that proprietary material examined during the inspection had been returned. ATTACHMENTS:
 
=SUPPLEMENTAL INFORMATION=
 
==KEY POINTS OF CONTACT==
licensee Personnel
: [[contact::J. Aldana]], Security Coordinator
: [[contact::R. Alexander]], Electrical Superintendent
: [[contact::J. Austin]], System Engineering Manager 1. Barker, Quality Assurance Manager
: [[contact::J. Bebb]], Security Manager
: [[contact::S. Bebb]], Administrative Services Manager
: [[contact::M. Bergmeier]], Operation Support Group Supervisor
: [[contact::K. Billesbach]], Materials, Purchasing and Contracts Manager
: [[contact::D. Buman]], Director of Engineering
: [[contact::K. Cardy]], Fire Protection Engineer
: [[contact::G. Chinn]], Contractor
: [[contact::L. Deuhirst]], Corrective Actions and Assessments Manager
: [[contact::R. Dyer]], Engineering Support Program Engineer
: [[contact::J. Dykstra]], Electrical Engineering Program Supervisor
: [[contact::R. Estrada]], Design Engineering Manager
: [[contact::J. Flaherty]], Senior Staff licensing Engineer J Gage, Reactor Operator
: [[contact::R. Gauchat]], Security Training Supervisor 1. Hattovy, Engineering Support Manager
: [[contact::D. Jones]], Safety Coordinator 1. Kahland, Reactor Operator
: [[contact::C. Long]], Engineering Specialist
: [[contact::D. McGargill]], Non-licensed Operator 1. Mue!!er, Senior Reactor Operator
: [[contact::K. Newcomb]], Fire Marshal
: [[contact::D. Oshlo]], Information Technology Manager
: [[contact::R. Penfield]], Operations Manager
: [[contact::D. Seylock]], Training Manager
: [[contact::J. Shrader]], Fire Safety Lead, Nebraska Public Power District
: [[contact::D. Van Der Kap]], licensing Manager
: [[contact::M. Van Winkle]], Electrical Design Supervisor
: [[contact::D. Weniger]], Valves Program Engineer
: [[contact::D. Willis]], General Manager, Plant Operations
: [[contact::A. Zaremba]], Director of Nuclear Safety Assessment
===NRC personnel===
: [[contact::M. Chambers]], Resident Inspector
: [[contact::S. Vaughn]], NRR/DIRS/IPAB
: [[contact::J. Bowen]], NRR/DIRS/IRIB
: [[contact::D. Loveless]], Senior Reactor Analyst, RIV/DRS
: [[contact::M. Runyan]], Senior Reactor Analyst, RIV/DRS A-1 Attachment 1
UST OF
==ITEMS OPENED, CLOSED, AND DISCUSSED==
 
===Opened===
: 05000298/2009006-01 AV Inadequate Post-Fire Safe Shutdown Procedures (Section 1 R05.01)  
===Opened and Closed===
: 05000298/2009006-02 NCV Failure to Correct a Condition Adverse to Quality Related to Post-Fire Safe Shutdown Closed ADAMS BWR CR CFR DRS FSAR HPCi LPSI MOV NCV NFPA NRC PAR PRA RCIC RHR SDP SRV (Section 1 R05.05) None UST OF ACRONYMS Agencywide Documents Access and Management System Boiling Water Reactor Condition Report Code of Federal Regulations Division of Reactor Safety Final Safety Analysis Report High Pressure Coolant Injection Low Pressure Safety Injection Motor Operated Valve Noncited Violation National Fire Protection Association Nuclear Regulatory Commission Publicly Available Records Probabilistic Risk Assessment Reactor Core Isolation Cooling Residu'al Heat Removal Significance Determination Process Safety/Relief Valve A-2 Attachment 1 


==LIST OF DOCUMENTS REVIEWED==
- A-2 - Attachment 1 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 05000298/2010006-01 AV Inadequate Post-Fire Safe Shutdown Procedures (Section 1R05.1) Opened and Closed 05000298/2010006-02 NCV Failure to Monitor the Performance of the Emergency Lights Against the Maintenance Rule Criteria (Section 1R05.8) Closed None LIST OF ACRONYMS ADAMS Agencywide Documents Access and Management System BWR Boiling Water Reactor CR Condition Report CFR Code of Federal Regulations DRS Division of Reactor Safety FSAR Final Safety Analysis Report HPCI High Pressure Coolant Injection LPSI Low Pressure Safety Injection MOV Motor Operated Valve NCV Noncited Violation NFPA National Fire Protection Association NRC Nuclear Regulatory Commission PAR Publicly Available Records PRA Probabilistic Risk Assessment RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal SDP Significance Determination Process SRV Safety/Relief Valve
CALCULATIONS Number Title Revision NEDC 01-030 HPCI Room Heatup During Appendix R Shutdown from 2 Alternative Shutdown Panel NEDC 09-080 Multiple Spurious Operation Expert Panel Results 0 NEDC 85-081 Pressure Drop in Steam Line to the HPCI Turbine OCi NEDC 94-034H Containment Analysis for Appendix R -Shutdown from 2 Alternative Shutdown Room NEDC 95-003 Determination of Allowable Operating Parameters for 23 CNS MOV Program MOVs CONDITION REPORTS (CRs)
: CR-CNS-2004-03595
: CR-CNS-2004-05511
: CR-CNS-2006-03138
: CR-CNS-2007 -01248
: CR-CNS-2007 -04155
: CR-CNS-2007 -07065 C R -C N S-2008-05653
: CR-CNS-2008-5751
: CR-CNS-2008-05766
: CR-CNS-2007 -08253
: CR-CNS-2010-02387
: CR-CNS-2010-03500
: CR-CNS-2010-05023
: CR-CNS-2010-05269
: CR-CNS-2010-05855
: CR-CNS-2010-05856
: CR-CNS-2010-06942
: CR-CNS-2010-06184
: CR-CNS-2010-06236
: CR-CNS-2010-06245
: CR-CNS-2010-06258
: CR-CNS-2010-06264
: CR-CNS-2010-06441
: CR-CNS-2010-06775
: CR-CNS-2010-06942
: CR-CNS-201 0-0701 0
: CR-CNS-2010-07527
: CR-CNS-2010-07527
: CR-CNS-2010-07553
: CR-CNS-2010-07553
: CR-CNS-2010-07757*
: CR-CNS-2010-07762*
: CR-CNS-2010-07776*
: CR-CNS-2010-07803*
: CR-CNS-2010-07813*
: CR-CNS-2010-07823*
: CR-CNS-201 0-07831 *
: CR-CNS-2010-07839*
: CR-CNS-2010-07847*
: CR-CNS-2010-07848*
: CR-CNS-2010-07857*
: CR-CNS-2010-07859*
: CR-CNS-201 0-07861 *
: CR-CNS-201 0-07914 *
: CR-CNS-2010-08163*
: CR-CNS-2010-08165*
: CR-CNS-2010-08166*
: CR-CNS-2010-08167* I
: CR-CNS-201 0-08201 * I
: CR-CNS-201 0-08221 * I
: CR-CNS-2010-08250* A-3 Attachment 1 
[
: CR-CNS-2010-08253* * Condition Report initiated due to inspection activities. DRAWINGS Number Title Revision 14EK-0144 Diesel Engine Generator Schematic Diagram N22 85B-70008 Sheet Wiring Diagram
: WD-12, 13, & 14 F.v.R Starter
: NOO 159 0709-003 Ruskin Model NIBD23 3 Hour Type C -U.L. Labeled B Horizontal Fire Damper 1 X 1 0717-005 Ruskin Model NIBD23 3 Hour Type A -U.L. Labeled N01 Horizontal Fire Damper 00735-001 Ruskin Model NIBD23 3 Hour Type C -U.L. Labeled 0 Horizontal Fire Damper 1 X 1 Flow Diagram -Circulating, Screen Wash and Service I 2006 Sheet 1 Water Systems N76 2031 Sheet 2 Flow Diagram -Reactor Building -Closed Cooling N65 Water System 2036 Sheet 1 Flow Diagram -Reactor Building -Service Water N98 System 2038 Sheet 1 Flow Diagram, Reactor Buiding Floor & Roof Drain N49 Systems 2038 Sheet 2 Flow Diagram, Reactor Buiding Floor & Roof Drain N03 Systems 2040 Sheet 1 Flow Diagram -Residual Heat Removal System N80 2042 Flow Diagram -Reactor Building -Main Steam System N85 2045 Sheet 1 Flow Diagram -Core Spray System N58 2016 Sheet 1 C Flow Diagram -Fire Protection -Reactor Building N03 2016 Sheet 2 Fire Protection System -Flow Diagram For Pumphouse N30 and Storage Tanks 2016 Sheet 4 Halon and Cardox System Flow Diagram N04 2041 Reactor Building-Main Steam System-Cooper Nuclear N23 Station 2629-1 8"
: MS-1 & 10"
: MS-1 Main Steam N17 Auxiliary One Line Diagram Motor Control Center Z, 3002 Sheet 1 Switchgear Bus 1A, 1 B, 1 E, And Critical Switchgear N44 I Bus 1 F, And 1 G A-4 Attachment 1
: 3004 Sheet 3 Auxiliarl One Line Diagram Motor Control Center C, D, N22 H, J, DG1, And DG2 3012 Sheet 1 Main Three Line Diagram N08 I 3012 Sheet 2 Main Three Line Diagram N06 3012 Sheet 3 Main Three Line Diagram N19 3012 Sheet 4 Main Three Line Diagram N13 3012 Sheet 5 Main Three Line Diagram N15 3012 Sheet 6 Main Three Line Diagram N17 3012 Sheet 7 Main Three Line Diagram N08 3012 Sheet 8 Main Three Line Diagram N07 3012 Sheet 8a Main Three Line Diagram N05 3012 Sheet 9 Main Three Line Diagram N09 3012 Sheet 10 Main Three Line Diagram N11 I 3012 Sheet 12 Electrode Boiler Switchgear Main Three Line Diagram N03 3019 Sheet 3 4160V Switchgear Elementary Diagrams N36 3020 Sheet 4 4160V Switchgear Elementary Diagrams N20 3020 Sheet 8 4160V Switchgear Elementary Diagrams N32 3020 Sheet 9 4160V Switchgear Elementary Diagrams N22 3020 Sheet 4 4160V Switchgear Elementary Diagrams N20 3024 Sheet 8 4160V Switchgear Elementary Diagrams N32 Lighting Plan 3045 Sheet 14 Control Elementary Diagrams N48 3058 D.C. One Line Diagram N53 3058 Sheet 1 D.C. One Line Diagram N53 3059, Sheet 1 D.C. Panel Schedules Cooper Nuclear Station 36 3065 Sheet 17 Control Elementary Diagrams N44 3065 Sheet 17a Control Elementary Diagram N11 3177 Outdoor Grounding Plans And Details N02 3251 Sheet 11 4160V Switchgear Connection Wiring Diagram N20 3253 Sheet R-1 480V Motor Control Center R Connection Wiring N15 I Diagram A-5 Attachment 1 
: 257, Sheet 71 Alternative Shutdown ADS Panel Internal Connections N06 3700 Sheet 16 Annunciator Elementary Ladder Diagram N05 3720 Sheet 1 Multiplexer Input Wiring
: ANN-MUX-10 N04 3726 Sheet 1 Multiplexer Input Wiring
: ANN-MUX-16 N03 3727 Sheet 1 Multiplexer Input Wiring
: ANN-MUX-17 N05 3751 Sheet 7 Annunciator Loop Diagram
: ANN-MUX-01 Devices NOO Sheet No. 6B 3757 Sheet 1 Annunciator Loop Diagram
: ANN-MUX-07 N01 3766 Sheet 1 Annunciator Loop Diagram
: ANN-MUX-16 N02 3767 Sheet 1 Annunciator Loop Diagram
: ANN-MUX-17 N04 0133C8690 Sheet 15 Horizontal Drawout M/C Switchgear Device And 1-17-1973 Harness Identification 0223R0558 Sheet 32 Power And Control Circuits Line-Up 08 Units 1 And 2 N22 Piping Isometric -Wet Sprinkler System Electrical
: 453200226 Trays In North East Corner Reactor Building -Floor N04 Elevation 903'-6" I
: 454016108 Contract E69-20 Fire Protection System N10
: 454016113 Contract E69-20 Fire Protection System N01
: 454016115 Contract E69-20 Fire Protection System N01
: 454016116 r::c" "" __ C' .. h..A A vUlllI Clvl !::U;:1-':'U I-II 0 r I UlOvllU11 u Y :::'lOIII l'iU'"t Nebraska Public Power District Contract Number
: 454016126 N04 E-69-20 115D6011, Sheet 1 Local Rack 25-50
: NOO 729E720BB High Pressure Coolant Injection System N03 730E149BB, Sheet 1 Functional Control Diagram N05 730E149BB, Sheet 2 Main Steam Line Isolation Valve Control System Logic N04 791 E253 Sheet 1 Automatic Blowdown System Elementary Diagram N30 791 E253 Sheet 2 Automatic Blowdown System Elementary Diagram N27 791 E253 Sheet 3 Automatic Blowdown System Elementary Diagram N11 791 E264 Sheet 7 Elementary Diagram Reactor Core Isolation Cooling N15 System (13-113) ...,,, ... ""..., ... C'L... __ '" Cooper Nuclear Station-HPCI System-Elementary ....1""1"\ 11;:1IE':'1 I, ullOOlU I Diagram l'i 1;:1 A-6 Attachment 1 
: 791 E266 Sheet 12 Elementary Diagram Primary Containment Isolation N12 System (16-23) 791E514 Sheet 1 Connection Diagram Panel 9-21 N23 791 E514 Sheet 2 Connection Diagram Panel 9-21 N01 944E689 Sheet 1 Elementary Diagram (Mod) Low-Low Set N13
: CNS-EO-105 Sheet 1 EO Configuration Detail GE/PCI Pressure Switch N01
: CNS-EO-i05 Sheet 2 EO Configuration Detail, GE/PCI Pressure Switch N01 Tabulation Sheet
: CNS-FP-146 932'-6" Reactor Building -North Wall Critical N06 Switchgear Room 1 G Fire area Boundary Drawing
: CNS-FP-170 Fire Area Boundary Drawing Diesel Generator Room N05 "1" South Wall
: CNS-FP-171 Fire Area Boundary Drawing Diesel Generator Room N05 "2" North Wall
: CNS-FP-215 Fire Protection Pre-Fire Plan Reactor Building First N04 I Floor Elevation 903'-6"
: CNS-FP-216 Fire Protection Pre-Fire Plan Reactor Building Critical N03 Switchgear Room 1 F Elevation 932'-6"
: CNS-FP-221 Fire Protection Pre-Fire Plan Reactor Building MG Set N05 Area Elevation 976'-0"
: CNS-FP-236 Fire Protection Pre-Fire Plan Diesel Generator Building I N05 I D.G. # 1 Elevations 917'-6" and 903'-6"
: CNS-FP-285 Sheet 1 CNS Fire Barrier Penetration Seal Details N04
: CNS-EE-186 Safe Shut Down Component Locations & Emergency 4 Route Lighting, 903'-6" Diesel Generator Building
: CNS-LRP-3, Sheet 4 Local Rack 25-50 Structure NOO
: CNS-LRP-3, Sheet 8 Local Rack 25-50 Structure N01
: CNS-LRP-3, Sheet 9 Local Rack 25-50 Structure N02 E0223R0558, Sheet Power And Control Circuits Line-Up 09 Units 1 And 2 N23 33 Lighting Plan Sheet 2 E501 Sheet 17 A Integrated Control Circuit Diagram
: CS-MOV-M012A N01 Core Spray Inboard Injection Valve E501 Sheet 17B Integrated Control Circuit Diagram
: RHR-MOV-M025A N02 E501 Sheet 17C Integrated Control Circuit Diagram
: RHR-MOV-M027 A N02 RHR Loop A Injection Outboard Isolation E501 Sheet 2'),A Integrated Control Circuit Diagram
: RHR-MOV-M018 I\In1 I RHR Suction Cooling Inboard Isolation Valve A-7 Attachment 1 
: E50i Sheet 26A Integrated Control Circuit Diagram
: SW-MOV-M089A N01 RHR Heat Exchanger A Service Water Outlet I E501 Sheet 29C Integrated Control Circuit Diagram
: RCIC-MOV-M021 N01 RCIC Injection E501 Sheet 30 Motor Operated Valves Connection Diagrams N08 E501 SHEET30C Integrated Control Circuit Diagram
: RHR-MOV-M017 N01 RHR Shutdown Cooling Supply Outboard isolation E501 Sheet 33A Integrated Control Circuit Diagram
: HPCI-MOV-M058 N01 HPCI Pump Suction From Suppression Pool E501 Sheet 44 Motor Operated Valves Connection Diagrams N02 E501 Sheet 45A Integrated Control Circuit Diagram
: RHR-MOV-M025B N02 RHR Loop B Injection Inboard Isolation E501 Sheet 48A Integrated Control Circuit Diagram
: SW-MOV-M089B N02 RHR Heat Exchanger B Service Water Outlet E507 Sheet 24 Connection Wiring Diagram Reactor Building N08 E507 Sheet 29 Connection Wiring Diagrams Reactor Building N03 I E507 Sheet 235 Reactor Building Terminal Box 242 Connection Wiring N01 Diagram G5-262-743 Sheet 1 Emergency Diesel Generator No.1 Electrical Schematic N23 G5-262-746 Sheet 2 Emergency Diesel Generator No.1 Electrical Schematic N18 G5-262-746 Sheet 3 Emergency Diesel Generator No.1 Electrical Schematic N23 G5-262-746 Sheet 4 Emergency Diesel Generator No.1 Electrical Schematic N12 G5-262-746 Sheet 5 Emergency Diesel Generator No.1 Internal Wiring N19 Diagram G5-262-746 Sheet 6 Emergency Diesel Generator No.1 Control Panel Wiring N16 Diagram X2629-200
: MS-1 Main Steam N06 FIRE IMPAIRMENTS FP08-01-FP-SD-61 A&B FP10-01-NO APPDX R FP10-01-FP-SD-533 LIGHT CEILING TILE FP10-02-FP-HT-3 FLOODED FP1 0-01-FC9ASDG1 OOF FP1 0-01-EE-L
: TG-APP R FP10-02-6.FP.302 FP10-01-COMP RM TILES FP10-01-FP-PNL-CAS FP1 0-01-RW BLDG HORNS FP1 0-01-CORE BORES FP10-01-SWP RM HALON FP10-01-EE-LTG-R18 BULB FP10-02-FP-HT-12 FP1 0-02-FP-HT -15 FAIL IMPAIRED INACCESSABLE FP10-01-APPDX R F\f\J I OVERFILL FP1 0-01-VVVV FALSE ALRM I AHU1 FP1 n-n1-FP A'pP R A-8 Attachment 1 
: PREVENTIVE MAINTENANCE TASKS
: 14624836
: 14624889 [4663722 [4663770
: 14712840 [4713833 PROCEDURES Number Title Ad min istrative Conduct of the Condition Report Process Procedure 0.5 Administrative Operating Experience Program Procedure 0.10 Administrative CNS Fire Protection Plan Procedure 0.23 Administrative Hot Work Procedure 0.39 Administrative Fire Watches and Fire Impairments Procedure 0.39.1 Emergency Procedure 5.3AL T-Alternative Core Cooling Mitigating Strategies STRATEGY Emergency Procedure 5.4FIRE-Fire Induced Shutdown From Outside Control Room SID Emergency Procedure 5.4POST-Post-Fire Operational Information FIRE Maintenance Appendix RISSO Lighting Functional Test Procedure
: IS.EE.302 Maintenance 3M Interam E-5A Fire Wrap Fire Resistive Assembly Procedure 7.3.21.7 Non-TS Surveillance Fire Detection System Tri-Annual Test (Group 1) Procedure 15.FP.303 Non-TS Surveillance Critical Switchgear Room Duct Wrap Visual Inspection Procedure 15.FP.652 3.9 ASME OM Code Testing Of Pumps and Valves (""t. ** ___ =11.,-__ -.._ A ........ ,.... .. Ii.-. . "._ I \ 'r 1._ r":._ " .. :1. ,... .. ' '-' _ r A"' ....... " ...... '" I f'\U'::> IVIi::H1UC:lI v C:llve '"-II (;Ull ,"-onnnUity Tram f'\;:'U-f'\U;:' I .::>UI Vt:::IIIC:lII(;t::: A-9 Revision 67 21 60 42 6 23 38 36 and 37 20 12 15 2 25 A A I I Attachment 1
===Procedure===
: Panel 6.ADS.202 Surveillance 1ST Closure Test of
: HPCI-CV-10CV and
: RCIC-CV-Procedure 7 6.CSCSA04 10CV Surveillance Annual Testing of Fire Pumps 30 Procedure 6.FP.102 Surveillance Fire Damper Assembly Examination (Fire Protection o and 9 Procedure 6.FP.203 System 18 Month Examination) Surveillance Operations Power Block Sprinkler System Testing 17 Procedure 6.FP.301 Surveillance Automatic Deluge and Pre-Action Systems Testing 19 Procedure 6.FP.302 Surveillance Fire Detection System Circuitry Operability 7 Procedure 6.FP.304 Surveillance Fire Barrier/Fire Wall Visual Examination 12 Procedure 6.FP.606 Surveillance Calibration Procedure for HPCI Pressure Procedure Instrumentation 8 6.HPC1.306 Surveillance Procedure HPCI Turbine Trip and Initiation Logic Functional Test 7 6.HPC1.311 Surveillance Safety Valve and Relief Vaive Position indication '13 Procedure 6.SRV.303 Operability Check And LLS Logic Test Surveillance Diesel Generator C02 Operability Teat (DIV 1) 10 Procedure 6.1
: FP.301 Surveillance Fire Detection System 184 Day Examination 9 Procedure 6.1
: FP.302 Surveillance High Pressure C02 Cylinder Examination (DIV 1) 12 Procedure 6.1
: FP.601 Surveillance Safe Shutdown BBESI Emergency Lighting Unit 14 Procedure 7.3.12.2 Examination and Maintenance Surveillance Appendix RISBO Lighting Functional Test 20 Procedure 15.EE.302 Surveillance Fire Detection System Tri-Annual Test (Group 3) 10 Procedure 15.FP.305 I System Operating I Communication Systems 41 A-10 Attachment 1 
: MISCELLANEOUS DOCUMENTS Number Title Revision COR002-18-02
: OPS-Reactor Core Isolation Cooling 17 Cutler-Hammer Instructions For Size 1 Or 2 Type B Thermal June 1998 Overload Relay, 3 Pole, Ambient Compensated Or Non-Compensated I.L.16954A Design Criteria Fire Protection Systems May 10, 2010 Document 11 Engineering Evaluation of Critical Switchgear Rooms 1 F and 1 G 0 Evaluation Number Fire Barrier Separation
: EE 09-031 Evaluation Number Appendix R MOV Overthrust Evaluation 0
: EE 04-046 Engineering I Ruskin Manufacturing Company -Site Storage and 2 Procedure Number Handling of
: NIED-23 Curtain Type Fire Dampers E-510
: EODP.2.210 Electroswitch Series 24 (3 Sheets On
: EO 10 Certification of Model 2421 OB Switch) Letter LOA8200158 Fire Protection Rule 10
: CFR 50, Appendix R June 28, 1982 Letter LOA83001 09 Fire Protection Rule 10
: CFR 50, Appendix R, March 18, Preliminary Supplemental Response (Revised) 1983 Nebraska Public Response to Appendix A to Branch Technical December 17, Power District Letter Position APCB 9.5-1 Guidelines for Fire Protection 1976 for Nuclear Power Plants Nebraska Public Revisions and Additional Information Fire Protection April 6, 1977 Power District Letter Review Public Fire Protection Rule 10
: CFR 50, Appendix R, June 02, 1983 Power District Letter Preliminary Supplemental Response (Revision 2) NRC Letter K. R. Goller, NRC, to Nebraska Public Power District November 29, 1977 NRC Letter G. Lear, NRC, to Nebraska Public Power District February 24, 1978 NRC Letter T. Ippolito, NRC, to Nebraska Public Power District May 23,1979 NRC Letter T. ippolito, NRC, to Nebraska Public Power District September 18, A-11 Attachment 1 
: NRC Letter Ippolito, NRC, to Nebraska Public Power District I November 21, I 1980 NRC Letter D. Vassallo, NRC, to Nebraska Public Power District April 29, 1983 NRC Letter D. Vassallo, NRC, to Nebraska Public Power District September 21, 1983 NRC Letter D. Eisenhut, NRC, to Nebraska Public Power District September 21, 1983 NRC Letter Safety Evaluation For Appendix R to 10 CFR Part April 16, 1984 50, Items
: II.G.3 and
: III.L, Alternative or Dedicated Shutdown Capability NRC Letter Outstanding Fire Protection Modifications August 21, 1985 NRC Letter W. Long, NRC, to Nebraska Public Power District April 10, 1986 NRC Letter W. Long, NRC, to Nebraska Public Power District September 9, 1986 NRC Letter Cooper Nuclear Station -Amendment No. 126 to November 7, Facility Operation License No.
: DPR-46 1988 NRC Letter Cooper Nuclear Station -Amendment No. 127 to February 3, Facility Operation License No.
: DPR-46 1989 NRC Letter Revocation Of Exemption From 10 CFR Part 50, August 15, Appendix R -Cooper Nuclear Station 1995 NRC Letter Conversion To Improved Technical Specifications July 31, 1998 For The Cooper Nuclear Station -Amendment No. 178 To Facility Operating License No.
: DPR-46 OTH015-92-02 Lesson Plan Post Fire Shutdown Outside The 09 Control Room Procedures (5.4POST-FIRE, 5.4FIRE-S/D,5.1ASD) Siemens-Allis DC DC Contactors Special Purpose 2 Pole, 600V Max No Date Contactors AC or DC Operated Paaes 147 And 148 Siemens Overload Manufactures Data Thermal Overload Relays Type April 1997 2 Sheets 3UA59 Siemens Overload Manufacture's Data On Bimetallic Thermally No Date 4 Sheets Delayed Overload Relays Type 3UA5, 3UA6 Class 10 Southwest Research NPPD PO#
: 4500092806 Williams Fire Pump Diesel July 29,2008 Institute Oil Test Summary Report Southwest Research NPPD PO#
: 4500100440 Williams Fire Pump Diesel Revision 1 Institute Oil Analytical Test Report May 11,2009 Southwest Research NPPD PO#
: 4500102145 Williams Fire Pump Diesel May 18, 2010 Institute Oil Analvtical Test Report I Technical Publication I Electroswltch Senes 24 Instrument and Control I February 1998 I A-12 Attachment 1 
: 24-1 Switches For Power Industry and Heavy Duty Industrial Applications Technical Fire Protection Systems July 29, 2010 Requirements Manual Section 3.11 Technical Alternative Shutdown System Amendment Specification 3.3.3.2 233 Updated Safety Alternative Shutdown Capability July 24, 2001 Analysis Report Section
: VII-18 Updated Safety Fire Protection System January 08. Analysis Report 2004 Section X-9 Updated Safety Appendix R Safe Shutdown January 29, Analysis Report 2003 Section X-18 Updated Safety Fire Protection Program April 16, 2010 Analysis Report Section
: XIII-1 0
: VM-1730 Emergency Lighting 1 Westinghouse Starter Manufactures Data Sheets Showing 460 VAC A201, April 1984 Information A211, A251 Size 2 Magnetic Contactor Non-Reversing Or Reversing I. L. 16961 A 257HA354AC GE Design Specification, Sheet 2 2
: 790523 Amendment No. 56 to Facility Operating License No. 001
: DPR-46
: 4605196 Sample Fuel Oil And Send For Analysis For Williams July 29, 2008 B.5.b Credited Pump
: 4625867 Sample Fuel Oil And Send For Analysis For Williams April 29, 2009 B.5.b Credited Pump
: 4664953 Sample Fuel Oil And Send For Analysis For Williams May 03,2010 B.5.b Credited Pump 1ST Reference/Acceptance Limits Data File 205 SYSTEM TRAINING MANUALS Number Title Revision COR002-11-02 High Pressure Coolant Injection 26 COR002-19-02 Reactor Equipment Cooling 20 ,..,,, /"\,.., n __ :-I .. _I I I_,-L r"\ ____ **. _1 ("\."-".1. ____ ,..,.., I r\t:::'IUUdl nt:dl r\t:IIIUVdl "y:stt:::rll L.t A-13 Attachment 1 
: WORK ORDERS
: 4704976
: 4704973
: 4705129
: 4636801
: 4704980
: 4705274
: 4704985
: 4704986
: 4705369
: 4541652
: 4680341
: 4600849
: 4601469
: 4625865
: 4627329
: 4629553
: 4634534
: 4636434
: 4643635
: 4648115
: 4649842
: 4656140
: 4659221
: 4659685
: 4662049
: 4664951
: 4688234
: 4691445
: 4694802
: 4702636
: 4704770
: 4711699
: 4712867
: 4713861 A-14 Attachment 1 
: FINAL SIGNIFICANCE DETERMINATION SUMMARY COOPER TRIENNIAL FIRE PROTECTION ISSUE Significance Determination Basis a. Phase 1 Screening Logic, Results, and Assumptions In accordance with NRC Inspection Manual Chapter 0612, Appendix B, "Issue Screening," the issue was determined to be more than minor because it was associated with the equipment performance attribute and affected the mitigating systems cornerstone objective to ensure the availability, reliability, or function of a system or train in a mitigating system in that 3 motor-operated valves would not have functioned following a postulated fire in multiple fire zones. The following summarizes the valves and fire areas affected: * Valves Affected
: RHR-MO-25A Residual Heat Removal (RHR) A Inboard Injection Valve
: RHR-MO-25B RHR B Inboard Injection Valve
: RR-MO-53A Reactor Recirculation Pump A Discharge Valve * Fire Areas Affected
: CB-A-1
: CB-B
: CB-C
: CB-D Control Building Division 1 Switchgear Room and Battery Room Control Building Division 2 Switchgear Room and Battery Room Control Building Reactor Protection System Room 1 B Control Room, Cable Spreading Room, Cable Expansion Room, and Auxiliary Relay Room
: RB-DI (SW) Reactor Building South/Southwest 903, Southwest Quad 889 and 859, and RHR Heat Exchanger Room B
: RB-DI (SE) Reactor Building RHR Pump B/HPCI Pump Room
: RB-J Reactor Building Critical Switchgear Room 1 F
: RB-K Reactor
: RB-M
: RB-N
: TB-A Building Critical Switchgear Room 1 G Reactor Building North/Northwest 931 and RHR Heat ExchangerRoom Reactor Building South/Southwest 931 and RHR Heat Exchanger Room B Turbine Building (multiple areas) The significance determination process (SDP) Phase 1 Screening Worksheet (Manual Chapter 0609, Attachment 4), Table 3b directs the user to Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," because it affected fire protection defense-in-depth strategies involving post fire safe shutdown systems. However, Manual Chapter 0308, Attachment 3, Appendix F, "Technical Basis for Fire Protection Significance Determination Process for at Power Operations," states that Manual Chapter 0609, Appendix F, does not include explicit B-1 Attachment 2
treatment of fires in the main control room. The Phase 2 process can be utilized in the treatment of main control room fires, but it is recommended that additional guidance be sought in the conduct of such an analysis. b. Phase 2 Risk Estimation Based on the complexity and scope of the subject finding and the significance of the finding to main control room fires, the analyst determined that a Phase 2 estimation was not appropriate. c. Phase 3 Analysis A risk analysis was performed previously of a similar problem that affected the three valves addressed by this performance deficiency. This was documented in
: EA 07-204, Report Number 05000298/2008008, dated June 13, 2008. In both cases, Valves
: MOV-25A,
: RHR-MOV-25B, and
: RHR-MOV-53A were incapable of being remotely operated from the motor starter as prescribed by Procedure 5.4FIRE-S/O. The risk estimate performed in 2008 as it pertains to these three valves (the 2008 Phase 3 also included several other valves) remains valid for the current situation. However, changes were made to Procedure 5.4FIRE-SID subsequent to the 2008 issue. These changes were credited in the current analysis and resulted in a decrease in the risk significance of the subject valves. Text from the 2008 risk analysis is shown in italics throughout this document. In accordance with Manual Chapter 0609, Appendix A, the analyst performed a Phase 3 analysis using input from the Nebraska Public Power District, "Individual Plant Examination for External Events (IPEEE) Report-10
: CFR 50. 54 (f) Cooper Nuclear Station, NRC Docket No. 50-298, License No.
: DPR-46, JJ dated October 30, 1996, the Standardized Plant Analysis Risk (SPAR) Model for Cooper, Revision 3.31, dated September 2007, licensee input (see documents reviewed list in Enclosure 3), a probabilistic risk assessment using a linked event tree model created by the analyst for evaluating main control room evacuation scenarios, and appropriate hand calculations. [Note: The SPAR model used in the 2008 analysis has been superseded by newer versions. However, the risk result gained from the portion of the analysis that used this model (non-alternative shutdown scenarios) was not significant to the current risk estimate. Virtually all of the risk associated with the current issue results from the alternative shutdown scenarios for which a specific SPAR model was created. Therefore, the use of the older mode! has no consequence.] Assumptions: 1. For fire zones that do not have the possibility for a fire to require the main control room to be abandoned, the ignition frequency identified in the IPEEE is an appropriate value. 2. The fire ignition frequency for the main control room (PF1F) is best quantified by the licensee's revised value of 6.88 x 10-3/yr. B-2 Attachment 2 
: 3. Of the original 64 fire scenarios evaluated, 18 were determined to be redundant and were eliminated, 41 of the remaining (documented in Table 1) were identified as the predominant sequences associated with fires that did not result in control room abandonment. [Note: the current issue did not include all of the fire scenarios from the 2008 issue, but all of the current fire scenarios are included in the 2008 compilation] 4. The baseline conditional core damage probability for a control room evacuation at the Cooper Nuclear Station is best represented by the creation of a probabilistic risk assessment tool previously created by the analyst using a linked event tree method. The primary event tree used in this model is displayed as Figure 1 in the Attachment. The baseline conditional core damage probability as calculated by the linked event tree model was 1.14 x 10-1, which is similar to the generic industry value of 0.1. 5. The analyst used an event tree, RECOVERY-PA TH, shown in Figure 2 in the Attachment, to evaluate the likelihood of operator recovery via either restoration of HPCI or manually opening Valve
: RHR-MO-258. The resulting non-recovery probability was 7. 9 x 10-2. [Note: This value was adjusted to 1.01 E-3 in the current analysis based on improvements made to Procedure 5.4FIRE-SID.] 6. The risk related to a failure of Valve
: RHR-MO-258 to open following an evacuation of the main control room was evaluated using the analyst's linked event tree model. The conditional core damage probability calculated by the linked event tree model was 1.19 x 10-1. 7. Any fire in the main control room that is large enough to grow and that goes unsuppressed for 20 minutes will lead to a control room evacuation. 8. Any fire that is unsuppressed by automatic or manual means in the auxiliary relay room, the cable spreading room, the cable expansion room or Area R8-FN will result in a main control room evacuation. 9. The Cooper SPAR model, Revision 3.31, represents an appropriate tool for evaluation of the core damage probabilities associated with postulated fires that do not result in main control room evacuation. 10. All postulated fires in this analysis resulted in a reactor scram. In addition, the postulated fire in Fire Area R8-K resulted in a loss-of-offsite power. 11. Valves
: RHR-MO-25A and
: RHR-MO-258 are low pressure coolant injection system isolation valves. These valves can prevent one method of decay heat removal in the shutdown cooling mode of operation. 12. For Valves
: RHR-MO-25A and
: RHR-MO-258, the subject performance deficiency only applies to the portion of the post fire procedures that direct the transition into shutdown cooling. 8-3 Attachment 2 
: 13. Valve
: RHR-MO-25B must opened from the motor-control center for operators to initiate alternative shutdown cooling from the alternative shutdown panel following a main control room evacuation. 14. Valve
: RHR-MO-53A is the discharge isolation valve for Reactor Recirculation Pump 1-A. The failure to close either this valve or Valve
: RR-MO-43A would result in a short circuit of the shutdown cooling flow to the reactor vessel. The performance deficiency did not apply to Valve
: RR-MO-43A. 15. The exposure time used for evaluating this finding should be determined in accordance with Inspection Manual Chapter 0609, Appendix A, Attachment 2, "Site Specific Risk-Informed Inspection Notebook Usage Rules. JJ Given that the performance deficiency was known to have existed for many years, the analyst used the 1-year of the current assessment cycle as the exposure period. 16. Based on fire damage and/or procedures, equipment affected by a postulated fire in a given fire zone is unavailable for use as safe shutdown equipment. 17. The performance deficiency would have resulted in each of the demanded valves failing to respond fol/owing a postulated fire. 18. In accordance with the requirements of Procedure 5.4POST-FIRE, operators would perform the post-fire actions directed by the procedure following a fire in an applicable fire zone. Therefore, the size and duration of the fire would not be relevant to the failures caused by the performance deficiency. 19. Given Assumption 18, severity factors and probabilities of 17017-suppression were not addressed for postulated fires that did not result in main control room evacuation. Postulated Fires Not Involving Main Control Room Evacuation: The risk significance from fires not involving control room evacuation was determined to be insignificant for the current finding. This was estimated by referring to the 2008 risk evaluation. Text in italics is from the 2008 report and Table 1 is reproduced for the fire areas that involve
: RHR-MOV-25A,
: RHR-MOV-258, or
: RHR-MOV-53A. The senior reactor analyst used the SPAR model for Cooper Nuclear Station to estimate the change in risk, associated with fires in each of the associated fire scenarios (Table 1, Items 1 -41) that was caused by the finding. Average unavailability for test and maintenance of modeled equipment was assumed, and a cutset truncation of 1. a x 10-13 was used. For each fire zone, the analyst calculated a baseline conditional core damage probability consistent with Assumptions 9, 10, 25 [now 17] and 26 [now 18]. 8-4 Attachment 2 
: For areas where the postulated fire resulted in a reactor scram, the frequency of the transient initiator,
: IE-TRANS, was set to 1.0. All other initiators were set to the house event "FALSE," indicating that these events would not occur at the same time as a reactor scram. Likewise, for Fire Area
: RB-K, the frequency of the loss-of-offsite power initiator,
: IE-LOOP, was set to 1.0 while other initiators were set to the house event "FALSE." With input from the detailed IPEEE notebooks, maintained by the licensee, the analyst was able to better assess the fire damage in each zone. This resulted in a more realistic evaluation of the baseline fire risk for the zone, and lowering the change in risk for each example. Consistent with guidance in the Reactor Accident Sequence Precursor Handbook, including NRC document, "Common-Cause Failure Analysis in Event Assessment, (June 2007), " the baseline established for the fire zone, and Assumptions 22 through 26, [now 15 through 19] the analyst modeled the resulting condition following a postulated fire in each fire zone by adjusting the appropriate basic events in the SPAR model. Both the baseline and conditional values for each fire zone are documented in Table 1. As shown in Table 1, the analyst calculated a chanf',e in core damage frequency (IlCDF) associated with these 41 fire scenarios of 2.9 x 1(J /yr. [Note: This result included fire areas not affected by the current finding.] The analyst evaluated the licensee's qualitative reviews of the 13 fire scenarios that were impacted by the failure of the HPCI turbine to trip. In these scenarios, HPCI floods the steam lines and prevents further injection by either HPCI or reactor core isolation cooling system. Qualitatively, not all fires will grow to a size that causes a loss of the trip function due to spatial separation. Additionally, not al/ unsuppressed fires would cause a failure of the HPCI trip function. Finally, no operator recovery was credited in these evaluations. Given that these qualitative factors would all tend to decrease the significance of the finding, the analyst believed that the total change in risk would be significantly lower than the 2.9 x 10-6/yr documented above. Based on analyst judgment and an assessment of the evidence provided by the licensee, an occurrence factor of O. 1 was applied to the 13 fire scenarios. This resulted in a total IlCDF of 7.8 x 1Q-7/yr. Therefore, the analyst determined that this value was the best estimate of the safety significance for these 41 fire scenarios. From Table 1, the total risk associated with fire areas that involve Valves
: RHR-MOV-25A,
: RHR-MOV-25B, or
: RHR-MOV-53A is 5.5E-7. As noted above, in the 2008 analysis, there were qualitative reasons for lowering this risk estimate. Also, because the previous evaluation included the contribution from several other valves that affected the same fire areas, the risk attributable to the current evaluation is lower. For these reasons, the analyst concluded that the risk for the current finding is less than 1.0E-7 for fire areas that do not involve control room evacuation. B-5 Attachment 2 
--TABLE 1 Postulated Fires Not Involving Main Control Room Evacuation Fire Area/-Scenario Scenario Ignition Estimated Area/Shutdown Base CCDP Case CCDP delta-CDF Function Al'fected Zone Number Description Frequency Contribution
: RBC-CF 1C 1 RHRA 2.94E-03 B.B2E-07 B.i5E-05 2.37E.07 Pump Room 2 MCC K 3.02E-03 2.76E-05 1.2BE-04 3.03E-07 3 MCCQ 3.93E-03 2.76E-05 1.2BE-04 3.95E-07 4 MCCR 3.43E-03 2.76E-05 1.2BE-04 3.44E-*07 5 MCC RB 1.62E-03 1.12E-03 1.21 E-03 1.46E-07 6 MCC S 2.23E-03 1.12E-03 1.21 E-03 2.01 E-07 Shut
: HPCI-MO-14, 7 MCCY 3.B3E-03 1.12E-03 1.21 E-03 3.45E-*07
: HPCI-MO-16, B Panel AA3 9.9BE-04 2.76e-05 1.2BE-04 1.00E-07
: RHR-MO-921, 2AJ2C 9 Panel BB3 9.9BE-04 1.12E-03 1.21 E-03 B.9BE-OB
: RWCU-MO-1B and 10 RCIC Starter 1.32E-03 5.27E-06 8.27E-05 1.02E-07
: MS-MO-77 Rack 11 250V Div 1 Rack 5. 1
: OE-04 2.76E-05 1.2BE-04 5.12E-OB 12 250V Div 2 Rack 2.09E-04 1.12E-03 1.21 E-03 1.BBE-OB 13 ASD Panels 3.02E-04 1.12E-03 1.21 E-03 2.72E-OB
: CB-A 14 6.74E-03 7.64E-04 7.64E-04 O.OOE+OO 15 1.36E-03 2.61 E-06 2.61 E-06 O.OOE+OO 16 RPS Room 1A 4.15E-03 1.75E-07 1.75E-07 O.OOE+OO Open
: RHR-MO-25B 17 2.42E03 3.57E-04 3.5BE-04 4.B4E-10 and
: RHR-MO-67 1B Hallway (used 1.09E-02 2.05E-05 2.B5E-05 B.74E-OB CB corridor) 8-6 Attachment 2 
--Fire Estimated --Area/Sh utdown Area/-Scenario Scenario Ignition Base CCDP Case CCDP delta-CDF Function Affected Strategy Zone Number Description Frequency Contribution DC Switchgear Open
: RHR-MO-17,
: BH 19 Room 1A 4.27E-03 3.49E-03 3.49E-04 1.2BE-*09
: RHR-MO-25B, and
: CB-A'I
: RHR-MO-67
: BE 20 Battery Room 2.25E-03 8.74E-06 1.03E-05 3.51 E-*09 1A --DC Switchgear 8G 21 Room 1B 4.27E-03 1.82E-03 1.83E-03 3.42E-OB
: CB-B Open
: RHR-MO-25A 8F 22 Battery Room 2.25E-03 4.81 E-06 5.73E-06 2.07E-09 1B --8B 23 4.15E-03 1.75E-07 1.77E-07 5.81 E-12 Open
: RHR-MO-17,
: CB-C RPS Room 1A
: RHR-MO-25A, and 8C 24 4.15E-03 1.75E-07 1.77E-07 5.81 E-12
: RHR-MO-67 _. RHR Heat Shut
: HPCI-MO-14
: RB-DI (SW) 2D 25 Exchanger 6.70E-04 8.66E-05 8.68E-05 1.27E-10 and
: RR-MO-53A Room B
: RB-DI (SE) 1 D/1 E 26 RHR B/HPCI 4.28E-03 6.48E-05 1.44E-04 3.37E-07 Shut
: HPCI-MO-14 Pump Room and
: RR-MO-53A Switchgear Open
: RHR-MO-17,
: RB-J 3A 27 3.71 E-03 5.28E-05 5.28E-05 O.OOE+OO
: RHR-MO-2EiB, and Room iF
: RHR-MO-67
: RB-L 3B 28 Switchgear 3.71E-03 1.77E-02 1.77E-02 O.OOE+OO Open
: RHR-MO-25A Room 1G 3C/3DI 29 RB Elevation 3E 932 1.13E-02 7.06E-06 8.99E-06 2.18E.08 Open
: RHR-MO-17
: RB-M RHR Hx Room 6.70E-04 7.06E-06 8.99E-06 1.29E-09 and
: RHR-MO-25B 2B 30 A --3C/3D Reactor Building
: RB-N 13E 31 Elevation 932 1.13E-02 1.22E-05 1.38E-05 1.81 E-08 Open
: RHR-MO-25A RHR Heat 2D 32 Exchanger 6.70E-04 1.22E-05 1.38E-05 1.07E-09 Room B 8-7 Attachment 2 
: Firea Scenario Scenario Ignition Estimated Area/Shutdown Area/-Base CCDP Case CCDP delta-CDF Function Strate( Zone Number Description Frequency Contribution
: TB-A 110 33 Condenser Pit 3.10E-03 4.83E-06 6.20E-06 4.25E-09 Area Reactor 11E 34 Feedwater 6.25E-03 4.83E-06 6.20E-06 8.56E-*09 Pump Area 11 L 35 Pipe Chase 6.70E-04 4.83E-06 6.20E-06 9.18E-10 12C 36 Condenser and 3.27E-03 4.83E-06 6.20E-06 4.48E-09 Heater Bay Area Open
: RHR-M017,
: RHR-MO-25A, and 120 37 TB Floor 9033 3.45E-03 4.83E-06 6.20E-06 4.73E-09
: RHR-MO-67 13A 38 Operating Floor 5.76E-03 4.83E-06 6.20E-06 7.89E-09 Non-critical 13B 39 Switchgear 3.79E-03 4.83E-06 6.20E-06 5.19E-09 Room 13C 40 Electric Shop 8.56E-04 4.83E-06 6.20E-06 1.17E-09 130 41 I&C Shop 8.90E-04 4.83E-06 6.20E-06 1.22E-09 Total Estimated .6COF for 41 Postulated Fire Scenarios 1291E-06 8-8 Attachment 2 
: Post-Fire Remote Shutdown Calculations: Note: The risk attributable to post-fire remote shutdown (control room abandonment sequences) results predominantly from the inability to operate Valve
: RHR-MOV-258 as described in Procedure 5.4FIRE-SID. This is the credited train and the only procedural means for initiating shutdown cooling during the recovery actions. The additional risk contribution from
: RHR-MOV-25A and
: RHR-MOV-53A is negligible. As documented in Assumptions 4, 5, and 6, the analyst created a linked event tree model, using the Systems Analysis Programs for Hand-on Integrated Reliability Evaluation (SAPHIRE) software provided by the Idaho National Laboratory, to evaluate the risks related to fire-induced main control room abandonment at the Cooper Nuclear Station. This linked event tree was used to evaluate the increased risk from the subject performance deficiency during the response to postulated fires in the main control room, the auxiliary relay room, the cable spreading room, the cable expansion room or Fire Area
: RB-FN. The primary event tree used in this model is displayed as Figure 1 in the Attachment. As documented in Assumption 5, the analyst used an event tree to evaluate the likelihood of operator recovery via either restoration of l-IPCI or manually opening Valve
: RHR-MO-25B. The resulting non-recover; probability was 1.01 E-3. The derivation of this result is discussed below. This result applied only to sequences where HPCI provides injection flow. In cases where HPCI fails or is not available, there is much less time available to recover from the failure. For this case, a H evaluation was performed, and is discussed below. Note: In the 2008 analysis, the non-recovery probability for HPCI success sequences was determined to be 7.9E-2. This non-recovery probability was decreased by a factor of 78 for the current finding because of changes that were made to Procedure 5.4FIRE-SID. These changes directed operators to close SRVs if RHR injection was not observed to be successful. Also, it directed operators to delay securing HPCI until RHR injection is confirmed. In the 2008 analysis, recovery credit was only applied to sequences that contained an early success (lack of failure or unavailability) of HPCI. This is because with the use of HPCI, a considerable amount of decay heat is removed prior to the point of attempting to open
: RHR-MOV-258 in Procedure 5.4FIRE-S/D, and ample time is available to diagnose the failure and manually open the valve prior to fuel damage. Also, HPCI can be re-initiated in theSe cases to maintain reactor parameters, and the new procedures instruct operators to keep HPCI online until low-pressure injection is confirmed. However, if HPCI is out of service for maintenance or experiences a failure, the only success path is to establish RHR low pressure injection and the time available is very limited. According to the licensee's MAAP analysis, incipient core damage will occur 15 minutes after
: RHR-MOV-258 fails to open unless it is opened (manually) by that time. For early HPCI failures, it is assumed in this analysis (consistent with the 2008 analysis) that there is enough time to reach the step in Procedure 5.4FIRE-S/D where
: RHR-MOV-258 is opened. If it fails to open (1.2E-2 in the base case, 1.0 in the condition case), operators have 15 minutes to diagnose the situation (injection failure) and develop a strategy that includes visually checking the position of
: RHR-MOV-258 and opening it manually to at least 23 hand wheel turns to gei sufficieni fiow io prevent core damage. The analyst considered whether changes to Procedure 5.4FIRE-S/O subsequent to 8-9 Attachment 2
the 2008 risk analysis could allow some recovery credit to be applied to sequences involving early HPCI failure in the current analysis. One possible reason to do this is that the revised procedure directs the operator at the alternative shutdown panel to close SRVs in the event that RHR injection cannot be verified. This would have the effect of delaying the depletion of water inventory in the core. However, the diagnosis of this situation would likely take a long time. The operator at the alternative shutdown panel would be difficult to determine quickly, whether low pressure injection was successful because of a lack of direct indication (total RHR flow is displayed, but the effect of successful injection would only be a slight increase in the total RHR flow rate until Valve
: RHR-MO-34B is throttled closed to divert the flow that was previously directed to the suppression pool). The reactor level indication would likely be the first indication of unsuccessful injection, but a lowering level could well be misinterpreted as a shrink from the injection of colder water. Also, if the operator used the alternative method prescribed in the procedure, which is used when nitrogen pressure is determined to be reliably available, he is directed to use SRVs to maintain pressure within a band of 150-200 psig. This could result in masking the lowering level from a lack of injection. For these reasons, the analyst determined that recovery for early HPCI failure sequences would be challenging. A
: SPAR-H evaluation was performed to estimate a non-recovery probability for HPCI failure sequences. AI! non-nomina! PSFs are shown in the following table: Diagnosis (nominal =1.0E-2) Action (nominal = 1.0E-3) Available Time Barely Adequate (2/3 Time Required (10) nominal) (10) Stress High (2) High (2) Complexity Moderate (2) Nominal ExperiencelTraining Nominal High (0.5) Procedures Poor (5) Nominal Ergonomics Nominal 50% Poor, 50% nominal-(5.5) Total PSF Product 200 55 HEP 0.67 0.05 Total HEP 0.72 The licensee's thermal-hydraulic analysis indicated that approximately 15 minutes of time would be available to open
: RHR-MOV-25B enough turns to provide adequate core flow after the step in the procedure to open
: RHR-MOV-25B failed. The analyst assumed that a nominal time to diagnose the problem is 15 minutes and the nominal time to close the valve is 5 minutes. The available 15 minutes was partitioned with 10 minutes for diagnosis and 5 minutes for action. This explains the selection of the factors above for available time for both diagnosis and action. B-10 Attachment 2 
: Stress would be high in both cases. For diagnosis, complexity was considered be moderate because of the need to observe several indications while following a procedure that only addresses successful operation of the equipment and that directs further actions to be taken that are unrelated to diagnosing equipment failures. In addition, procedures for diagnosis were considered to be poor because of a lack of direction to the operator at the alternative shutdown panel to check the position of
: RHR-MOV-25B if a reactor vessel rise is not observed. Although there is a procedural step for the reactor building operator to check the valve position, it is specifically prescribed for cable spreading room fires only, and it is not clear that he would do this for other alternative shutdown fires unless directed by the operator at the alternative shutdown panel. The analyst considered experience and training to be high for MOV manual operations at the plant because it is a frequently performed task. Ergonomics for action were divided half and half between poor and nominal because it would take an unusually large force to open the valve against the full shutoff head of the RHR pump. In addition, there is a somewhat unfavorable geometry for this operation. Procedure 5.4FIRE-S/D, Attachment 2, Step 1.20.7 instructs the reactor building operator to verify that
: RHR-MOV-258 is open if the fire is in the cabie spreading room. If the valve is observed to not be open, Step 1.20.8 instructs the operator to open the breaker and manually open the valve. There is some uncertainty as to \,AJhether the operator \*'Vou!d proceed VJith Step 1.20.8 (after correctly skipping Step 1.20.7) if the fire was not in the cable spreading room. The analyst concluded that the text of Step 1.20.8 ("If the valve did not operate, perform following .. ") is written in such a way that it presumes that the operator has performed the valve position verification of Step 1.20.7. Therefore, if Step 1.20.7 is skipped, it would be logical to mark Step 1.20.8 "N/A." The analyst concluded that the recovery probability for cable spreading room fires would be nominal because it involves a direct observation of the valve position, followed by a trained and proceduralized evolution. Therefore, for cable spreading room fires, the recovery probability was assigned a value of 1.1 E-2 (nominal
: SPAR-H value). Unlike the value used for "action" in the
: SPAR-H tabulation above, in this case there would be extra time available for the operator to open the valve manually because no time would be needed for diagnosis. For all other fire areas that cause alternative shutdown, the non-recovery value of 0.72 was used as discussed above. The following table summarizes the recovery assumptions: Non-Recovery Value HPCI Success 1.01 E-3 Early HPCI Failure 1.1 E-2 Cable Spreading Room Early HPCI Failure 0.72 All Other ASD Areas Using the linked event tree model described in Assumption 4, the analyst calculated the Condition CDF as 7.79E-6/yr. The base CDF was 5.81 E-6/yr. With a one-year exposure time, the delta-CDF is 2.0E-6/yr. Almost all of the risk (approximately 99%) resulted from sequences that involve alternative shutdown fires (other than the cable spreading room) that include early failures or unavailability of HPCI. 8-11 Attachment 2
dominant cutsets are shown below in Table 2. Table2 Main Control Room Abandonment Sequences Postulated Fire Sequence I Mitigating Functions Results Auxiliary Relay Room 4-01-rly Failure of HPCI 1.3 x 10-6/yr re to Open
: MO-2SB Main Control Room 3-01-12 Early Failure of HPCI 3.4 x 10*7/yr Failure to Open
: MO-2SB Auxiliary Relay Room 4-31-1-1-1-1-Early Failure of HPCI 12 Failure to Open
: MO-2SB 1.8 x 10*7/yr Main Control Room 3-31-1-1-1-1-Early Failure of HPCI 12 Failure to Open
: MO-2SB 4.6 x 10-8/yr Auxiliary Relay Room 4-01-03 Early Failure of HPCI 3.4 x 10-8/yr Failure to Open
: MO-2SB The following text from the 2008 analysis discusses the derivation of the control room abandonment frequency. This information was considered applicable to the current evaluation. Control Room Abandonment Frequency NUREGICR-2258, "Fire Risk Analysis for Nuclear Power Plants, JJ provides that control room evacuation would be required because of thick smoke if a fire went unsuppressed for 20 minutes. Given Assumption 6 and assuming that a fire takes 2 minutes to be detected by automatic detection and/or by the operators, there are 18 minutes remaining in which to suppress the fire prior to main control room evacuation being required. NRC Inspection Manual Chapter 0609, Appendix F, Table 2.7.1, "Non-suppression Probability Values for Manual Fire Fighting Based on Fire Duration (Time to Damage after Detection) and Fire Type Category," provides a manual non-suppression probability (PNS) for the control room of 1.3 x 10-2 given 18 minutes from time of detection until time of equipment damage. This is a reasonable approach, although fire modeling performed by the licensee indicated that 16 minutes was the expected time to abandon the main control room based on habitability. In accordance with Inspection Manual Chapter 0609, Appendix F, Task 2.3.2, the analyst used a severity factor of O. 1 for determining the probability that a postulated fire would be self sustaining and grow to a size that could affect plant equipment. Given these values, the analyst calculated the main control room evacuation frequency for fires in the main control room (FE VA C) as foiiows: = 6.88 x 1Q-3Iyr * 0.1 * 1.3 x 10-2 = 8.94 x 10*61yr In accordance with Procedure 5. 4
: FIRE-SID, operators are directed to evacuate the main control room and conduct a remote shutdown, if a fire in the main control room or any of the four areas documented in Assumption 8, if plant equipment spuriously actuates/de-energizes equiprner;t, or if instrutnentatioll becomes unreliable. 8-12 Attachment 2 
: Therefore, for all scenarios except a postulated fire in the main control room, the probability of non-suppression by automatic or manual means are documented in Table 3, below. Table 3 Control Room Abandonment Frequency Fire Area Ignition Severity Automatic Manual Abandonment Frequency Suppression Suppression Frequency (per year) (per year) Main Control 6.88 x 10-3 0.1 1.3 x 10-2 8.94 X 10-6 Room none Auxiliary Relay 1.42 x 10-3 0.1 none 0.24 3.41 x 10-5 Room Cable Expansion 1.69 x 10-4 0.1 2 x 10-2 0.24 8.11 x 10-8 Room Cable Spreading 4.27 x 10-31 0.1 5 x 10-2 0.24 1 5.12 x 10-6 Room Reactor Building 1.43 x 10-31 0.1 2 x 10-2 0.24 6.86 x 10-7 903' (RB-FN) Total MCR Abandonment: 4.89 x 10-5 The licensee's total control room abandonment frequency was 1.75 x 10-5. For the main control room fire, the licensee's calculations were more in-depth than the analyst's. The remaining fire areas were assessed by the licensee using IPEEE data. However, the following issues were noted with the licensee's [2008J assessment: Kitchen fires were not inciuded in iicensee's evaiuation This would tend to increase the ignition frequency This might add more heat input than the electrical cabinet fires modeled by the licensee Habitability Forced Abandonment Non-suppression probability did not account for fire brigade response time or the expected time to damage. Reduced risk based on 3 specific cabinets causing a loss of ventilation early, when it should have increased the risk. Fire modeling showed that fires in these cabinets could damage nearby cables and cause ventilation damper(s) to close. Risk Assessment Calculation
: ES-91 uses an abandonment value of 9.93 x 10-7. However, the supporting calculation performed by EPM IIC'ON n? v 1n-6 LfVv\...# V.V"-A I V . B-13 Attachment 2 
: Equipment Failure Control Room Abandonment Criteria for leaving the control room did not accurately reflect the guidance that was procedura/ized. * The evaluation of the Cable Expansion Room stated that the only fire source was self-ignition of cables. This was modeled as a hot work fire, and it included a probability that administrative controls for hot work and fire watches would prevent such fires from getting large enough to require control room abandonment. This is inappropriate for self-ignition of cables, since there would not really be any fire watch present. Adjusting for this would increase the risk in this area by two orders of magnitude. The licensee concluded that fires in equipment in the four alternative shutdown fire areas outside the main control room (see Assumption 8) would not result in control room abandonment without providing a technical basis. The licensee's Appendix R analysis concluded that fire damage in these rooms require main control room evacuation to prevent core damage. The analyst used the main control room abandonment frequencies documented in Table 3. In addition, sensitivities were run using the licensee's values. Recovery Following Failure of Valve
: RHR-MO-258 (HPCI success sequences only) As noted above, the recovery value determined in the 2008 analysis was 7.9E-2. The following table presents the revised split fractions based on the improvements to Procedure 5.4FIRE-S/D. ... .... 1 ... I Split Fractions for RECOVERY -PATH Top Event How Assessed Failure Probability
: LEVEL-DOWN
: SPAR-H (Diagnosis OnlY} 1.75E-4
: SRV-STATUS
: SPAR-H (Diagnosis Onhl 1.75E-3
: CLOSE-SRVS
: SPAR-H (Action Only) 4.38E-4 RESTORE-HPCI
: SPAR-H (Combined) 7.0E-4
: OPEN-MO-258
: SPAR-H (Combinedl 2.89E-1 Using the event tree in Figure 2 and the split fractions in Table 4, the analyst calculated a combined non-recovery probability of 1.01 E-3. The licensee's combined non-recovery probability was 4.0 x 10-3. [Note: this value is based on the licensee's evaluation before the aforementioned improvements were made to the procedure]. The licensee used a similar approach to quantify this value. However, the licensee assumed that operators would always shut the safety-relief valves upon determining that reactor pressure vessel water level was decreasing. The analyst assumed that some percentage of operators would continue to follow the procedure and attempt to recover from the failed RHR valve or try alternative methods of low-pressure injection. In addition, the analyst identified the following issues that impacted the licensee's analysis: 8-14 Attachment 2 
: The inspectors determined that it would require 112 ft-fbs of force to manually open Valve
: RHR-MO-25B. The analyst determined that this affected the ergonomics of this recovery. Some operators may assume that the valve is on the backseat when large forces are required to open it. Some operators might be incapable of applying this force to a 2-foot diameter hand wheel. The analyst noted that the following valves would be potential reasons for lack of injection flow and/or may distract operators from diagnosis that Valve
: RHR-MO-025B is closed:
: RHR-81 B, RHR Loop B Injection Shutoff Valve, could be closed.
: RHR-27CV, RHR Loop B Injection Line Testable Check Valve, could be stuck closed.
: RHR-MO-274B, Injection Line Testable Check Valve Bypass Valve, could be opened as an alternative. Operators could search for an alternative flow path. The licensee's [2008J evaluation did not include sequences involving the failure of the HPCI system shortly after main control room evacuation in their risk evaluation. These sequences represented approximately 26 percent of the I'lCDF as calculated by the analyst. These sequences are important for the following reasons: Failure of HPClleads to the need for operators to rapidly depressurize the reactor to establish alternative shutdown cooling. Decay heat will be much higher than for sequences involving early HPCI success. Also, depressurization under high decay heat and high temperature result in greater water mass loss. This will significantly reduce the time available for recovery actions. HPCI success sequences provide long time frames available with HPCI operating. This reduces decay heat, increases time for recovery, and permits the establishment of an emergency response organization. Those factors are not applicable to early HPCI failure sequences. The basis for operating HPCI was not well documented by the licensee. During many of the extended sequences, suppression pool temperature went well above the operating limits for HPCI cooling and remained high for extended periods of time. The following facts were determined through inspection: The design temperature for operating HPCI is 140'F based on process flow providing oil cooling. General Electric provided a transient operating temperature of 170'F for up to 2 hours. 8-15 Attachment 2 
: In the licensee's best case evaluation of the performance deficiency, the suppression pool would remain above 150'F for 10.6 hours. The licensee used a case-specific combined recovery in assessing the risk of this performance deficiency. Most of the recoveries discussed by the licensee would have been available with or without the performance deficiency. Therefore, these should be in the baseline model and portions of the sequences subtracted from the case evaluation. This is the approach used by the analyst in the linked event trees model. The licensee stated during the regulatory conference that credit should be given for diesel-driven fire water pump injection. This is one of the licensee's alternative strategies. However, the inspectors determined, and the licensee concurred, that this alternative method of injection requires that Valve
: RHR-MO-258 be open. Therefore, no credit was given for this alternative strategy. Conclusions: The analyst concluded that the performance deficiency was of low to moderate significance (VVhite). Ill,S documented in Table 1, for a period of exposure of 1 year, the analyst determined a best estimate .6.CDF for fire scenarios that did not require evacuation of the main control room of less than 1.0E-7/yr. using both quantitative and qualitative techniques. Additionally, using the linked event tree model described in Assumption 4 for a period of exposure of 1 year, the analyst calculated the .6.CDF to be 2.0E-6/yr. for postulated fires leading to the abandonment of the main control room. This resulted in a total best estimate .6.CDF of 2.0E-6/yr. 8-16 Attachment 2 
: Figure 1 ----Reactor Failure to Failure to Failure to Failure to Failure to Failure to Shutdown from Establish AC Establish Level Establish Torus Properly Cool the Establish Reestablish HPCI Alternate Power anci Pressure Cooling Reactor Shutdown Cooling Before CD --I REMOTE_SD
: ASD-EPS
: ASD-HPSI
: ASD-SPC
: ASD-COOL
: ASD-SDC
: ASD-REHEAT # I __ 1 OK 2 OK I 3 CD 4 OK I 5 CD 6 OK [ 7 OK I _. 8 CD 9
: CD 10 OK Depress Only HPCI Recover Only 10K I 11 12 I
: CD 13
: CD 14
: CD 15 CD
: REMOTE-SO -2008/06/11 ----A-1 Attachment 2 
: Figure 2 r-------,-------,-----------, I Valve 258 Fails op. erators Fail to Operators Operators Fail to Operators Fail to I ()perators Fail to to Open Upon Diagnose Level Decide to Leave Close SRVs Reestablish I Open Valve 258 Demand Decrease SRVs Open Given Decision HPCI
: MO-25B-FAI
: LEVEL-DOWN
: SRV-STATUS
: CLOSE-SRVS RESTORE-HP
: OPEN-MO-25 #
: END-STATES -----'-------....L------t--OK 2 OK HEP -HPCI Fails 3 CD HEP -SRV, 0,"" 4 OK 5 CD HEP -SRV, 0,,"" 6 OK 7 CD 8 i CD I RECOVERY-PATH -Combine Multiple Recoveries 10 25B Failure 2008/06/11 Page 36 8-18 Attachment 2
}}
}}

Revision as of 00:53, 19 February 2018

IR 05000298-10-006, Cooper Nuclear Station Errata, Errata Triennial Fire Protection
ML110890962
Person / Time
Site: Cooper Entergy icon.png
Issue date: 03/28/2011
From: O'Keefe N F
Division of Nuclear Materials Safety IV
To: O'Grady B J
Nebraska Public Power District (NPPD)
References
IR-10-006
Download: ML110890962 (4)
v • d • e


Text

March 28, 2011

Brian J. O'Grady, Vice President-Nuclear and Chief Nuclear Officer Nebraska Public Power District Cooper Nuclear Station 72676 648A Avenue Brownville, NE 68321

SUBJECT: ERRATA FOR NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000298/2010006, COOPER NUCLEAR STATION

Dear Mr. O'Grady:

This Errata corrects the tracking numbers and a title for the violations in the subject report issued by our letter (ML110760579) (A. Vegel to B. O'Grady, dated March 17, 2011). Please replace Page 18 of the Enclosure and Page A-2 of Attachment 1 with the enclosed revised pages. We regret any inconvenience this may have caused. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure(s), and your response, if you choose to provide one, will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html.

Sincerely,/RA/ Neil F. O'Keefe, Chief Engineering Branch 2 Division of Reactor Safety Docket No. 50-298 License No. DPR-46

Enclosure:

Inspection Report No. 05000298/2010006

w/Attachments:

Supplemental Information Final Significance Determination Summary cc w/enclosure: Distribution via ListServ for CNS Nebraska Public Power District - 2 - Electronic distribution by RIV: Regional Administrator (Elmo.Collins@nrc.gov) Deputy Regional Administrator (Art.Howell@nrc.gov) DRP Director (Kriss.Kennedy@nrc.gov) DRP Deputy Director (Troy.Pruett@nrc.gov) DRS Director (Anton.Vegel@nrc.gov) DRS Deputy Director (Vacant) Senior Resident Inspector (Jeffrey.Josey@nrc.gov) Resident Inspector (Michael.Chambers@nrc.gov) Branch Chief, DRP/C (Vincent.Gaddy@nrc.gov) Senior Project Engineer, DRP/C (Bob.Hagar@nrc.gov) Project Engineer, DRP/C (Rayomand.Kumana@nrc.gov) CNS Administrative Assistant (Amy.Elam@nrc.gov) Public Affairs Officer (Victor.Dricks@nrc.gov) Public Affairs Officer (Lara.Uselding@nrc.gov) Project Manager (Lynnea.Wilkins@nrc.gov) Branch Chief, DRS/TSB (Michael.Hay@nrc.gov) RITS Coordinator (Marisa.Herrera@nrc.gov) Regional Counsel (Karla.Fuller@nrc.gov) Congressional Affairs Officer (Jenny.Weil@nrc.gov) RES Branch Chief (MarkHenry.Salley@nrc.gov) OEMail Resource@nrc.gov OEWEB Resource OEDO RIV Coordinator (Nathan.Sanfilippo@nrc.gov) DRS/TSB STA (Dale.Powers@nrc.gov) R:\ ADAMS ML ADAMS: No Yes SUNSI Review Complete Reviewer Initials: NFO Publicly Available Non-Sensitive Non-publicly Available Sensitive RIV/DRS/EB2 RIV/DRS/BC J.Mateychick N. O'Keefe /RA/ /RA/ 3/23/11 3/26/11 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

-18- Enclosure The licensee entered this issue into their corrective action program as Condition Reports CR-CNS-2010-08014 and CR-CNS-2010-08250. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program, this violation is being treated as a noncited violation, consistent with the Enforcement Policy: NCV 05000298/2010006-02, Failure to Monitor the Performance of the Emergency Lights Against the Maintenance Rule Criteria. .9 Cold Shutdown Repairs a. Inspection Scope The team verified that the licensee identified repairs needed to reach and maintain cold shutdown and had dedicated repair procedures, equipment, and materials to accomplish these repairs. Using these procedures, the team evaluated whether these components could be repaired in time to bring the plant to cold shutdown within the time frames specified in the design and licensing bases. The team verified that the repair equipment, components, tools, and materials needed for the repairs were available and accessible on site. b. Findings No findings were identified. .10 Compensatory Measures a. Inspection Scope The team verified that compensatory measures were implemented for out-of-service, degraded, or inoperable fire protection and postfire safe shutdown equipment, systems, or features (e.g., detection and suppression systems and equipment; passive fire barriers; or pumps, valves, or electrical devices providing safe shutdown functions). The team also verified that the short-term compensatory measures compensated for the degraded function or feature until appropriate corrective action could be taken and that the licensee was effective in returning the equipment to service in a reasonable period of time. b. Findings A finding related to this review was documented in Section 1R05.01. No additional findings were identified. .11 B.5.b Inspection Activities a. Inspection Scope The team reviewed the licensee's implementation of guidance and strategies intended to maintain or restore core, containment, and spent fuel pool cooling capabilities under the circumstances associated with loss of large areas of the plant due to explosions or fire as required by Section B.5.b of the Interim Compensatory Measures Order, EA-02-026, dated February 25, 2002 and 10 CFR 50.54(hh)(2).

- A-2 - Attachment 1 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 05000298/2010006-01 AV Inadequate Post-Fire Safe Shutdown Procedures (Section 1R05.1) Opened and Closed 05000298/2010006-02 NCV Failure to Monitor the Performance of the Emergency Lights Against the Maintenance Rule Criteria (Section 1R05.8) Closed None LIST OF ACRONYMS ADAMS Agencywide Documents Access and Management System BWR Boiling Water Reactor CR Condition Report CFR Code of Federal Regulations DRS Division of Reactor Safety FSAR Final Safety Analysis Report HPCI High Pressure Coolant Injection LPSI Low Pressure Safety Injection MOV Motor Operated Valve NCV Noncited Violation NFPA National Fire Protection Association NRC Nuclear Regulatory Commission PAR Publicly Available Records PRA Probabilistic Risk Assessment RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal SDP Significance Determination Process SRV Safety/Relief Valve

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